WO2020009569A1

WO2020009569A1 - Methods and system for characterising a fluid flowing in a conduit

Info

Publication number: WO2020009569A1
Application number: PCT/NL2019/050403
Authority: WO
Inventors: Robert Bouke Peters; Wilhelmus Hubertus Paulus Maria Heijnen; Thomas Hahn-Jose
Original assignee: Rbp Technology Holding B.V.
Priority date: 2018-07-04
Filing date: 2019-07-01
Publication date: 2020-01-09
Also published as: NL2021236B1

Abstract

A method for characterising a fluid flowing in a conduit (2) is presented. The method comprises the steps of generating uniquely coded signals (8) and transmitting the uniquely coded signal (8) into a fluid in the conduit (2); detecting one or more reflected coded signals (9) from entrained reflective interfaces (10) in the fluid; determining correlations between the transmitted uniquely coded signals (8) and the reflected coded signals (9); and based on these correlations, calculating locations and velocity vectors of the one or more reflective interfaces (10).

Description

Methods and systems for characterising a fluid flowing in a conduit

Field of the invention

The present invention relates to methods for characterising a fluid flowing in a conduit with a well logging system, such as those used in the oil and gas industry or in the geothermal industry. In a further aspect the present invention relates to well logging systems for

characterising a fluid flowing in a conduit.

Background

US patent publication US 3,603,145 discloses a method to measure fluid flow rate using ultrasonic means in which a transmitter emits an acoustic wave which is detected by two receivers, one being located upstream of the transmitter and one being located downstream of the transmitter with respect to the direction of fluid flow. By detecting the time difference in the signal arriving at both receivers, or by detecting the frequency of the signal arriving at both receivers, the flow velocity may be determined using principles such as Doppler theory or time of flight measurement. By analysing the amplitude of the signal arriving at the receivers, useful information such as the density of the fluid may be derived.

US patent publication US 4,452,077 discloses a method to measure fluid flow rate using ultrasonic means in which again, a transmitter emits an acoustic wave which is detected by two receivers, one being located upstream of the transmitter and one being located downstream of the transmitter with respect to the direction of fluid flow. The difference in arrival times as well as the difference in frequency are used to determine the fluid flow velocity, using principles such as Doppler shift and time of flight. In addition, the disclosed prior art uses a direct measurement of tool velocity using ultrasonic means such as Doppler shift in signals reflected off the wellbore wall or ultrasound signal refraction of signals carried in the well casing to correct the fluid flow velocity for the movement of the tool itself.

US patent publication US 4,947,683 discloses a method to measure fluid flow rate using ultrasonic means in which a sonde with upper and lower centralisers is used which contains an ultrasonic transducer acting as a transceiver. The transceiver is placed at the lower end of the sonde and emits acoustics waves into the fluids flowing in the well. Waves reflect off particles in the fluid flow and are analysed for frequency shift, using Doppler shift principles to derive the velocity of the particles. The transceiver is placed at an angle from the longitudinal axis of the tool and uses different time gates between transmitting and receiving so as to vary the distance in front of the transceiver where Doppler particle velocity is measured.

US patent publication US 4,905,203 discloses a method to measure fluid flow rate using ultrasonic means in which a sonde containing a transmitter and a receiver is located in a wellbore. The transmitter emits an acoustic signal, which is reflected off particles in the flow and received by a receiver. The Doppler shift of the frequency of the signal in the received signal is used to calculate the velocity of reflective particles, thus deriving the fluid velocity. US patent publication US 5,473,948 discloses a method to measure fluid flow rate using ultrasonic means in which a transceiver is used to transmit an acoustic signal into a fluid flow which reflects off a particle. By detecting reflections of ultrasound, reflected off an individual particle from successive transmissions, and measuring the difference in arrival times from successive transmissions, the particle velocity is derived. Use of suitable gates allows successive reflections from an individual particle to be tracked, while rejecting reflections from other particles. The method is thereby not based on Doppler shift, but purely on the difference in observed pulse travel time between a first transmission/reception cycle, and a second transmission / reception cycle. The difference in the two-way time of flight represents the displacement of the particle relative to the measurement device.

International patent application WO 2013/064494 discloses a method to measure fluid flow rate using ultrasonic means in which a transceiver is placed on a centralized sonde inside a borehole. The transceiver emits an ultrasonic signal which is reflected off particles in the fluid flow. The reflected signal is received at the same transceiver and a Doppler frequency shift is detected and used to calculate particle velocity. In addition, a series of electrical capacitance sensors is mounted on the circumference of the sonde to determine the nature of the fluids flowing past the sonde, which needs to be centralized for this purpose. Besides Doppler frequency shift analysis, the velocity may also be determined using speckle velocimetry principles. The sonde uses a transducer substantially parallel to the longitudinal axis of the sonde, and also a transducer at a variable angle with the longitudinal axis of the sonde. By varying the angle, the cross section of the wellbore may be fully swept to obtain information on the flow pattern in the well bore.

International patent application WO 2017/009075 discloses a method to measure fluid flow rate using ultrasonic means in which ultrasound transducers are mounted on projecting elements from a sonde. Transducers are distributed angularly as an array around a cylindrical housing. The housing has to be centralized. The tool can thus transmit and/or receive ultrasonic waves at angles from the longitudinal axis of the tool, and can be used for flow imaging. Flow imaging is achieved using Doppler analysis, echo amplitude analysis and/or time of flight measurements.

International patent application WO2017/153169 discloses a method to measure fluid flow rate using ultrasonic means in which ultrasonic transducers are positioned radially around the circumference of a downhole sonde as well as placed on one end of a downhole sonde at a small angle to the longitudinal axis of the sonde. Ultrasonic transducers are used to derive fluid properties, fluid velocity and tool velocity.

German patent application DE 10 2015 106 695 A1 discloses a device and method for ultra-sonic flow measurement, in particular for location and / or speed evaluation of reflectors such as suspended matter in fluid or gases. Coded pulse signals are transmitted and reflections thereof are received, wherein correlations are determined between transmitted and received signals.

The above referenced prior art suffers from a variety of drawbacks and disadvantages.

For example, the methods and systems disclosed typically require centralisation of a well logging system/probe in a borehole for determining a fluid flow there through, wherein an annular space between the probe and the borehole wall is required. However, centralisation of the probe often involves use of mechanical centraliser blades/arms that are vulnerable and prone to malfunction in challenging borehole environments such as barefoot completions.

A further drawback of the prior art is that the probe may be provided with acoustic transducers that need to rotate relative to a probe axis for taking fluid flow velocity measurements, making the probe prone to damage and/or malfunction.

Another drawback of the prior art is that the speed of sound in the fluid is assumed to be constant, which need not be the case in practice and as a result flow velocity measurements may be less accurate at particular locations within the borehole.

An even further drawback of the prior art is that the velocity of the probe within the borehole is often measured by means of a cable connected to the probe, wherein the speed of the cable measured near the entrance of the borehole need not be the same as the actual speed of the probe. The discrepancy between a measured cable speed versus the actual probe speed often occurs in non-vertical boreholes, such as substantially horizontal boreholes in which movement of the probe may be erratic due to stick-slip behaviour as the probe engages the borehole wall.

Summary of the invention

The present invention aims to provide an improved method for characterising fluid flow in a conduit, e.g. a borehole, with a well logging system, wherein the method allows for increased accuracy in determining fluid flow characteristics whilst relaxing positional requirements of the well logging system in the conduit.

According to the present invention, a method for characterising a fluid flowing in a conduit with a well logging system is provided, wherein the well logging system comprises an elongated probe body provided with a plurality of ultrasonic transducers spaced apart in

lengthwise/longitudinal fashion along an outer surface of the probe body, an ultrasonic transceiver system connected to the plurality of ultrasonic transducers for transmitting and detecting ultrasonic signals therewith, wherein the method comprises the steps of:

a) positioning the well logging system at a desired location within the conduit;

b) generating, with the ultrasonic transceiver system, a uniquely coded signal for each of the plurality of ultrasonic transducers,

c) transmitting, with the plurality of ultrasonic transducers, each uniquely coded signal into a fluid in the conduit;

d) detecting, with the plurality of ultrasonic transducers, one or more reflected coded signals from one or more entrained reflective interfaces in the fluid;

e) determining correlations, with the ultrasonic transceiver system, between the transmitted uniquely coded signals and the one or more reflected coded signals; and based on these correlations,

f) calculating a location and a velocity vector of each of the one or more reflective interfaces. According to the present invention, a unique coded signal is generated for each ultrasonic transducer and subsequently transmitted with an associated ultrasonic transducer into the fluid surrounding the well logging system, so for each ultrasonic transducer a uniquely identifiable coded signal is generated. Once transmitted into the fluid, the uniquely coded signals reflect from one or more entrained reflective interfaces in the fluid and are subsequently detected by the same plurality of ultrasonic transducers as reflected coded signals.

By transmitting the uniquely coded signals and subsequently detecting reflected coded signals with the plurality of ultrasonic transducers, it is possible to correlate reflected coded signals back to the ultrasonic transducers that transmitted the uniquely coded signals. So by determining correlations between the uniquely coded signals and the reflected coded signals it is possible to calculate locations and velocity vectors of reflective interfaces in the fluid.

It should be noted that calculation of locations and velocity vectors of the reflective interfaces is possible because the geometric/spatial layout of the plurality of ultrasonic transducers is known with respect to the well logging system, e.g. the probe body, and that detected codes signals reflected from reflective interfaces can be correlated back to their point of origin, i.e. the associated ultrasonic transducers in transmit mode. So an ultrasonic transducer that transmitted a particular uniquely coded signal can be correlated with an ultrasonic transducer that detected the reflected coded signal. Once correlations are known between receiving ultrasonic transducers and corresponding transmitting ultrasonic transducers, known methods can be used to determine locations and velocities of reflective interfaces in the fluid with respect to the well logging system. For example, by analysis of time of flight between transmission and detection, and knowledge of the ultrasonic transducers that transmitted the uniquely coded signal and the ultrasonic transducer that detected the reflected coded signals, the location of reflective interfaces in the conduit can be determined.

The velocity vector in a longitudinal direction within the conduit can be readily calculated through, for example, analysis of changes in peak-to-peak timing within a uniquely coded signal between transmission and detection, from which the velocity vector of the reflective particle may be determined in a direction away from or towards the detecting ultrasonic transducer using relationships between peak-to-peak time differences and the speed of sound in the fluid.

One of many advantages of the present invention is that a plurality of fluid velocities at different depths/distances from the well logging system can be determined accurately in a single transmission cycle. For example, simultaneously transmitting the uniquely coded signals with the plurality of ultrasonic transducers and subsequently detecting reflected coded signals with the same plurality of ultrasonic transducers is sufficient to determine a plurality of velocity vectors of the fluid at various distances from the well logging system. This allows for a high measurement rate compared to prior art methods that rely on multiple transmission an detection cycles.

A further advantage of the method is that the well logging system need not be centralized in the conduit but may be eccentrically positioned as well, e.g. along a wall part of the conduit, thereby providing increased positional freedom for a well logging system. Also, by allowing off centre/decentralized placement within the conduit, the method is able to include fluid flow characterisation around a central axis of the conduit and not just an annular fluid flow around the well logging system.

In a further aspect, the present invention relates to a well logging system for

characterising a fluid flowing in a conduit, comprising an elongated probe body provided with a plurality of ultrasonic transducers spaced apart in lengthwise/longitudinal fashion along an outer surface of the probe body, an ultrasonic transceiver system connected to the plurality of ultrasonic transducers for transmitting and detecting ultrasonic signals therewith, and wherein the ultrasonic transceiver system is configured to:

generate a uniquely coded signal for each of the plurality of ultrasonic transducers;

transmit, with the plurality of ultrasonic transducers, each uniquely coded signal into a fluid in the conduit;

detect, with the plurality of ultrasonic transducers, one or more reflected coded signals from one or more entrained reflective interfaces in the fluid;

determine correlations between the transmitted uniquely coded signals and the one or more reflected coded signals; and based on these correlations, to

calculate a location and velocity vector of each of the one or more reflective interfaces in the fluid.

Brief description of drawings

The present invention will now be described by way of reference to a number of illustrative embodiments as shown in the accompanying figures in which:

Figure 1 shows a side view of a well logging system arranged in a conduit in a direction of fluid flow according to an embodiment of the present invention;

Figure 2A shows a schematic view of a uniquely coded signal according to an embodiment of the present invention;

Figure 2B shows a schematic view of a reflected coded signal according to an embodiment of the present invention;

Figure 3 shows a side view of a well logging system arranged in a conduit in a direction opposite to fluid flow according to an embodiment of the present invention; and

Figure 4 shows a plurality of different conduit cross sections according to embodiments of the present invention.

Detailed description of embodiments

Oil and gas companies drill wells in order to produce hydrocarbon fluids from porous rocks contained in the subsurface. These hydrocarbon-containing rocks are referred to as reservoirs. Wells can also be used to inject fluids such as water or natural gas into these reservoirs. This is typically done to maintain pressure, drive hydrocarbons towards producing wells or to dispose of unwanted fluids such as excess water. In the geothermal industry, wells are drilled to produce hot water to surface, and to inject cold water back into the subsurface. Wells are drilled in sections. Each section is lined with steel or composite material pipe after the drilling phase, in order to keep the well stable and open, and also to isolate the different layers of rock that have been penetrated from each other and from the surface. This isolation is achieved by a sheath of cement that is placed in the annular space between the outside of the pipe and the different earth formations that are penetrated. The steel or composite linings are referred to as casing strings. When a casing string is not run fully back to surface but to a point higher up within the well bore, it is referred to as a liner.

After drilling and casing off a number of sections of the well, the well will reach the target formation, also called the target reservoir, or simply reservoir. After the target reservoir has been penetrated, this last section of the well may also be lined with steel pipe and cement, or it may be left open if the rock formation is sufficiently stable to allow this. If the reservoir is left open, it is referred to as an open hole completion or a barefoot completion.

After drilling the well, a smaller diameter production or injection pipe is installed into the well, reaching from surface to the top of the reservoir. This pipe is called tubing. Furthermore, flow communication needs to be established with the reservoir rock. If the reservoir is lined with steel pipe and cement, holes are created through the steel liner and cement using explosives. This is called perforating. If the reservoir is not lined, the well is referred to as an open hole completion or barefoot completion. In the case of a barefoot completion, drilling fluid residue or“mud cake” is often present on the well bore wall which can form a barrier to flow between the well bore and the reservoir rock.

In order to make the flow communication between the reservoir and well more efficient, stimulation activities may be carried out. These can consist of the placement of acids or other fluids that dissolve“mud cake” or particles present within the reservoir section of the well, thereby making the flow of fluids easier. Alternatively, wells may be stimulated using the injection of large volumes of viscous liquids and volumes of sand or other particles. Fractures are induced into the reservoir rock and these fractures are filled with the injected particles to make the flow of fluids into the well easier.

Following this stage, the well is ready to be taken into operation, producing fluids from the reservoir or injecting fluids into the reservoir.

Wells have traditionally been drilled vertically. In such wells, the length of the reservoir penetration was typically small, up to two hundred meters long. In recent years, wells are also drilled deviated or horizontal. These deviated or horizontal wells can have reservoir penetrations that can reach over ten kilometres in length.

As a result of production or injection operations, the condition of the well, the steel pipes installed into the well, and the reservoir rock will change. This can be the result of pressure changes, leading to stresses being exerted onto the wellbore. This can result in turn in pipe deformation or reservoir rock deformation or even collapse. Other changes may occur as a result of corrosion of installed tubulars. Yet other changes may be the result of injecting fluids at a pressure that is too high, resulting in the creation of unwanted fractures in the reservoir rocks. Such fractures can lead to unwanted distribution of fluid flow in the reservoir, since fluid will flow easier into fractures than into unfractured reservoir rocks. Yet other changes may be the result of chemical incompatibility between injected fluids and fluids naturally present in the reservoir.

When a reservoir is developed with multiple wells, it is desirable to understand the exact location within each well, where hydrocarbon fluids flow from the reservoir into the well, and of the exact location in each well where injected water flows from the well into the reservoir. This knowledge helps experienced professionals to decide where to drill future wells, and helps with predicting the expected ultimate recovery from the developed reservoir. If an undesirable location of fluid flow is detected, remedial activities may be executed to return the well to optimum performance, thereby improving the expected ultimate recovery of hydrocarbons from the reservoir.

From the above description it is clear that when operating a well, it is desirable to collect information from time to time about the distribution of fluid flow between the well and the reservoir, and also to collect information on the condition of the well, which often changes with time as a result of being operated.

Such measurements can be made with specialist measurement devices. Many of such devices exist. They are commonly referred to as Production Logging Tools (PLTs) to measure fluid distribution, or well condition monitoring tools to measure the condition of hardware items in the wellbore. Finally, a family of instruments exist that can detect the presence of fractures using ultrasonic scanning methods.

In order to characterize the downhole fluid flow in a well adequately, the following parameters are typically measured:

Natural Gamma radiation levels are measured. Each formation intersected by the well emits a specific and constant level of natural Gamma radiation originating from minerals contained in the formation rocks such as Uranium, Potassium or Thorium. This signature Gamma radiation profile is always measured during initial drilling of the well and is retained as a depth reference signature for future use. By measuring the level of Gamma radiation with the flow characterization system it is therefore possible to position the system exactly on depth by comparison to the reference Gamma ray vs. depth profile. The technology of Gamma radiation detection is disclosed in US2563333 (Herzog, 1951) and US2749446 (Herzog, 1951 ) and has been applied in virtually all downhole measurement devices and methods since then.

Pressure and Temperature are measured. The pressure and temperature in the flowing or injecting well can provide useful information to help interpret the condition of the well and the flow in different parts of the well. The use of these parameters has been known for many years and widely applied and described, for example in SPE-155439 (Peters et.al. 2012). The pressure and temperature may for example be used to calculate the velocity of sound in water as described in The Journal of Chemical Physics 22, 351 (A.H. Smith, A.W. Lawson, 1954).

The wellbore size is measured. All Production Logging Tools aim to measure the effective wellbore size. This information is necessary since the wellbore cross-sectional area can vary with depth and is therefore needed to compare volumetric flow rate along the well trajectory derived from flow velocity measurements (see later). It is a change in volumetric flow with depth that identifies if fluids enter of leave the wellbore. If only fluid velocity is compared, wellbore size or shape differences may yield false indications of fluid movement between the wellbore and the reservoir. Mechanical means of measuring the wellbore size are described for example in US1858544 (Erickson, 1928), US2695456 (Roberts, 1950) and US2721 1 10 (Price, 1953) and have found widespread use in tools since. More recently, the use of ultrasonic or acoustic calipers has emerged such as disclosed in US2596023 (Goble, 1944), US3369626 (Zemanek, 1965), US3835953 (Summers, 1973) and GB2254921 (Duckworth, 1992) where ultrasonic transducers are used to send an acoustic pulse from a downhole tool towards a wellbore wall and reflections are received. The distance between the transceiver in the tool and the wellbore wall can be derived from the travel time of the pulse with knowledge of the speed of sound in the medium traversed. This concept has been applied widely in different downhole applications since then.

Fluid flow velocity is measured. Every Production Logging Tool aims to measure fluid flow velocity since it is a very good indication of the amount of fluid that enters or leaves the wellbore. Many tools use mechanical spinner or rotating disc type flowmeters such as disclosed in

GB2323446 (Aguesse, 1997) and in US4566317 (Shakra, 1986). Other tools use ultrasonic measurements to derive fluid flow velocity, such as described in US3603145 (Morris, 1969), US4452077 (Siegfried II, 1982), US4947683 (Minear, 1989), US4905203 (Sims, 1988),

US5473948 (Moss, 1994), WO2013064494 (Hallundbaek, 2012), SPE155439 (Peters, 2012), WO2017009075 (Donzier, 2015) and WO2017153169 (Heijnen, 2016).

Downhole tool velocity is measured. Since all fluid velocity measurements are made relative to a tool body, it is important to correct for the velocity of the tool itself in order to derive the velocity of the fluid relative to the static wellbore. This tool velocity is usually derived from the rate of pay-out of the conveying means such as wireline or coiled tubing from which the tool is suspended in the wellbore. This method is for example disclosed in US4947683 (Minear, 1989). Unfortunately in highly deviated wells or horizontal wells, the velocity of the tool is often different from the rate of pay-out of wireline or coiled tubing at surface due to friction and what is called ‘stick-slip’ movement of the logging tool. In order to overcome this discrepancy and obtain a measurement of velocity at the tool itself, the velocity of the tool may also be determined from ultrasonic measurements as disclosed in US4452077 (Siegfried II, 1982) or disclosed in

SPE155439 (Peters, 2012).

Mechanical flow meters such as spinners or rotating discs have many disadvantages. The flow velocity is derived from the rotational velocity of the propeller or disc which is placed in the fluid flow. Because the propeller or disc can never be of the same diameter as the wellbore (it would be difficult to insert or use without damage), the instrument only measures the velocity in a part of the wellbore, which is often not representative of the true average velocity in the wellbore. Furthermore, these mechanical devices are prone to damage from debris present in the well such as sand particles or scale (organic or non-organic). A further disadvantage of mechanical spinners is the inertia and rotational friction of these devices. Each spinner has a unique minimum amount of flow, which is required before the spinner rotates, and has a unique resistance to rotation.

When using such devices it is therefore necessary to conduct calibration operations each time whilst the device is in the well to determine the relationship between observed spinner rotation and actual fluid flow velocity. These calibrations are time consuming and therefore undesirable. Because spinner sensors only measure the rate of rotation and not the direction of rotation, ‘spinner reversal’ is sometime difficult to observe and happens when the fluid flow velocity and the speed of the measurement device are similar. It is therefore necessary to conduct flow surveys at multiple deployment speeds when using spinner type sensors. This is also undesirable as it consumes more time.

Figure 1 shows a side view of a well logging system 3 arranged in a conduit 2 in a direction of fluid flow 1 according to an embodiment of the present invention. In the embodiment shown, the well logging system 3 comprises an elongated probe body 4 provided with a plurality of ultrasonic transducers 5 spaced apart in lengthwise/longitudinal fashion along an outer surface of the probe body 4, i.e. spaced apart in longitudinal direction of the probe body 4. An ultrasonic transceiver system 6 is provided, e.g. within a compartment of the probe body 4, and connected to the plurality of ultrasonic transducers 5 for transmitting and detecting ultrasonic signals. It should be understood that the ultrasonic transducers 5 may be used in transmission mode and/or receiving/detection mode. In an embodiment, the probe body 4 may further comprise a connector 4a configured to connect to a conveyance system such as wireline or coiled tubing (not shown) which may be further configured to allow electronic communications with surface equipment.

As depicted, the well logging system 3 is configured for insertion into a conduit 2 and to allow for various fluid flow measurements at some particular location of interest. In exemplary embodiments, the conduit 2 may be a borehole/wellbore, e.g. a vertical or horizontal borehole.

The fluid flow 1 through the conduit 2 may comprise water, oil, and various other compounds. The fluid flow 1 may be single phase, multiphase and may be laminar or turbulent.

Without loss of generality, the fluid flow 1 through the conduit 2 is considered to be mostly laminar as indicated by flow lines“F”. In laminar flow conditions, which are often present, the flow velocity of e.g. water varies as indicated by flowlines F. Flow velocity is minimal at a wall part of the conduit 2 and maximal in a centre zone of the conduit 2.

For the purpose of the present invention, the fluid flowing through the conduit 2 carries one or more entrained reflective interfaces 10 that are able to reflect acoustic signals, such as ultrasonic signals. For simplicity, the one or more entrained reflective interfaces 10 are assumed to be carried by the fluid flow 1 in unison, so that velocity vectors of the reflective interfaces 10 are representative for actual velocity vectors of the fluid flow 1 at the locations of the various reflective interfaces 10. In exemplary embodiments, the one or more entrained reflective interfaces 10 may comprise particles and/or gas bubbles.

According to the present invention, the method to characterise a fluid flowing through the conduit 2 can now be explained in further detail. In particular, the method starts with the step of a) positioning the well logging system 3 at a desired location within the conduit 2. In an embodiment, the well logging system 3 may be positioned in centralised fashion in the conduit 2 or

eccentrically/off centre in the conduit 2. In the depicted embodiment of Figure 1 , the well logging system 3 is arranged off centre and engages a side wall of the conduit 2. The conduit 2 may have any orientation at the location, i.e. vertical and non-vertical, e.g. a horizontal orientation. It is noted that the well logging system 3 need not be positioned in stationary fashion but may be moving continuously through the conduit 2 as well, so that positioning the well logging system 3 at a desired location may be interpreted as a position at a particular moment in time, i.e. a“snapshot”.

As the well logging system 3 is at the desired location in the conduit 2, the method continues with step of b) generating, with the ultrasonic transceiver system 6, a uniquely coded signal 8 for each of the plurality of ultrasonic transducers 5, where Figure 2A shows an embodiment of a schematic view of a uniquely coded signal 8.

Note that for step b) each generated uniquely coded signal 8 is allocated to one of the ultrasonic transducers 5 and that a uniquely coded signal 8 is a uniquely coded acoustic signal, e.g. a uniquely coded ultrasonic signal.

The method of the present invention continues with the step of c) transmitting, with the plurality of ultrasonic transducers 5, each uniquely coded signal 8 into the fluid in the conduit 2. In this step, each ultrasonic transducer 5 is in transmit mode and transmits a uniquely coded signal 8 into the fluid in a direction exemplified by a plurality of signal propagation paths 7 as shown in Figure 1.

As the various uniquely coded signals 8 propagate through the fluid away from the well logging system 3, one or more entrained reflective interfaces 10 in the fluid reflect the transmitted uniquely coded signals 8 back to the well logging system 3 along the signal propagation paths 7.

In light of these reflections, the method continues with the step of d) detecting, with the plurality of ultrasonic transducers 5, one or more reflected coded signals 9 from the one or more entrained reflective interfaces 10 in the fluid. See Figure 2B for a schematic view of a reflected coded signal 9 according to an embodiment of the present invention.

As the plurality of ultrasonic transducers 5 detect the one or more reflected coded signals 9, the method continues with the step of e) determining correlations, with the ultrasonic transceiver system 6, between the transmitted uniquely coded signals 8 and the one or more reflected coded signals 9; and based on these correlations, f) calculating a location and a velocity vector of each of the one or more reflective interfaces 10.

According to the method, a uniquely coded signal 8 is generated for each ultrasonic transducer 5 and subsequently transmitted with its associated ultrasonic transducer 5 into the fluid surrounding the well logging system 3, so that for each ultrasonic transducer 5 a uniquely identifiable signal 8 is generated. Once transmitted, the uniquely coded signals 8 reflect from the one or more entrained reflective interfaces 10 and are detected by the plurality of ultrasonic transducers 5, which are then in detect mode, as reflected coded signals 9 from the one or more entrained reflective interfaces 10.

By transmitting the uniquely coded signals 8 and subsequently detecting reflected coded signals 9 with the plurality of ultrasonic transducers 5, it is possible to correlate the reflected coded signals 9 back to the originating ultrasonic transducers 5 that initiated their transmission.

Through correlations between the transmitted uniquely coded signals 8 and the reflected coded signals 9 it is possible to calculate locations of reflective interfaces 10 in the fluid as well as velocity vectors thereof at those locations. In particular, calculation of locations and velocity vectors of the reflective interfaces 10 is possible because the geometric/spatial layout of the plurality of ultrasonic transducers 5 is known with respect to the well logging system 3, i.e. the probe body 4.

One of many advantages of the present invention is that a plurality of velocity vectors at different radial locations from the well logging system 3 can be accurately determined in a single transmission cycle. For example, simultaneously transmitting the uniquely coded signals 8 with the plurality of ultrasonic transducers 5 and subsequently detecting reflected coded signals 9 with the ultrasonic transducers 5 is sufficient to determine velocity vectors of the fluid at various distances from the well logging system 3. Such a single transmission cycle provides for higher measurement rate compared to prior art methods.

As mentioned above, the probe body 4 is provided with a plurality of ultrasonic transducers 5 spaced apart in lengthwise/longitudinal fashion along an outer surface of the probe body 4. In particular, the plurality of ultrasonic transducers 5 are spaced apart at distinct predetermined longitudinal positions 5a, 5b ,5c as depicted in Figure 1 . In an advantageous embodiment, the probe body 4 is provided with the plurality of ultrasonic transducers 5 spaced apart at the distinct longitudinal positions 5a, 5b ,5c and wherein for each longitudinal position 5a, 5b, 5c the plurality of ultrasonic transducers 5 are circumferentially arranged around the probe body 4. In this particular embodiment the plurality of ultrasonic transducers 5 are therefore provided as a plurality of circumferentially arranged ultrasonic transducers 5 at each longitudinal position 5a, 5b, 5c. For example, the embodiment of Figure 1 shows three circumferential arrangements of a plurality of ultrasonic transducers 5 spaced apart in correspondence with the three longitudinal positions 5a, 5b, 5c.

The plurality of ultrasonic transducers 5 in circumferential arrangements around the probe body 4 at each of the longitudinal positions 5a, 5b, 5c provides great freedom when positioning the well logging system 3 in method step a). That is, regardless of the rotational orientation of the probe body 4 with respect to a longitudinal axis of the conduit 2, and whether or not the well logging system 3 is centralized or not, the plurality ultrasonic transducers 5 allow measurements to be taking at a full 360° degrees around the probe body 4. Moreover, should the well logging system 3 be in engagement with the wall of the conduit 2, then one or more ultrasonic transducers 5 will not blocked by the conduit wall and as such accurate flow characterisation remains possible.

With further reference to Figure 2A, in an embodiment each uniquely coded signal 8 is a uniquely coded pulse train, e.g. a uniquely coded acoustic/ultrasonic pulse train. An advantage of utilizing uniquely coded pulse trains is that they can be easily generated and readily provided with a unique“signature” that is identifiable in reflected coded signals 9 detected by the ultrasonic transducers 5.

In light of the invention, a uniquely coded pulse train may comprise a plurality of pulses each having a distinct frequency and amplitude A1 , A2, A3, wherein the pulses are separated by pulse time periods P1 , P2. A pulse may take the form as a“chirp” or an alternative pulsed waveform. Each pulse is further characterised by its pulse time duration T1 , T2, T3. It is important to empathize that throughout the present disclosure the term“coded” may also be interpreted as“modulated”. That is, the uniquely coded signals 8 may likewise be interpreted as uniquely modulated signals 8 and a such uniquely coded (ultrasonic) pulse trains may likewise be interpreted as uniquely modulated (ultrasonic) pulse trains.

In a further embodiment, method step b) comprises differentiating each uniquely coded pulse train by differentiating pulse amplitudes A1 , A2, A3 between each uniquely coded pulse train. In this embodiment it is possible to provide a uniquely coded signal 8 as a pulse train coded by unique pulse amplitudes A1 , A2, A3.

In an even further embodiment, method step b) may comprise differentiating each uniquely coded pulse train by differentiating pulse time periods P1 , P2 between each uniquely coded pulse train. Here, each pulse train may be uniquely identified through pulse time periods P1 , P2.

In yet a further embodiment, method step b) may comprise differentiating each uniquely coded pulse train by differentiating pulse frequencies between each uniquely coded pulse train. In this embodiment , each pulse train may be uniquely identifiable through the frequencies used for the pulses.

Therefore, by differentiating amplitudes A1 , A2, A3, pulse time periods P1 , P2, and/or frequencies for each coded pulse train, it is possible to create a large number of uniquely coded pulse trains and thus a large number of uniquely coded signals 8 that facilitate the method step of correlating reflected coded signals 9 with uniquely coded signals 8.

In an embodiment, method step b) may comprise generating at least two pulse sets S1 , S2, wherein each pulse set S1 , S2 comprises at least two pulses, e.g. acoustic/ultrasonic pulses, and wherein a pulse time period P1 between the at least two ultrasonic pulses is shorter than a set time period Ts between the at least two pulse sets S1 , S2.

In this embodiment, each generated uniquely coded pulse train comprises temporally separated“batches” of pulses having particular amplitudes A1 , A2, A3, pulse time periods T1 , T2, T3 and frequencies, and wherein these“batches” (S1 , S2) of pulses are separated by the set time period Ts which is larger than each of the pulse time periods P1 , P2 within the pulse sets S1 , S2. This embodiment is advantageous as it further facilitates the method step of e) determining correlations between the transmitted uniquely coded signals 8 and the one or more reflected coded signals 9.

By means of the transmitted uniquely coded pulse trains, the reflected coded signals 9 take the form a reflected coded pulse train as depicted in Figure 2B. As the uniquely coded pulse trains propagate through the fluid, motion of the fluid as well as physical properties thereof alter the transmitted pulse trains as they propagate and reflect back toward the plurality of ultrasonic transducers 5.

For example, a reflected coded signal 9 in the form of a reflected coded pulse train is shown in Figure 2B, and may be characterised by amplitudes B1 , B2, B3, pulse time periods Q1 , Q2, and set time period Tr. Note that a reflected coded pulse train may slightly differ from its associated transmitted uniquely coded pulse train with particular amplitudes A1 , A2, A3, pulse time periods T1 , T2, T3 and set time period Ts as shown in Figure 2A.

A reflected coded pulse train may, in correspondence with its associated uniquely coded pulse train, comprise at least two pulse sets R1 , R2, wherein each pulse set R1 , R2 comprises at least two pulses, e.g. acoustic/ultrasonic pulses, and wherein a pulse time period Q1 between the at least two pulses is shorter than a set time period Tr between the at least two pulse sets R1 , R2.

Determining correlations according to method step e) may comprise to first determine for each detected reflected coded signal 9, i.e. reflected code pulse train, its ultrasonic transducer 5 of origin. Then through known geometry/spatial distribution of the plurality of ultrasonic transducers 5, locations of the reflective interfaces 10 can be calculated in method step f).

So in an exemplary embodiment, method step e) may comprise correlating a reflected coded signal 9 detected by a first ultrasonic transducer back to a corresponding uniquely coded signal 8 transmitted by a second ultrasonic transducer, wherein the first and second ultrasonic transducer are different. This embodiment then allows for calculating a signal propagation path and hence a location of a reflective interfaces 10 with respect to the well logging system 3.

Further correlations that can be determined in method step e) are changes in pulse time periods P1 , P2 of generated uniquely coded pulse trains versus pulse time periods Q1 , Q2, of the reflected coded pulse trains, from which velocity vectors of the reflective interfaces 10 can be calculated in method step f). So in an embodiment, method step e) may further comprise correlating changes between a pulse time period Q1 , Q2 of a reflected coded pulse train detected by the first ultrasonic transducer and a pulse time period P1 , P2 of the uniquely coded pulse train transmitted by the second ultrasonic transducer. This embodiment is based on“peak-to-peak” timing between transmitted and detected pulses and allows for calculating velocity vectors of the reflective interfaces 10 in method step f).

Even further correlations may be determined based on changes in amplitudes A1 , A2, A3 of generated uniquely coded pulse trains versus amplitudes B1 , B2, B3 of the reflected coded pulse trains. Correlations may also be determined based on changes in frequencies used for generated uniquely coded pulse trains versus frequencies detected of reflected coded pulse trains.

So in summary, various changes between transmitted uniquely coded signals 8 and associated reflected coded signals 9 yields information on locations and velocity vectors of the one or more reflective interfaces 10. Furthermore, the aforementioned changes between transmitted signals 8 and detected signals 9 may also provide information of fluid properties itself. For example, in an embodiment method step f) may comprise calculating a density of the fluid based on changes in amplitudes A1 , A2, A3 of a uniquely coded pulse train and amplitudes B1 , B2, B3 of its associated reflected coded pulse train as detected by the plurality of ultrasonic transducers 5.

Referring to Figure 1 , in an embodiment method step c) may comprise transmitting, with the plurality of ultrasonic transducers 5, each uniquely coded signal 8 at a different angle a1 , a2, a3 with respect to a longitudinal axis of the probe body 4 into the fluid. This embodiment not only allows for fluid flow characterisation over a wider area with respect to the well logging system 3, but also allows control over radial signal depth for determining locations and velocity vectors of the reflective interfaces 10. Therefore, the different angles allow reflections from different radial locations away from the well logging system 3 to be detected, describing flow velocity at different radial locations in the conduit 2 and as such provide accurate average fluid velocity in the conduit 2.

In an embodiment, transmitting each uniquely coded signal 8 at a different angle a1 , a2, a3 with respect to the longitudinal axis of the probe body 4 may be accomplished by arranging transmitting directions of the plurality of ultrasonic transducers 5 at these different angle a1 , a2, a3 with respect to a longitudinal axis of the probe body 4. The angles of the transmitting directions may lie between 5° to 60° with respect to the longitudinal axis of the probe body 4.

According to the present invention, accuracy of characterising fluid flow in a conduit 2 can be much improved by knowing the actual speed of sound in the fluid that surrounds the well logging system 3. To that end, the well logging system 3 further comprises a pressure and temperature sensor 11 , 12 arranged along the outer surface of the probe body 4, and wherein method step f) further comprises calculating the speed of sound in the fluid around the well logging system (3) from a measured pressure and measured temperature by the pressure and temperature sensor 1 1 ,12, respectively. Note that in this embodiment calculating the speed of sound is performed prior to calculating locations and velocities of the one or more reflective interfaces 10. Since properties of the fluid in the conduit 2 may change at particular locations, this embodiment ensures that accurate fluid flow characterisation is possible even when the composition of the fluid changes locally in the conduit 2.

As mentioned earlier, the method of the present invention does not require centralisation of a well logging system 3 inside the conduit 2. Furthermore, it may not always be the case that the well logging system 3 is longitudinally aligned with the conduit 2, which means that in particular scenarios the longitudinal axis of the probe body 4 may be arranged at an angle with respect to the longitudinal axis of the conduit 2 at the desired location.

To account for such an angular deviation of the well logging system 3 when calculating locations and velocity vectors of the one or more reflective interfaces 10, an embodiment is provided wherein the well logging system 3 further comprises a plurality of first ultrasonic distance sensors 13 circumferentially arranged around the probe body 4 at a first end e1 thereof, and a plurality of second ultrasonic distance sensors 14 circumferentially arranged around the probe body 4 at an opposing second end e2 thereof. Then prior to calculating locations and velocities of the reflective interfaces 10, method step f) further comprises the steps of

measuring a first wall distance between each of the plurality of first ultrasonic distance sensors 13 and a first conduit wall part, e.g. an opposing first conduit wall part, yielding a plurality of first wall distances between the first end e1 of the probe body 4 and the a first conduit wall part; and

measuring a second wall distance between each of the plurality of second ultrasonic distance sensors 14 and a second conduit wall part, e.g. an opposing second conduit wall part, yielding a plurality of second wall distances between the second end e2 of the probe body 4 and the a second conduit wall part. Based on the measured plurality of first and second wall distances, the method may then continue by determining a longitudinal orientation of the well logging system 3, i.e. the probe body 4, with respect to the longitudinal axis of the conduit 2 at the location of interest.

By using the first and second ultrasonic distance sensors 13, 14 that are circumferentially arranged around opposing ends e1 , e2 of the probe body 4, the method allows for increased accuracy of flow characterisation should the well logging system 3 be in an angled position with respect to the conduit 2. A typical example of this would be where the desired location is at a substantial horizontal part of a conduit 2 but where the probe body 4 is arranged in an inclined orientation.

The method of the present invention allows accurate determination of velocity vectors of reflective surface 10 from which flow lines“F” or flow fields“F” can be determined. In addition to characterising flow fields F within the conduit 2, an embodiment is provided wherein method step f) further comprises the step of calculating a volumetric flow rate of the fluid along the well logging system 3 based on the measured plurality of first and second wall distances as well as the calculated velocity vectors of the one or more reflective interfaces 10. In this embodiment, an effective cross section of the conduit 2 can be determined along the well logging system 3 based on the first and second wall distances measured by the plurality of first and second ultrasonic distance sensors 13, 14. From the calculated velocity vectors of the reflective interfaces 10 and the effective cross section of the conduit 2, a volumetric flow rate of the fluid along the well logging system 3 can be determined.

Additional advantages of the present method are provided. For example, in an embodiment method step f) may further comprise measuring, with the plurality of first or second ultrasonic distance sensors 13, 14, a wall hardness of the first or second conduit wall part, respectively. This embodiment provides geological information in conjunction with fluid flow characterisation. For example, measuring presence of soft“mud cake” at the first or second conduit wall part, so that the“mud cake” can be removed to improve conduit performance, e.g. performance of a borehole/wellbore.

In another advantageous embodiment, the well logging system 3 may further comprise one or more ultrasound motion sensors 18 and where method step f) may comprise, prior to calculating velocity vectors of the reflective interfaces 10, measuring with the one or more ultrasound motion sensors 18 a velocity of the well logging system 3 within the conduit 2. In this embodiment it is possible to take into account movement of the well logging system 3 within the conduit 2 when calculating velocity vectors of the reflective interfaces 10. In an embodiment, the one or more ultrasound motion sensors 18 may be arranged at the second end e2 of the probe body 4, wherein the second end e2 may be seen as the front or“nose” of the probe body 4.

In another advantageous embodiment, the well logging system 3 may further comprise one or more infrared sensors 15 circumferentially around the probe body 4, so that method step f) further comprises determining, with the one or more infrared sensors 15, a temperature profile of a conduit wall section. Such infrared sensors 15 may be arranged around the probe body 4 to obtain a thermal image of the a conduit wall section to further assist in determining the fluid flow in the conduit 2. This may be advantageous when making measurements in a water injection well, for example, where injected water is colder than geological formations in which it is injected. A cooling effect resulting from injection is then visible through the one or more infrared sensors 15 and can be recorded to further identify locations where water is injected.

In another advantageous embodiment, the well logging system 3 further comprises a gravity sensor 16, and wherein method step f) further comprises determining, with the gravity sensor 16, the direction of the Earth’s gravitational field relative to the probe body 4 and the plurality of ultrasonic transducers 5. Here, the gravity sensor 16 is employed to provide information on a rotational/radial orientation of the plurality of ultrasonic transducers 5 relative to the Earth’s gravitational field in e.g. a non-vertical conduit. This ensures that even if the well logging system 3 may rotate somewhat during measurements, the calculated velocity vectors are determined in a correct rotational/radial orientation in the conduit 2.

In an embodiment, the gravity sensor 16 may be combined with the use of the plurality of ultrasonic transducers 5 arranged at the different angles a1 , a2, a3 as mentioned earlier. This embodiment further reduces the need to centralize the tool within the conduit 2. This is advantageous in harsh and irregular geological environments such as open hole completed wells, wells with debris such as stimulation proppant, scale and the like.

In particular scenarios, the fluid in the conduit 2 may comprise both water and hydrocarbons and knowing the percentage of water and hydrocarbons in the fluid can be advantageous for further improving the characterisation of the fluid flow 1 . To that end an embodiment is provided wherein the well logging system 3 further comprises a microwave emitter 17 arranged along the outer surface of the probe body 4, and wherein method step f) further comprises the step of determining, with the microwave emitter 17, a dielectric constant of the fluid surrounding the well logging system 3. The microwave emitter 17 may further be used to measure the complex dielectric permittivity to microwave radiation of the fluid surrounding the well logging system 3.

In the present invention, the significant difference in relative dielectric constant of water (approximately 75) versus hydrocarbons (approximately 2 for liquids and 1 for gas) under microwave radiation at around 2.45 GHz, may be used in an embodiment of the method. For example, by irradiating the fluid with microwave radiation for a very short time period, e.g.

between 10 and 100 microseconds, and measuring the amount of energy absorbed by the fluid mixture surrounding the well logging system 3 during such a short time period, the percentage of water and hydrocarbons in the fluid can be determined.

In an advantageous embodiment, the probe body 4 may comprise a window of a suitable transparent material, e.g. glass, configured to allow microwave radiation from the microwave emitter 17 to pass through into the fluid.

As shown in Figure 1 , the method of the present invention may be performed when the well logging system 3 is arranged in a conduit 2 in a direction of the fluid flow 1 , thus wherein the aforementioned second end e2 of the probe body 4 may be viewed as the front or’’nose” pointing in a direction of the fluid flow 1 .

Figure 3 on the other hand shows an alternative flow direction, thus wherein the well logging system 3 is arranged in the conduit 2 in a direction opposite to the fluid flow 1 , i.e. the front/nose (second end e2) of the probe body 4 points in opposite direction to the fluid flow 1 . To accommodate such opposite flow direction as shown in Figure 3, an embodiment may be provided wherein transmitting directions of the plurality of ultrasonic transducers 5 are arranged at different angle a1 , a2, a3 with respect to a longitudinal axis of the probe body 4 such that the plurality of signal propagation paths 7 are now directed in a direction opposite to the fluid flow 1 .

As mentioned earlier, an important advantage of the method is that centralization of the well logging system 3 is not required. In light of this, Figure 4 shows a plurality of different conduit cross sections 2a, 2b, 2c according to embodiments of the present invention. As depicted, the conduit 2 may have a non-circular cross section 2a, e.g. an elliptical cross section, wherein the well logging system 3 may be positioned in method step a) on a most narrow arched wall section of the conduit 2.

In a further embodiment, the conduit 2 may have a substantial circular/round cross section 2b, so that the well logging system 3 may be positioned in method step a) on an arched wall section exhibiting a substantially uniform curvature along the entire circumference of the conduit 2.

Alternatively, the conduit 2 may have a non-circular cross section 2c, e.g. an elliptical cross section, but wherein the well logging system 3 may be positioned in method step a) on a widest arched wall section of the conduit 2.

It is noted that a conduit 2, e.g. a borehole, may be cased with steel liners, in which case a conduit cross section will be substantially round as indicated by the circular/round cross section 2b. When not lined with a steel casing but left as an open hole, the conduit 2 may have a large variety of shapes such as exemplified by the non-circular cross sections 2a, 2c. As also described in publication‘Viscous flow through pipes of various cross-sections’, by J. Lekner, European Journal of Physics 28 (2007) 521 -527, flow distribution may take many different forms in boreholes having different shapes and multiple spatially distributed measurements will allow a more accurate determination of average fluid velocity.

Figure 4 further shows an exemplary embodiment of a circumferential arrangement of ultrasonic transducers 5 around the probe body 4. As mentioned hereinabove, having a plurality of ultrasonic transducers 5 in circumferential arrangements around the probe body 4 at each of the longitudinal positions 5a, 5b, 5c as depicted in Figure 1 , will provide great freedom in positioning the well logging system 3 regardless of rotational orientation of the well logging system 3 with respect to the longitudinal axis of the conduit 2. Moreover, the well logging system 3 need not be centralized in the conduit 2.

As clearly shown in Figure 1 and 4, the circumferential arrangements of ultrasonic transducers 5 at each of the longitudinal positions 5a, 5b, 5c allows measurements to be taking at 360° degrees around the probe body 4. Furthermore, should the well logging system 3 be in engagement with the wall of the conduit 2, then accurate determination of the fluid flow 1 in the conduit 2 remains possible by means of the ultrasonic transducers 5 that are not blocked by the wall of the conduit 2.

In emphasized that having a detailed view of a cross sectional shape of a conduit 2 is advantageous for characterizing the fluid flow 1 there through. To that end, the method may comprise the step of determining a cross sectional shape of the conduit 2 with the plurality of first ultrasonic distance sensors 13 circumferentially arranged around the probe body 4 at the first end e1 , and/or the plurality of second ultrasonic distance sensors 14 circumferentially arranged around of the probe body 4 at the opposing second end e2. By virtue of the circumferential arrangement of the plurality of first and second ultrasonic distance sensors 13, 14, a

circumferential shape of the conduit 2 enclosing the well logging system 3 can be determined at the location of interest.

In a further aspect of the present invention but in direct relation to the method as outlined above, a well logging system 3 is provided and configured for use with the method for characterising fluid flowing in a conduit 2. In particular, the well logging system 3 comprises an elongated probe body 4 provided with a plurality of ultrasonic transducers 5 spaced apart in lengthwise/longitudinal fashion along an outer surface of the probe body 4. An ultrasonic transceiver system 6 is provided, typically arranged in a compartment of the probe body 4, and connected to the plurality of ultrasonic transducers 5 for transmitting and detecting ultrasonic signals therewith, wherein the ultrasonic transceiver system 6 is configured to:

generate a uniquely coded signal 8 for each of the plurality of ultrasonic transducers 5; transmit, with the plurality of ultrasonic transducers 5, each uniquely coded signal 8 into a fluid in a conduit 2;

detect, with the plurality of ultrasonic transducers 5, one or more reflected coded signals 9 from one or more entrained reflective interfaces 10 in the fluid;

determine correlations between the transmitted uniquely coded signals 8 and the one or more reflected coded signals 9; and based on these correlations, to

calculate a location and velocity vector of each of the one or more reflective interfaces 10 in the fluid.

The well logging system 3 is configured to perform the method steps b) to f) once it has been positioned at a desired location according to method step a). In correspondence with the method, in an embodiment the ultrasonic transceiver system 6 may be configured to generate a uniquely coded pulse train as the uniquely coded signal 8 for each of the plurality of ultrasonic transducers 5. In a group of embodiments, the ultrasonic transceiver system 6 may be configured to differentiate each uniquely coded pulse train by differentiating pulse amplitudes (A1 , A2, A3); pulse time periods (P1 , P2); and/or pulse frequencies between each uniquely coded pulse train. Each of the pulse train characteristics as exemplified in Figure 2 allow reliable correlation of reflected coded signals 9 with corresponding uniquely coded signals 8 as originally transmitted.

In an embodiment, the ultrasonic transceiver system 6 may be configured to generate a uniquely coded pulse train of at least two pulse sets S1 , S), each pulse set S1 , S2 comprising at least two ultrasonic pulses, and wherein a pulse time period P1 between the at least two ultrasonic pulses is shorter that a set time period Ts between the at least two pulse sets S1 , S2. Utilizing such“batches” of pulse trains facilitates correlation between reflected coded signal 9 with corresponding transmitted uniquely coded signals 8.

In an embodiment, each of the plurality of ultrasonic transducers 5 may be arranged at a different angle cd , a2, a3 with respect to a longitudinal axis of the probe body 4, thereby allowing for a more detailed fluid flow characterisation over a wider area with respect to the well logging system 3 as well as at different depth into the fluid flow. These different angles a1 , a2, a3 may be taken between 5°-60° degrees to get improved fluid flow determination at different radial locations with respect to the well logging system 3.

The well logging system 3 of the present invention is provided with a plurality of ultrasonic transducers 5 spaced apart in lengthwise/longitudinal fashion along an outer surface of the probe body 4. In particular, the plurality of ultrasonic transducers 5 are spaced apart at distinct predetermined longitudinal positions 5a, 5b, 5c as depicted in Figure 1 .

In an advantageous embodiment, the probe body 4 is provided with the plurality of ultrasonic transducers 5 spaced apart at the distinct longitudinal positions 5a, 5b, 5c and wherein for each longitudinal position 5a, 5b, 5c the plurality of ultrasonic transducers 5 are

circumferentially arranged around the probe body 4. So in this particular embodiment the plurality of ultrasonic transducers 5 are provided as a plurality of circumferentially arranged ultrasonic transducers 5 at each of the longitudinal positions 5a, 5b, 5c. In the embodiment of Figure 1 there are three of such circumferential arrangements of the plurality of ultrasonic transducers 5 spaced apart in correspondence with the three longitudinal positions 5a, 5b, 5c.

In a further advantageous embodiment, each of the circumferentially arrangements of ultrasonic transducers 5 around the probe body 4 may be arranged at different angles cd , a2, a3 with respect to a longitudinal axis of the probe body 4, thereby allowing for a more detailed fluid flow characterisation over a wider area around the well logging system 3 as well as at different radial location in the fluid flow 1 . So for each longitudinal position 5a, 5b, 5c, the circumferentially arranged ultrasonic transducers 5, i.e. transmitting directions thereof, may be positioned at different angles c , a2, a3 with respect to the longitudinal axis of the probe body 4.

In another advantageous embodiment, the well logging system 3 may further comprise one or more infrared sensors 15 circumferentially arranged around the probe body 4, so that method step f) further comprises determining, with the one or more infrared sensors 15, a temperature profile of a conduit wall section. Such infrared sensors 15 may be arranged around the probe body 4 to obtain a thermal image of the a conduit wall section to further assist in determining the fluid flow in the conduit, particularly when making measurements in a water injection well, where injected water is colder than geological formations in which it is injected. A cooling effect resulting from injection is then visible through the one or more infrared sensors 15 can be recorded to further identify locations where water is injected.

In an embodiment, the well logging system 3 further comprises a gravity sensor 16 configured to detect the direction of the Earth’s gravitational field relative to the probe body 4 and the plurality of ultrasonic transducers 5. As already mentioned in light of the method, the gravity sensor 16 is employed to provide information on a rotational/radial orientation of the plurality of ultrasonic transducers 5 relative to the Earth’s gravitational field in e.g. a non-vertical conduit. This ensures that even if the well logging system 3 may rotate somewhat during measurements, the calculated velocity vectors are determined in a correct rotational/radial orientation in the conduit 2.

The gravity sensor 16 may be combined with the plurality of ultrasonic transducers 5 arranged at different angles a1 , a2, a3 as mentioned earlier. This embodiment further reduces the need to centralize the tool within the conduit 2. This is especially attractive for irregular geological environments such as open hole completed wells, wells with debris such as stimulation proppant, scale and the like.

In an embodiment, the well logging system 3 may further comprise a microwave emitter 17 arranged along the outer surface of the probe body 4 and which emitter 17 is configured to detect a dielectric constant of the fluid surrounding the well logging system 3. The microwave emitter 17 may further be used to measure the complex dielectric permittivity to microwave radiation of the fluid surrounding the well logging system 3. In an advantageous embodiment, the probe body 4 may comprise a window of a suitable transparent material, e.g. glass, configured to allow microwave radiation from the microwave emitter 17 to pass through into the fluid.

In view of the above, the present invention can now be summarised by the following embodiments:

Embodiment 1. A method for characterising a fluid flowing in a conduit (2) with a well logging system (3), the well logging system (3) comprising

an elongated probe body (4) provided with a plurality of ultrasonic transducers (5) spaced apart in lengthwise fashion along an outer surface of the probe body (4), an ultrasonic transceiver system (6) connected to the plurality of ultrasonic transducers (5) for transmitting and detecting ultrasonic signals therewith, the method comprising the steps of:

a) positioning the well logging system (3) at a desired location within the conduit (2); b) generating, with the ultrasonic transceiver system (6), a uniquely coded signal (8) for each of the plurality of ultrasonic transducers (5),

c) transmitting, with the plurality of ultrasonic transducers (5), each uniquely coded signal

(8) into the fluid in the conduit (2);

d) detecting, with the plurality of ultrasonic transducers, (5), one or more reflected coded signals (9) from one or more entrained reflective interfaces (10) in the fluid;

e) determining correlations, with the ultrasonic transceiver system (6), between the transmitted uniquely coded signals (8) and the one or more reflected coded signals (9); and based on these correlations,

f) calculating a location and a velocity vector of each of the one or more reflective interfaces (10). Embodiment 2. The method according to embodiment 1 , wherein each uniquely coded signal (8) is a uniquely coded pulse train.

Embodiment 3. The method according to embodiment 2, wherein method step b) comprises differentiating each uniquely coded pulse train by differentiating pulse amplitudes (A1 , A2, A3) between each uniquely coded pulse train.

Embodiment 4. The method according to embodiment 2 or 3, wherein method step b) comprises differentiating each uniquely coded pulse train by differentiating pulse time periods (P1 , P2) between each uniquely coded pulse train.

Embodiment 5. The method according to any of embodiments 2-4, wherein method step b) comprises differentiating each uniquely coded pulse train by differentiating pulse frequencies between each uniquely coded pulse train.

Embodiment 6. The method according to any of embodiments 2-5, wherein method step of b) generating a uniquely coded pulse train comprises generating at least two pulse sets (S1 , S2), each pulse set (S1 , S2) comprising at least two ultrasonic pulses, and wherein a pulse time period (P1 , P2) between the at least two ultrasonic pulses is shorter that a set time period (Ts) between the at least two pulse sets (S1. S2).

Embodiment 7. The method according to any of embodiments 1-6, wherein method step c) comprises transmitting, with the plurality of ultrasonic transducers (5), each uniquely coded signal

(8) at a different angle (a1 , a2, a3) with respect to a longitudinal axis of the probe body (4).

Embodiment 8. The method according to any of embodiments 1-7, wherein method step e) comprises correlating a reflected coded signal (9) detected by a first ultrasonic transducer back to a corresponding uniquely coded signal (8) transmitted by a second ultrasonic transducer, the first and second ultrasonic transducer being different.

Embodiment 9. The method according to embodiment 8, wherein method step e) further comprises correlating changes between a pulse time period (Q1 , Q2) of the reflected coded signal

(9) detected by the first ultrasonic transducer and a pulse time period (P1 , P2) of the uniquely coded signal (8) transmitted by the second ultrasonic transducer.

Embodiment 10. The method according to any of embodiments 1 -9, wherein the well logging system (3) further comprises a pressure and temperature sensor (11 , 12) arranged along the outer surface of the probe body (4), and wherein method step f) further comprises, prior to calculating locations and velocities of the one or more reflective interfaces (10), calculating the speed of sound in the fluid around the well logging system (3) from a measured pressure and measured temperature by the pressure and temperature sensor (11 ,12), respectively. Embodiment 11. The method according to any of embodiments 1-10, wherein the well logging system (3) further comprises a plurality of first ultrasonic distance sensors (13) circumferentially arranged around the probe body (4) at a first end (e1) thereof, and a plurality of second ultrasonic distance sensors (14) circumferentially arranged around of the probe body (4) at an opposing second end (e2) thereof; and wherein method step f) further comprises, prior to calculating locations and velocities of each of the reflective interfaces (10),

measuring a first wall distance between each of the plurality of first ultrasonic distance sensors (13) and a first conduit wall part, yielding a plurality of first wall distances between the first end (e1) of the probe body (4) and the a first conduit wall part;

measuring a second wall distance between each of the plurality of second ultrasonic distance sensors (14) and a second conduit wall part, yielding a plurality of second wall distances between the second end (e2) of the probe body (4) and the a second conduit wall part; and based on the measured plurality of first and second wall distances,

determining a longitudinal orientation of the well logging system (3) with respect to a longitudinal axis of the conduit (2).

Embodiment 12. The method according to embodiment 11 , wherein, based on the measured plurality of first and second wall distances, and the calculated velocities of the one or more reflective interfaces (10), method step f) further comprises calculating a volumetric flow rate of the fluid along the well logging system (3).

Embodiment 13. The method according to any of embodiment 11-12, wherein method step f) further comprises measuring, with the plurality of first or second ultrasonic distance sensors (13,14), a wall hardness of the first or second conduit wall part, respectively. Embodiment 14. The method according to any of embodiments 1-13, wherein the well logging system (3) further comprises one or more infrared sensors (15) circumferentially around the probe body (4), wherein method step f) further comprises determining, with the one or more infrared sensors (15), a temperature profile of a conduit wall section. Embodiment 15. The method according to any of embodiments 1-14, wherein the well logging system (3) further comprises a gravity sensor (16), and wherein method step f) further comprises determining, with the gravity sensor, the direction of the Earth’s gravitational field relative to the probe body (4) and the plurality of ultrasonic transducers (5). Embodiment 16. The method according to any of embodiments 1 -15, wherein the well logging system (3) further comprises a microwave emitter (17) arranged along the outer surface of the probe body (4), and wherein method step f) further comprises determining, with the microwave emitter (17), a dielectric constant of the fluid surrounding the well logging system (3).

Embodiment 17. A well logging system for characterising a fluid flowing in a conduit, comprising an elongated probe body (4) provided with a plurality of ultrasonic transducers (5) separated in lengthwise fashion along an outer surface of the probe body (4), an ultrasonic transceiver system (6) connected to the plurality of ultrasonic transducers (5) for transmitting and detecting ultrasonic signals (7) therewith, wherein the ultrasonic transceiver system (6) is configured to:

generate a uniquely coded signal (8) for each of the plurality of ultrasonic transducers (5); transmit, with the plurality of ultrasonic transducers (5), each uniquely coded signal (8) into a fluid in the conduit (2);

detect, with the plurality of ultrasonic transducers (5), one or more reflected coded signals (9) from one or more entrained reflective interfaces (10) in the fluid;

determine correlations between the transmitted uniquely coded signals (8) and the one or more reflected coded signals (9); and based on these correlations, to

calculate a location and velocity vector of each of the one or more reflective interfaces

(10).

The present invention embodiments have been described above with reference to a number of exemplary embodiments as shown in and described with reference to the drawings. Modifications and alternative implementations of some parts or elements are possible, and are included in the scope of protection as defined in the appended claims.

Claims

1. A method for characterising a fluid flowing in a conduit (2) with a well logging system (3), the well logging system (3) comprising

c) transmitting, with the plurality of ultrasonic transducers (5), each uniquely coded signal (8) into the fluid in the conduit (2);

f) calculating a location and a velocity vector of each of the one or more reflective interfaces (10).

2. The method according to claim 1 , wherein each uniquely coded signal (8) is a uniquely coded pulse train.

3. The method according to claim 2, wherein method step b) comprises differentiating each uniquely coded pulse train by differentiating pulse amplitudes (A1 , A2, A3) between each uniquely coded pulse train.

4. The method according to claim 2 or 3, wherein method step b) comprises differentiating each uniquely coded pulse train by differentiating pulse time periods (P1 , P2) between each uniquely coded pulse train.

5. The method according to any of claims 2-4, wherein method step b) comprises differentiating each uniquely coded pulse train by differentiating pulse frequencies between each uniquely coded pulse train.

6. The method according to any of claims 2-5, wherein method step of b) generating a uniquely coded pulse train comprises generating at least two pulse sets (S1 , S2), each pulse set (S1 , S2) comprising at least two ultrasonic pulses, and wherein a pulse time period (P1 , P2) between the at least two ultrasonic pulses is shorter that a set time period (Ts) between the at least two pulse sets (S1. S2).

7. The method according to any of claims 1-6, wherein method step c) comprises transmitting, with the plurality of ultrasonic transducers (5), each uniquely coded signal (8) at a different angle (a1 , a2, a3) with respect to a longitudinal axis of the probe body (4).

8. The method according to any of claims 1-7, wherein method step e) comprises correlating a reflected coded signal (9) detected by a first ultrasonic transducer back to a corresponding uniquely coded signal (8) transmitted by a second ultrasonic transducer, the first and second ultrasonic transducer being different.

9. The method according to claim 8, wherein method step e) further comprises correlating changes between a pulse time period (Q1 , Q2) of the reflected coded signal (9) detected by the first ultrasonic transducer and a pulse time period (P1 , P2) of the uniquely coded signal (8) transmitted by the second ultrasonic transducer.

10. The method according to any of claims 1 -9, wherein the well logging system (3) further comprises a pressure and temperature sensor (11 , 12) arranged along the outer surface of the probe body (4), and wherein method step f) further comprises, prior to calculating locations and velocities of the one or more reflective interfaces (10),

calculating the speed of sound in the fluid around the well logging system (3) from a measured pressure and measured temperature by the pressure and temperature sensor (11 ,12), respectively.

11. The method according to any of claims 1-10, wherein the well logging system (3) further comprises a plurality of first ultrasonic distance sensors (13) circumferentially arranged around the probe body (4) at a first end (e1) thereof, and a plurality of second ultrasonic distance sensors (14) circumferentially arranged around of the probe body (4) at an opposing second end (e2) thereof; and wherein method step f) further comprises, prior to calculating locations and velocities of each of the reflective interfaces (10),

12. The method according to claim 1 1 , wherein, based on the measured plurality of first and second wall distances, and the calculated velocities of the one or more reflective interfaces (10), method step f) further comprises calculating a volumetric flow rate of the fluid along the well logging system (3).

13. The method according to any of claims 1 1 -12, wherein method step f) further comprises measuring, with the plurality of first or second ultrasonic distance sensors (13,14), a wall hardness of the first or second conduit wall part, respectively.

14. The method according to any of claims 1 -13, wherein the well logging system (3) further comprises one or more infrared sensors (15) circumferentially around the probe body (4), wherein method step f) further comprises determining, with the one or more infrared sensors (15), a temperature profile of a conduit wall section.

15. The method according to any of claims 1 -14, wherein the well logging system (3) further comprises a gravity sensor (16), and wherein method step f) further comprises

determining, with the gravity sensor, the direction of the Earth’s gravitational field relative to the probe body (4) and the plurality of ultrasonic transducers (5).

16. The method according to any of claims 1 -15, wherein the well logging system (3) further comprises a microwave emitter (17) arranged along the outer surface of the probe body (4), and wherein method step f) further comprises determining, with the microwave emitter (17), a dielectric constant of the fluid surrounding the well logging system (3).

17. A well logging system for characterising a fluid flowing in a conduit, comprising an elongated probe body (4) provided with a plurality of ultrasonic transducers (5) separated in lengthwise fashion along an outer surface of the probe body (4), an ultrasonic transceiver system (6) connected to the plurality of ultrasonic transducers (5) for transmitting and detecting ultrasonic signals (7) therewith, wherein the ultrasonic transceiver system (6) is configured to:

(10).