DOWNHOLE PRODUCTION AND INJECTION LOGGING TOOL WITH ULTRASOUND SENSORS FOR FLUID PHASE DETECTION

Specification

Field of the invention

The invention is related to a downhole production and injection logging tool for use in well bores especially for the Oil and Natural Gas Industry.

Background and Summary of the invention

Well bores are used in the petroleum and natural gas

industry to produce hydrocarbons (production well) or to inject fluids, for example water, CO2 and/or Nitrogen

(injection well) . Typically, such fluids are injected to stimulate, i.e. to enhance the hydrocarbon recovery.

Lately, CO2 injection has been introduced to this to reduce the C02-concentration in the atmosphere in order to defeat global warming.

Typically, a well bore is lined with a steel pipe or steel tubing, generally referred to as casing or liner, and cemented in the overburden section to reduce the risk of unwanted evacuation of fluids from the overburden and/or the reservoir into the surface environment. For completion of the reservoir section at present several options are typically used, namely open hole completion, or using a liner with several formation packers for sealing off

sections of the annulus around the steel liner, or using a steel liner which is cemented in place and access to the reservoir is gained by perforating the liner and cement in a later stage of the completion, or completion of the well with a liner in open hole which has predrilled holes in the liner to gain access to the reservoir. It should be noted that the holes can also be made in a later stage of the well life.

During the production or injection of fluids from a well bore in an earth formation the well bore can enlarge due to chemical reactions and/or an instability of the borehole. This may occur due to injection or production pressure changes and/or erosion which can take place e.g. in case of production from unstable geological formations such as turbidites known for their unpredictable sand face failure resulting in massive sand production leading to well failure. Furthermore, when injection processes are being used fractures can be generated resulting in undesired direct communication between the injection and production wells. On the other hand the well can collapse, for example caused by compaction, a process which happens when the pressure in the reservoir reduces, or by the use of

chemicals used to improve injectivity or productivity. The latter can cause a collapse of the annulus and therewith possibly block the access to the reservoir and, therewith, preventing injection or production. Also of importance may be a phenomenon which is called cross flow in the annulus. Cross flow in the annulus is the result of pressure

differences along the liner of the production or injection well in an un-cemented completion. The latter can lead to loss of production and/or loss of economic reserves.

The well bore and/or the casing or liner and/or the

reservoir section may, for example, be subject to

inspection e.g. in order to verify physical properties such as pressure or temperature, more general to collect

information about the status, or in order to observe defects or anomalies, in particular in order to prevent collapses of all kind of the well.

As the total length from the reservoir to an access at the top end of the well bore may sum up to several hundred or even several thousand meters retrieving such data, e.g. to an extraction facility at said access, is difficult and subject to continued development. In particular, said total length keeps increasing over the past decades.

Production Logging Tools (PLT) are known per se. Several suppliers of such tools exist on the market. However, these tools suffer from drawbacks and/or limitations. One issue is, that to measure the fluid flow with sufficient accuracy the majority of tools require moving parts in the form of a so called spinner which are vulnerable to mechanical damage especially when used in an open hole completion. Other limitations are that taking a downhole sample, performing a pressure build up test and/or performing a medium analysis of e.g. the fraction of water, oil and gas, better known as multiphase flow analysis, are not feasible with a single tool .

More and more well bores have highly deviated and even horizontal portions. In such conditions, the fluid in the well bore may separate to layers. Additionally or

alternatively, the failure rate of such tools resulting regularly in the complete loss and/or abandonment of the tool in the well is quite high. As the costs of one tool are significant, reduction of tool losses would be greatly appreciated . Therefore it is an object of the invention to provide a Production Logging Tool which allows for measurement in difficult well environments such as highly deviated wells and/or at least partly open hole wells.

Another object of the invention is to provide a robust and reliable PLT which despite its robustness and reliability allows for complex measurements in the well. Still another object of the invention is to provide an integrated multi-measurement PLT, wherein in one

measurement run several or all desired measurement data can be retrieved. Yet another aspect of the object of the invention is to improve the limitations mentioned above.

The object of the invention is achieved by subject matter of the independent claims. Preferred embodiments of the invention are subject of the dependent claims.

A downhole tool is presented herein being adapted to operate in a well bore. For example, well bores can

comprise difficult environmental conditions such as a pressure up to 35 MPa or a temperature which could rise up to 400 K, or, as development of well bore exploitation continues rapidly, even more. Such a well bore can have open hole sections and/or cased hole sections, and it can comprise an angle with respect to a vector towards the centre of the earth. In other words, the well bore or at least sections of the well bore can have any orientation in an earth formation, including for example horizontal portions which are even preferred and drilled intentionally depending on the type of well bore.

The well bore fluid can consist of different portions or "phases" of fluid such as mainly water, oil and/or gas, but also other fluid portions (phases) and also particulate matter, e.g. sand particles, can be phases of the well bore fluid. It is particularly desired to determine the

fractions of these phases in the well bore fluid and in the following, a down-hole tool is descripted being able to determine said phases and in preferred embodiments may even achieve further tasks in a single, combined down-hole tool.

The down-hole tool comprises a housing having a fluid inlet. In a simple embodiment, the fluid inlet is an open fluid inlet front side of a circular or ring shaped outer hull. In other words, the housing can be tube shaped like a mathematical cylinder. The well bore fluid thus can flow into this cylindrical housing.

The space inside the housing, e.g. the central portion in the tube shaped housing, defines an inner channel portion in the housing. In other words, an internal side of the housing surrounds said inner channel portion.

The fluid inlet may evolve into the inner channel portion. The fluid inlet and/or the inner channel portion may further be designed regarding fluid dynamics, e.g. to minimize accumulation of particulate matter and/or to minimize liquid resistance and/or to generate turbulence in the well bore fluid for mixing the phases of the well bore fluid before measurement of said fluid phases. The housing further comprises a fluid outlet in connection with the inner channel, so that well bore fluid can flow through the inner channel portion of the down-hole tool and leave the inside of the down-hole tool.

The fluid outlet can for example comprise several fluid exit through-channels in the housing, where through the well bore fluid exits the housing of the down-hole tool after having been measured.

The housing of the down-hole tool can thus be

advantageously designed in an essentially circumferentially closed manner, e.g. like a tube. In a particularly

preferred embodiment, the housing consists of an

essentially circumferentially closed tube-like casing with an open front side and a closed back end encompassing the inner channel portion, wherein in the inner channel portion measurements are performed.

The down-hole tool comprises an internal multi-phase sensor device for detection of fluid phases of the well bore fluid. The internal multi-phase sensor device resolves the typically at least two phases in the well bore fluid and can distinguish at least between water, oil and gas and determine the fractions of these fluid phases in the well bore fluid.

The internal multi-phase sensor device may comprise at least one sound wave generator device, such as an

ultrasound sensor, for resolving said phases. For example, the ultrasound sensor can emit ultrasound waves into the well bore fluid when flowing through the down-hole tool. In other words, the internal multi-phase sensor couples waves into the well bore fluid inside the down-hole tool.

Particularly preferred, the ultrasound sensor is arranged at the internal side of the housing and is directed towards the opposite side of the internal side of the housing. In other words, said waves are coupled into the well bore fluid and propagate through the well bore fluid in a direction transverse to the flow direction through the down-hole tool. As thus, the at least one sound wave generator device can be situated at the inner channel portion of the housing.

With the ultrasound sensor "scanning" the well bore fluid transversely, a propagation time for the sound wave (s) can be determined and thus the density of the well bore fluid can be determined. As, for example, water, oil and gas comprise different densities, a total amount of the portion of water, oil and/or gas can be obtained.

The proposed multi-phase sensor device advantageously is very reliable and robust as the proposed measurement method is minimally invasive in the well bore fluid and also can tolerate a high amount of suspended solid (particulate matter) . As the multi-phase sensor device is situated in an inner volume and surrounded by the housing, well defined measurement conditions inside the housing can be generated, for example, that the whole well bore fluid flow is guided or forced to flow through the inside of the housing and can thus be measured by the multi-phase sensor device as a whole, and/or that the well bore fluid flow can be

turbulated (mixed) to provide a mixed well bore fluid inside the housing, and/or that the measurement region inside the housing is protectable by the housing e.g. by use of an anti-particle grid at the opening of the housing for improving the measurement results.

In a particularly preferred embodiment, the multi-phase sensor device comprises only static components (i.e. which do not move or have moving parts) , and even more advanced, all of the components of the multi-phase sensor device are installed inside the housing.

Opposing the ultrasound sensor of the multi-phase sensor device, being installed at the internal side of the

housing, an ultrasound wave receiver may be situated - thus on the opposite side of the internal side of the housing. Alternatively, a wave reflector may be situated opposing the ultrasound sensor. However, it is particularly

preferred, that the internal side of the housing is

composed such, that internal waves generated by the

ultrasound sensor can be reflected by the housing and in the housing and then be returned to the ultrasound sensor.

In other words, in an embodiment for measurement,

ultrasound waves are generated at one side of the inner channel portion (laterally offset of a center line of the down-hole tool) and penetrate through the well bore fluid flowing through the down-hole tool along or parallel to said center line. The ultrasound waves are preferably directed transversely with respect to said center line. After passing through the well bore fluid they reach the opposite side of the inner channel portion, where they are measured or reflected back to the location of their generation, where they thus propagate through the well bore fluid a second time. By determining the "time of flight" of the sound waves through the well bore fluid, a

determination of the speed of sound and thus of the density of the well bore fluid is made possible.

The at least one sound wave generator device can then advantageously be designed as a transceiving ultrasound sensor being able to transmit and receive ultrasound sonic waves for releasing ultrasound sonic waves into the inner channel portion and for registering the same.

For increasing measurement accuracy, it is possible to install more than one ultrasound sensors, the ultrasound sensors being at least partly distributed along a

longitudinal axis of the down-hole tool. The ultrasound sensors preferably are directed in a direction which is transverse to the main axis of the down-hole tool

corresponding to the well bore fluid flow direction. By using several ultrasound sensors and distributing them along a longitudinal axis a repetitive or redundant

measurement of the fluid phases is possible. By way of example, it has been found out that installation of six or more ultrasound sensors delivers improved results.

If applicable, the several ultrasound sensors can even be interlinked using a measurement timing system for taking into account a fluid flow velocity in order to measure, with the distributed ultrasound sensors, the same amount of well bore fluid with the longitudinally distributed

ultrasound sensors. The ultrasound sensors can preferably also be distributed radial at the internal side of the housing. Thus the same amount of fluid can be penetrated in different planes. This can improve the measurement accuracy with respect to achieving the composition of the well bore fluid especially in the case when the phases of the well bore fluid are separated from each other - e.g. not mixed and/or separated in layers - and/or when the well bore is highly deviated from the direction towards the centre of the earth - e.g. a horizontally or mostly horizontal portion of the well bore. The down-hole tool can therefore also be adapted to operate in openhole condition and/or in horizontal portions of the well bore. The down-hole tool can further comprise an outside fluid flow sensor device for comparative measurement of a side flow fluid velocity. Thus, in the case when an outside fluid flow exists which bypasses the inner channel portion, additionally this outside fluid flow can be registered and measured.

Additionally, an inline static mixer for mixing phases of the well bore fluid inside the downhole tool can be

comprised in the down-hole tool. The optional inline static mixer can comprise e.g. fix blades and/or a helix structure to generate turbulence in the well bore fluid in the down- hole tool for mixing the wellbore fluid prior to

measurement of its composition by the multi-phase sensor device .

In a preferred embodiment of the down-hole tool a fluid flow blocker device arranged at an outer side of the down- hole tool is comprised for forcing the well bore fluid to flow through the down-hole tool. The fluid flow blocker device can be designed e.g. as a bellow or an expandable sealing element which can be expanded or extended e.g. by pumping a fluid (bellow fluid) into the bellow. However, a mechanical expansion or extension mechanism can also be implemented. The fluid flow blocker device seals at least a section of the well bore surrounding the down-hole tool, thereby preventing well bore fluid from bypassing the down- hole tool.

Additionally or alternatively an inner fluid flow blocker device can be arranged at the internal side of the down- hole tool. The inner fluid flow blocker device can further be arranged to reduce or stop fluid flow through the down- hole tool. When combined with the fluid flow blocker device the well bore fluid flow can be stopped, so that e.g. a pressure test can be performed. The down-hole tool is advantageously designed as a

multifunctional down-hole tool comprising further

measurement devices such as a gamma ray sensor and/or a resistive sensor. Further, the down-hole tool can comprise a pressure sensor and a temperature sensor arranged at the internal side of the down-hole tool. In other words, the multifunctional down-hole tool, for example, collects data in the well bore and/or the reservoir or which operates other functions particularly for sustaining the well bore. The down-hole tool can also comprise the functionality of a communication equipment in order to exchange data e.g. with a central station in the extraction facility. The down-hole tool can further comprise a sample logging device for in-situ sampling of the well bore fluid. Sample taking can be performed such, that a vacuumed (evacuated) sample container, arranged inside the downhole tool, is brought in contact with the well bore fluid and, on demand, is opened, so that well bore fluid fills the sample

container. It is possible to arrange several sample

containers in one down-hole tool so that at several

positions generation of a sample probe is possible, wherein the sample containers are fillable independently.

Additionally or alternatively, an inline static mixer can be installed before the sample logging device for in-situ sampling of the well bore fluid, so that the well bore fluid can be mixed just before the sample probe is filled into one (of the) sample container (s) .

For determining the velocity of the down-hole tool in the well bore the down-hole tool can comprise a tool velocity sensor. The tool velocity sensor e.g. can scan the inner surface of the well bore and/or of the liner/casing. In another embodiment the down-hole tool is driven by a driving unit, e.g. by a tractor, whereas the tool velocity sensor can determine the speed of the driving unit.

The down-hole tool is advantageously designed as an

autonomous down-hole tool. As such, the down-hole tool has a communication device for exchanging information with a secondary communication unit, such as a surface platform or station. The communication device of the down-hole tool can comprise an electromagnetic communication transceiver for

transmitting gathered measurement data to the secondary communication unit.

The down-hole tool may comprise a side shift unit for laterally moving the down-hole tool and/or for laterally tilting the down-hole tool in the well bore. In other words, the down-hole tool as a whole can be shifted

sidewards or the down-hole tool is tilted around a tilt point. The fluid inlet of the down-hole tool can thus be offset transversally or set "off-axis" with respect to a center line of the well bore. In other words, the fluid inlet of the down-hole tool can perform a sideshift

movement.

By using the sideshift unit, it is possible to guide different portions of the well bore fluid into the down- hole tool. By way of example, if the well bore fluid is layered, which can be the case e.g. in horizontal portions of the well bore, the separated layers can thus be

analysed, e.g., successively.

For achieving the sideshift movement, or for tilting the downhole tool, a swivel motor arranged inside the housing and offset with respect to a center line of the down-hole tool can be comprised for swivelling said sideshift unit with respect to the remaining down-hole tool. In another preferred embodiment, the housing is designed as a segmented housing comprising, along a longitudinal axis of the down-hole tool, at least two housing segments. The housing segments can, for example, be screwed together to form, when all segments are screwed to one another, an elongated, cylindrical down-hole tool. Examples of such housing segments may include a front bellow housing segment, wherein a fluid flow blocker device according is arrangeable on the front bellow housing segment, and/or a fluid measurement housing segment, wherein the internal multiphase sensor device is arranged in the fluid measurement housing segment, and/or a fluid exit housing segment, wherein the fluid outlet is arranged in the fluid exit housing segment.

Further examples of housing segments may include a

versatile housing segment for arranging various measurement devices inside the housing for achieving additional measurement capabilities with the same down-hole tool, and/or a sample container housing segment, wherein the sample logging device is arrangeable, and/or a supply housing segment for arranging electronics and/or supply fluids and/or an energy storage inside the down-hole tool.

Yet a further example of a housing segment may include a down-hole tool sideshift housing segment with a sideshift unit.

In one embodiment, the down-hole tool comprises a component capable of measuring the acceleration in three axis and therewith the radial position of every sensor versus the vertical axis. In other words, said component comprises an acceleration sensor such as a gyro which can detect

acceleration of the down-hole tool with respect to its environment. By evaluating the acceleration of the down- hole tool also the down-hole tool velocity in one, two or three axes and/or down-hole tool rotation in one, two or three axes can be determined.

To summarize, a great advantage of the presented down-hole tool is its capability to perform a multi-phase measurement of the well bore fluid with high accuracy omitting moving parts, resulting in a high reliability. The presented down- hole tool additionally is highly modular allowing

implementation of several measurement systems in one down- hole tool thereby reducing costs for obtaining data from a well bore. The invention is described in more detail and in view of preferred embodiments hereinafter. Reference is made to the attached drawings wherein like numerals have been applied to like or similar components. Brief Description of the Figures

It is shown in

Fig. 1 a schematic cross-sectional view of an earth

formation with a down-hole tool in a well bore; Fig. 2 another schematic cross-sectional view of an

earth formation with a down-hole tool in a well bore having a horizontal section partly covered by a liner;

Fig. 3 a sectional sideview schematic of a down-hole

tool section;

Fig. 3a a first cross-sectional schematic of a down-hole tool section; Fig. 3b a second cross-sectional schematic of a down-hole tool section;

Fig. 3c a third cross-sectional schematic of a down-hole tool section;

Fig. 4 a sectional sideview schematic of a down-hole

tool section;

Fig. 4a a fourth cross-sectional schematic of a down-hole tool section;

Fig. 4b a top view on the end of a down-hole tool

section;

Fig. 5 a sectional sideview schematic of a down-hole

tool having two sections;

Fig. 6 a sectional sideview schematic of a down-hole

tool section;

Fig. 7 a sectional sideview schematic of a down-hole

tool with sketched fluid flow;

Fig. 8 a sectional sideview schematic of a down-hole

tool having three sections;

Fig. 9 a sectional sideview schematic of a down-hole

tool having four sections;

Fig. 10 a sectional sideview schematic of a down-hole

tool having two sections;

Fig. 11 a sectional sideview schematic of a down-hole

tool having seven sections;

Fig. 12 a sectional sideview schematic of a twist device; Fig. 13 a sectional sideview schematic of a down-hole

tool having mounted a twist section.

Detailed Description of the Invention

In Fig. 1 a well bore 2 is drilled in an earth formation 4 to exploit natural resources like oil or gas. The well bore 2 continuously extends from the extraction facility 9 at or near the surface 6 to a reservoir 8 of the well bore 2 situated distal from the wellhead 10 at the extraction facility 9.

A casing/liner 12 in the form of an elongated steel pipe or steel tubing is located within the well bore 2 and

extending from the wellhead 10 to an underground section of the well bore 2. The reservoir 8 and/or the casing/liner 12 are typically filled with a fluid 16, 17, 18, respectively. The fluids 16, 17, 18 are e.g. oil or gas in case of a production well or water, CO2 or nitrogen in case of an injection well. A down-hole tool 20 is located within the casing or liner 12. Advantageously, the down-hole tool 20 operates

autonomously having internal power storage 92 (see e.g. Fig. 2) and thus needs not be powered or wired externally. To sum up, the down-hole tool 20 can be operated quite freely in the well bore 2 and particularly needs not to be cable linked to the surface.

The downhole tool 20 may additionally be a movable downhole tool 20 being moved by moving means 21, generally known to the skilled person, within the casing or liner 12 to any desired position in the casing or liner 12.

Fig. 2 shows another earth formation with a down-hole tool 20 positioned in a horizontal portion of the casing/liner 12. The liner 12 in this embodiment only partly covers the well bore 2. The down-hole tool 20 comprises a power supply 92. Fig. 3 shows a sectional drawing of a first portion 28a of an elongated housing 28 of the down-hole tool 20, having an inner channel portion 34 surrounded by the internal side 32 of said housing 28.

Ultrasound sensors 50 are installed in said first portion 28a at the internal side 32 of said housing 28, each ultrasound sensor 50 directing towards the respectively opposite side of the inner channel portion 34. The

ultrasound sensors 50 are grouped in three longitudinally separated groups along the down-hole tool central axis y, wherein each group consists of two radial arranged

ultrasound sensors 50 in sections A-A, B-B and C-C.

The diameter of the housing 28 can be chosen e.g. with respect to the well bore diameter the down-hole tool shall be used for, and may comprise in an example an outer diameter of 73mm and an inner diameter of 55 mm, resulting in a housing thickness of about 18 mm. However, the outer diameter of the housing 28 lies preferably in a range in between 50 mm to 90 mm.

Fig. 3a displays a cross-sectional view (along the line A-A of Fig. 3) through the housing 28 and the inner channel portion 34 showing the relative positions of two of the radially arranged ultrasound sensors 50.

Fig. 3b displays another cross-sectional view (along the line B-B of Fig. 3) through the housing 28 and the inner channel portion 34 showing the relative positions of two of the radially arranged ultrasound sensors 50. Fig. 3c displays a third cross-sectional view (along the line C-C of Fig. 3) through the housing 28 and the inner channel portion 34 showing the relative positions of two of the radial arranged ultrasound sensors 50.

Figs. 3a, 3b and 3c share a common horizontal axis x in order to depict the radial distribution of the ultrasound sensors in relation to each other. As can further de seen from figs. 3a, 3b and 3c, the housing 28 - or at least the first portion 28a of the housing 28 - comprises a

circumferentially closed - or at least essentially

circumferentially closed - tube-like shape, where the ultrasound sensors 50 are arranged at the internal side 32 of said housing 28 for internally measuring the phases of the wellbore fluid.

Fig. 4 shows another embodiment of the first portion or section 28a of the down-hole tool 20 having an inner channel portion 34 surrounded by the internal side 32 of said housing 28.

Ultrasound sensors 50 are arranged at the internal side 32 of said housing 28 being distributed longitudinally along the down-hole tool central axis y. The ultrasound sensors are also distributed radial so that they are able to penetrate the well bore fluid flowing through the inner channel portion 34 in different angles. The housing 28 comprises a frontside 38, also referred to as "nose" or fluid inlet, where the well bore fluid can flow into the inner channel portion 34. The frontside 38 can be designed so as to minimize flow resistance. The frontside 38 can also be designed so as to induce

turbulence to the well bore fluid for mixing the well bore fluid, especially mixing the phases of the well bore fluid, at the entrance portion of the well bore fluid into the down-hole tool prior to the subsequent measurement inside the down-hole tool. The fluid inlet can be designed to be evolving into the inner channel portion 34 which is

connected or adjacent to the frontside 38.

The outermost part of the housing is composed of an epoxy layer 29, wherein in the epoxy layer 29 electrical cables 31 can be embedded. The electrical cables 31 can, for example, feed the ultrasound sensors 50.

The electrical cables 31 can be connectable with electrical section connectors 33 in order to electrically connect one section 28a of the down-hole tool 20 with another section (see e.g. Figs. 7 to 13) .

In the ring-shaped housing of the embodiment shown in Fig. 4 also a fluid channel 35 is shown. The fluid channel 35 can e.g. provide a fluid to a bellow mounted at the outer side of the housing (see e.g. Fig. 5) .

Fig. 4a shows a cross-sectional view through a first section 28a of the housing 28, wherein six ultrasound sensors 50 are installed distributed circularly around the internal side 32 of the housing 28. The sensors 50 can be distributed more or less freely around the internal side 32 of the housing 28, whereas two sensors should not oppose each other. It is preferred to have each two ultrasound sensors 50 in a right angle (90°) to each other.

Fig. 4b shows a top view on the end of the first section 28a of the housing 28. The end of the first section 28a is designed to be connectable to e.g. a bellow section 28b (see e.g. Fig. 5) of the down-hole tool 20. Connecting means 37 are provided for connecting said sections 28a, 28b to each other. The connecting means 37 can e.g. be holes drilled into the housing 28, wherein a screw (not shown) is screwed. Sealing means like a sealing ring 39 or a sealing ring 39a can be provided to improve sealing of the down- hole tool 20. Electrical section connectors 33 can be distributed around the housing 28 for electrically

contacting the sections of the housing to each other. The fluid channel 35 can extend through more than one section end thus also be connectable to an adjacent section.

Fig. 5 shows another embodiment of the down-hole tool 20 in a sideview having the first section 28a and a bellow section 28b, the two sections 28a, 28b connected to each other thereby modularly forming the housing 28.

The well bore fluid 16, 17, 18 can enter the inner channel portion 34 of the down-hole tool 20 at its frontside 38 and flow through the sections 28b, 28a. When the well bore fluid 16, 17, 18 passes the ultrasound sensors 50

measurement of its composition, its phases can be made. The fluid channel 35 extends from the first section 28a to the bellow section 28b, where a fluid is provided to a front bellow 40. The front bellow 40 radially surrounds the downhole tool 20. In other words, the front bellow

encircles the bellow section 28b (but i.e. not to the full length of the bellow section 28b) . By pumping bellow fluid into the front bellow 40 through the fluid channel 35 the front bellow 40 can extend and thus, e.g., seal the outer side of the down-hole tool 20 against the casing/liner in the wellbore.

Fig. 6 shows another embodiment of an uncoupled bellow section 28b having a bellow 40. The bellow section 28b can be coupled to the first section 28a, wherein the bellow section 28b comprises a projection 26 to connect with the first section 28a. The projection 26 can be a

circumferentially closed projection 26 e.g. for improved sealing of the sectioning area.

In this embodiment a mixer 48 such as an inline static mixer is integrated in the bellow section 28b. The mixer 48 advantageously mixes the phases of the well bore so that an emulsion is present which simplifies measurement.

Fig. 7 shows yet another embodiment of the down-hole tool 20, wherein well bore fluid 16 can enter the inner channel portion 34 through the frontside 38 of the housing 28 and flow as an internal fluid flow 17 through the first section 28a and to the exit section 28c of the housing 28. The exit section 28c comprises several fluid exit channels 42 distributed radial around the housing 28 to allow the well bore fluid 16, 17 to leave the down-hole tool 20.

The fluid exit channels 42 can be designed such to reduce drag induced to the well bore fluid 16, 17 by applying an angle to the flow direction of the well bore fluid 16, 17 through the fluid exit channels 42. As depicted in Fig.7, the fluid exit channels 42 comprise a first exit channel section 42a where the individual channels do not fully penetrate the housing 28, but rather are notches at the internal side 32, where the depth of the notch increases towards the second exit channel section 42b. In the second exit channel section 42b the channels 42 do fully penetrate the housing 28. In the third exit channel section 42c the individual channels again do not penetrate the housing 28, but rather are notches at the outer side of the housing 28 with decreasing depth to the rear. Thus the fluid flow is not forced to deviate by 90 degrees from the main flow direction y but rather can smoothly exit the inner channel portion 34 to the outside.

The ultrasound sensors 50 are electrically connected via electrical cables 31, which in the first section 28a are embedded in the epoxy layer at the outer side of the housing. The electrical contact between the first and the exit section 28a, 28c is established by way of the

electrical section connectors 33.

Fig. 8 shows another embodiment of the down-hole tool 20 having a first section 28a, an exit section 28c and a multi section 28d. Again, the first section 28a comprises several internal ultrasound sensors 50 for measuring the phases of the well bore fluid 16, 17, 18. Also, the first section 28a comprises the fluid entrance 38. The fluid can leave the inner channel portion 34 of the down-hole tool 20 through the exit channels 42. However, part of the fluid 16, 17, 18 can remain in the down-hole tool 20. A multi section 28d comprises further features of the down- hole tool 20, such as a pressure sensor 52 and a

temperature sensor 54, whereas a combined pressure and temperature sensor 52/54 can be installed as well. A sample channel 30 allows for part of the fluid 16, 17, 18 to flow to a sample section 28f (see e.g. Fig. 11) where it may be stored. A sample channel close off valve 62 can regulate, whether fluid 16, 17, 18 is permitted to flow into the sample channel 30.

The multi section 28d further comprises a back bellow 41 which is also used for sealing the outer region around the down-hole tool 20 against the casing/liner 12 e.g. for performing a blow test and/or for forcing all well bore fluid 16, 17 to flow through the down-hole tool. A fluid channel 36 provides bellow fluid to the back bellow 41, such as liquid oil. Fig. 9 shows another embodiment of the down-hole tool 20, wherein the well bore fluid 16, 17 is depicted flowing through the bellow section 28b, the first section 28a, the exit section 28c and, if the sample channel close off valve 62 is switched open, also partly through the multi section 28d. It is referred to the preceding embodiments, wherein same reference numerals depict the same technical features.

Fig. 10 shows a multi section 28d mounted to an additional measurement section 28e including several additional measurement options and thereby partly demonstrating the great variability and modularity of the presented down-hole tool. The measurement section 28e comprises one or more outer ultrasound sensors 51, in this example four outer ultrasound sensors 51, directed towards the outside of the down-hole tool 20, e.g. for measuring the tool forward speed of the down-hole tool 20 in the wellbore 2.

The measurement section 28e further comprises one or more resistivity sensors 56, in the given example four

resistivity sensors 56, for measuring the resistivity of the well bore fluid 16, 17, 18. The measurement section 28e can also comprise a gamma ray sensor 58.

Fig. 11 depicts a version of the down-hole tool 20 having more features, whereas the presented down-hole tools 20 can easily be modified by replacing and/or adding sections 28a, 28b, 28c, 28d, 28e, 28f, 28g in order to customize the down-hole tool 20 with respect to the mission objective.

In Fig. 11 the wellbore fluid 16, 17, 18 flows into the inner channel portion 34 through the opening of the

frontside 38. The front bellow 40 for sealing the

casing/liner 12 surrounds the down-hole tool 20 and is situated next to the frontside 38. In the inner channel portion 34 adjacent to the opening of the frontside 38 there may be situated a mixer 48, such as an inline static mixer 48 depicted in the present embodiment. The mixer 48 can provide mixing of the well bore fluid phases for improving measurement results with the ultrasound sensors 50. Several ultrasound sensors 50 are situated at the internal side 32 of the housing 28 surrounding the inner channel portion 34. Starting from the influx region at the frontside 38 of the downhole tool the bellow section 28b comprises in the depicted embodiment said frontside 38 as well as the front bellow 40. The wellbore fluid 16, 17, 18 flows through the bellow section 28b and passes therein the inline static mixer 48 for being mixed in the downhole tool 20.

The mixed wellbore fluid 17 thereafter passes the

ultrasound sensors 50, which are mounted in the first section 28a, for measurement of the phases of the wellbore fluid 17. After the measurement using the internal multi ^¬ phase sensor device 50 the wellbore fluid 17 continues to the exit section 28c, where the wellbore fluid 17 can exit the downhole tool 20 through the exit channels 42. However, if a blow test, which is a pressure build-up test, in the wellbore shall be performed, blowing the back bellow 41 can fully interrupt the fluid flow in the wellbore. When blowing both the front bellow 40 and the back bellow 41 it is even possible to detect a leakage in the wellbore, e.g. in the casing/liner 12, when the leakage is situated between the front bellow 40 and the back bellow 41, as a fluid flow through the down-hole tool 20 continues while both bellows 40, 41 are blown. The pressure in the wellbore fluid 16, 17, 18 of the wellbore 2 is measurable using the pressure sensor 52, which is situated in the present embodiment in the multi section 28d. Also the temperature in the wellbore fluid 16, 17, 18 is measurable by way of the temperature sensor 54. In the present embodiment, the installed sensor is a combined pressure/temperature sensor 52/54. If a physical probe of the wellbore fluid 16, 17, 18 shall be taken, a logging device 70 is provided for taking such. By opening the sample channel close off valve 62 wellbore fluid 16, 17, 18 can enter into the sample channel 30 to flow towards the logging device 70. In the present

embodiment, the logging device 70 comprises four sample containers 72 for storing wellbore fluid. The sample containers 72 are evacuated. By opening one of the sample valves 64, the corresponding sample container 72 may be filled with an amount of wellbore fluid 16, 17, 18.

Samples of wellbore fluid 16, 17, 18 can be taken on general purpose, but however it is of particular interest to take a sample, if measurement results e.g. from the internal multi-phase sensor device 50 are not relied upon. This may be the case, when the ratios of the phases in the wellbore fluid 16, 17, 18 are such, that the composition is not distinctly identifiable, e.g. when the averaged density value which the ultrasound sensor 50 measures allows for two different percentages of the phases.

Undesired wellbore fluid 16, 17, 18 in the sample channel 30 can be evacuated through the sample channel exit valve 66.

Additional sensors provide further informations out of the wellbore 2. Outer ultrasound sensors 51 are installed at the outside of the housing situated in a measurement section 28e to measure e.g. the tools' movement velocity in the wellbore 2 in relation to the casing/liner 12 or the open hole wall. In the present embodiment, four outer ultrasound sensors 51 are used. Additionally, resistivity sensors 56 can measure the resistivity of the wellbore fluid 16, 17, 18 which also can provide information about the composition of the fluid. In the present embodiment, four resistivity sensors 56 are used .

Measurement of the gamma ray spectrum is possible using a gamma ray sensor 58. By implementing said gamma ray sensor 58 into the down-hole tool 20 parallel measurement of also the gamma ray spectrum can be performed with only a single tool, which alone can be a big advantage over prior art.

A bellow pump 44 provides pumping means for providing a fluid to the front bellow 40 and/or the back bellow 41, thereby expanding said bellows 40, 41. In the embodiment of Fig. 11 the bellow pump 44 is situated at the rearmost part of the down-hole tool 20 in a support section 28g. Furthermore, an electronics compartment 80 provides storage room for installation of electronics e.g. to determine said phases of the wellbore fluid 16, 17, 18 out of the

measurement data of the sensors 50, 51, 52, 54, 56, 58 installed. In other words, all necessary data processing and handling can preferably be done with the down-hole tool 20 itself. If the down-hole tool 20 further provides a data transmission device, e.g. in the electronics compartment 80, it is then possible to transmit measurement results to the surface, wherein no raw data needs to be transmitted and thus bandwidth of transmission can be spared. This is even more important, as data transmission rates from an elongated wellbore 2 having a length of several kilometres may be limited. The electronics compartment 80 is situated in the embodiment of Fig. 11 in the support section 28g.

Further, in the support section 28g e.g. energy and/or a power unit for independent power supply 92 can be situated.

Fig. 12 depicts a twist device 100. Depending on where or whether the down-hole tool 20 has a fix point (suspension point) where the down-hole tool 20 is fixed with respect to lateral movement in the wellbore 2, the down-hole tool 20 can either be twisted or tilted in the wellbore 2, but can also be shifted sidewards. For example, the down-hole tool 20 can be moved by a tractor through the wellbore 2. The down-hole tool 20 may be fixed at its rear side, e.g.

centrally to the tractor. By twisting, tilting or laterally moving the down-hole tool 20 with the twist device 100, the frontside 38 can be displaced out of the wellbore central axis to a side thereby allowing for e.g. a side flow in the wellbore to enter the down-hole tool 20. This is of

particular interest if the phases in the wellbore 20 are segregated, e.g. layered, so that each phase can be

measured individually.

The twist device 100 comprises a rotary portion 102 having a a swivel motor 104 (twist motor) installed off-center in the rotary portion 102. A shaft 106 protrudes from the rotary portion 102 to be inserted off-center into another section of the down-hole tool 20. In the depicted

embodiment of Fig. 12, the shaft 106 is inserted into a fix portion 112 of the twist device 100. The fix portion 112 ca fixedly be connected to the next section of the down-hole tool 20, such as e.g. depicted in Fig. 13 to the support section 28g. By moving the swivel motor 104, the rotary portion 102 rotates eccentrically.

The twist device 100 of the present embodiment also comprises a second rotary portion 122 having a second swivel motor 124 and a second shaft 126, wherein second swivel motor 124 and second shaft 126 are mounted radial off-center. The effect of the second rotary portion 122 is comparable to the rotary portion 102, the range of the twist or lateral offset inducible by the twist device 100 on the down-hole tool 20 can be doubled by using two rotary portions 122, 124. However, it is to be understood, that one rotary portion 102 may suffice for the benefit of this feature .

The twist device 100 further comprises a shaft 130

mountable e.g. to a tractor for moving the down-hole tool 20 in the wellbore 2, or for any handling of the down-hole tool 20.

The twist device 100 may be designed as a twist section 28h for being coupled to another section of the down-hole tool 20. Fig. 13 finally shows a variant of the down-hole tool 20 comprising a segmented housing 20 for modularly

implementing one, several or all features described above. The segmented housing 20 comprises the several sections 28a, 28b, 28c, 28d, 28e, 28f, 28g, 28h. Same features are depicted with same reference signs, so that before

mentioned features, which can be present individually or combined with other features in one of the embodiments depicted above, can also be present in this embodiment. The above description is thus referenced.

To summarize, a down-hole tool 20 which allows for

determination of phases in the wellbore fluid is presented. The down-hole tool 20 uses an internal multi-phase sensor device 50 to determine the wellbore fluid phases, e.g. by measuring the "time of flight" of an ultrasound wave travelling through said wellbore fluid 17 inside the down- hole tool 20.

It will be appreciated that the features defined herein in accordance with any aspect of the present invention or in relation to any specific embodiment of the invention may be utilized, either alone or in combination with any other feature or aspect of the invention or embodiment. In particular, the present invention is intended to cover a downhole tool configured to include any feature described herein. It will be generally appreciated that any feature disclosed herein may be an essential feature of the

invention alone, even if disclosed in combination with other features, irrespective of whether disclosed in the description, the claims and/or the drawings. It will be further appreciated that the above-described embodiments of the invention have been set forth solely by way of example and illustration of the principles thereof and that further modifications and alterations may be made therein without thereby departing from the scope of the invention. List of reference signs:

2 Well bore

4 earth formation

6 surface

8 reservoir

9 extraction facility

10 well head

12 casing/ liner

16 wellbore fluid

17 fluid, internal fluid flow

18 fluid, outside fluid

20 down-hole tool

21 moving means

26 projection

28 housing

28a first section

28b bellow section

28c exit section

28d multi section

28e measurement section

28f sample section

28g support section

28h twist section

29 epoxy layer

30 sample channel

31 electrical cable

32 internal side

33 electrical section connector

34 inner channel portion

35 fluid channel

36 fluid channel

37 connecting means 38 frontside

39 sealing ring

39a sealing ring

40 front bellow

41 back bellow

42 fluid exit channel

42a first section of the fluid exit channel

42b second section of the fluid exit channel

42c third section of the fluid exit channel

44 Bellow Pump

46 Bellow fluid reservoir

48 Mixer

50 internal multi-phase sensor device; ultrasound sensor

51 outer ultrasound sensor

52 pressure sensor

54 temperature sensor

56 resistivity sensor

58 gamma ray sensor

62 sample channel close off valve

64 Sample valve

66 Sample channel exit valve

70 logging device

72 sample container

80 Electronics

92 stand-alone power supply

100 twist device

102 rotary portion

104 swivel motor

106 shaft

112 fix portion

122 second rotary portion

124 second swivel motor second shaft

shaft e.g. for tractor