Mandrel Arrangement and Method of Operating Same

Abstract

A mandrel arrangement is for use in a wellbore tubing. A method is for using the same. A mandrel body houses at least one piston, the at least one piston being movable in relation to the mandrel body between a first position and a second position by a fluid force acting on the piston. A cavity is arranged adjacent the piston for communicating wellbore fluid pressure between the wellbore tubing and the piston. The cavity is provided with drainage means for facilitating removal of any particles present in at least a lower portion of the cavity.

Description

This invention relates to a cycle open system for well barriers and other well tooling. More specific, the present invention relates to a mandrel arrangement for use in a wellbore tubing, the arrangement comprising a mandrel body housing at least one piston, the at least one piston being movable in relation to the mandrel body between a first position and a second position by a fluid force acting on the piston; and a cavity arranged adjacent the piston for communicating wellbore fluid pressure between the wellbore tubing and the piston.

In conjunction with the completion of wells, involving steps such as the installation of production casing, production liner (lower completion) and production tubing (upper completion), barrier systems are commonly used.

In one scenario, a barrier is mounted in top of the lower completion (production liner), to isolate the reservoir whilst installing the production tubing (upper completion) in the upper section of the well.

In another scenario, a barrier is installed in the bottom of the production tubing during the installation of this. Once the tubing is positioned correctly, pressure is applied on the inside to set the production packer. To form a sealed enclosure during such operation, to allow for pressurizing the internals of the tubing, the bottom of the tubing has to be sealed off. Most commonly, such seal is provided for by using a barrier device.

A common requirement to the above described barrier systems is the ability to withhold the required pressure during the stages where such barrier functionality is required. A second, equally important requirement is that the barrier can be opened r removed when barrier functionality is no longer required, to open the liner and/or production tubular so that fluids can flow through it.

Traditionally, these temporary completion barriers were installed and retrieved using well service techniques such as wireline or coil tubing.

In many offshore fields, very costly drilling rigs are utilized for the purpose of drilling and completing a well. In such cases, any time spent on wireline or coil tubing operations will contribute to making the completion of the well increasingly expensive, as it increases the time the drilling rig has to be rented for the completion of the well. To remove the need to operate the above mentioned barrier systems on wireline or coil tubing, barriers that can be operated to open without the need for physical intervention into the well have been developed. Initial systems of such kind were ball valves, flapper valves, sliding sleeves or similar that was operated open by cycling well pressure using a pump at the surface of the well.

Cycling pressure means repeated pressurizing and depressurizing (bleeding down) the tubing (and/or liner top) fluid in order to operate mechanical counter systems associated with the downhole barrier. Typically, after a certain amount of pressure cycles, the mechanical counter system will engage with a barrier activation mechanism that causes the barrier/valve to open. Typically, such engagement is achieved by the counter mechanism ultimately operating a valve member of the activation system, that allows well pressure to work against an atmospheric chamber via a piston, and the resulting work is used to shift the valve member to an open position. In other versions, such engagement is achieved by the counter mechanism ultimately operating a mechanical lock of the activation system that releases a pre-tensioned spring mechanism in the activation mechanism, whereupon this causes the valve member to shift to an open position. Other similar methods of activating and shifting the valve member may be applied. Such methods would be appreciated by a person skilled in the art, and are not described further herein.

US 2010/307773 A1 discloses a method and an apparatus for controlling a well barrier as arranged so as to be able to be inserted into a well for allowing a first well zone to be separated from a second well zone by means of a sealing element wherein the method includes setting a pressurized fluid in communication with an activating element by selectively controlling an opening device.

U.S. Pat. No. 6,244,351 B1 discloses a well string for use in a wellbore having plural fluid regions, including a flow conduit having an inner bore defining one of the fluid regions and an actuating assembly including an operator mechanism, an activation port in communication with the operator mechanism, and a member adapted to block the activation port.

U.S. Pat. No. 5,226,494 A discloses a method and an apparatus for actuating one or more downhole well tools carried by a production or work string conduit having an imperforate wall and for blocking fluid communication between an activating fluid body and a second fluid source within said well across dynamic seals between actuating members of the well tool, by producing selective signals through the conduit wall detectable by a member to produce an activating signal for actuating the downhole well tool by a downhole energy source.

U.S. Pat. No. 4,356,867 A discloses a method and an apparatus for setting a temporary lock-open mechanism incorporated in a safety valve employed in a subterranean well, the apparatus including an annular mandrel having an external, axially movable, radially expandable collet operated by an axially movable prong concentrically arranged within the mandrel housing.

US 2009065213 A1 discloses a downhole valve assembly including a valve mounted in a tubular body, the valve moveable between an open and closed position. Movement is achieved by a fluid operated valve actuation mechanism located downhole of the valve having a fluid inlet port located uphole of the valve.

GB 2345505 A discloses an actuating apparatus for use with a downhole tool in a wellbore including a flow conduit having an inner bore, comprising an operator piston, a port in communication with the operator piston, a moveable member that when in a first position blocks the port from fluid pressure in the flow conduit inner bore, and an actuating assembly responsive to pressure outside the flow conduit to move the member to a second position to expose the port to the flow conduit inner bore to enable communication of fluid pressure from the flow conduit inner bore to the operator piston.

Alternative barrier systems to metallic valves are barriers made of non-metallic materials such as for example glass, ceramics, salt or other more brittle materials. A common method for barrier removal in this respect is a mechanical cycle open mechanism that triggers an activation mechanism where an explosive charge is detonated inside or in close proximity to the brittle barrier. An alternative method entails the mechanical cycle open mechanism to operate a mechanical lock that holds a pre-tensioned spring system. When releasing the pre-tensioned spring, this will drive an impact device such as a spear into the brittle barrier to crush it. Even another method for removal is to lead a highly pressurized fluid in between brittle barrier components. Such methods are assumed known to someone skilled in the art, and not further referred to herein.

A well known problem with the above described remotely operated mechanical systems is that if the cycle open mechanism or activation mechanism fails to operate, or if the valve element fails to shift open for any other reason, alternatives for mechanical removal of the barrier are associated with a relatively high cost and risk.

An example of alternative removal is to use coil tubing to shift open, or in the worst case mill out a bail valve or a steel flapper valve.

Typical causes of failure may be debris in the well that jams the cycle open mechanism, the activation mechanism or the valve element itself. It is known that the s cleaning of a well can be problematic, and that it is difficult to guarantee that the environment where the cycle open mechanism operates is clean from debris, high viscous agents and similar that could cause problems.

Thus, there is a need to provide a cycle open mechanism that removes or at least reduces the problem of jamming due to debris and other impurities in the area of the well where the system is located.

The object of the invention is to remedy or reduce at least one of the drawbacks of prior art.

The object is achieved in accordance with the invention by the characteristics stated in the description below and in the following claims.

According to a first aspect of the present invention there is provided a mandrel arrangement for use in a wellbore tubing, the arrangement comprising: a mandrel body housing at least one piston, the at least one piston being movable in relation to the mandrel body between a first position and a second position by a fluid force acting on the piston; and a cavity arranged adjacent the piston for communicating wellbore fluid pressure between the wellbore tubing and the piston, wherein the cavity is provided with drainage means comprising an opening arranged for communicating fluid between the cavity (701) and the wellbore tubing (106), thereby for facilitating removal of any particles present in at least a lower portion of the cavity.

Preferably, the opening is an opening inclined downwards in a direction from the cavity towards the wellbore centerline. This has the effect that gravity will facilitate drainage of particles having a specific gravity higher than that of the wellbore fluid.

The cavity may be a recess open to the wellbore fluid, the recess being defined by a first portion, a second portion, and a side portion bridging said first portion and second portion, the second portion including the surface of the piston or a fluid pressure transition element extending from the cavity to the piston.

In one embodiment the first portion of the recess is inclined away from the second portion in a direction from the side portion of the recess towards the wellbore centerline. Thus, if the piston is arranged below the cavity the recess is slanting downward in a direction towards a wellbore centerline. This has the effect that gravity will facilitate drainage of particles having a specific gravity higher than that of the wellbore fluid.

In one embodiment the second portion of the recess is inclined away from the first portion in a direction from the side portion of the recess towards the wellbore s centerline. Thus, if the piston is arranged above the cavity the recess is slanting upward in a direction towards a wellbore centerline. This has the effect that gravity will facilitate drainage of any particles having a specific gravity lower than that of the wellbore fluid or reduce the possibility of entrapping any particles towards the piston.

The recess may be provided with both first portion and second portion being provided ID with inclined surfaces as described above.

In one embodiment, the mandrel body comprising an outer mandrel portion and an inner mandrel portion, the inner mandrel portion facing the fluid in the wellbore, and wherein the piston being arranged between the outer mandrel portion and the inner mandrel portion.

The piston or the fluid pressure transition element(s) may be provided with sealing means arranged for sealing off an annulus between the piston and the mandrel body. One purpose of the sealing means is to prevent impurities from entering between the piston or the fluid pressure transition element(s) and the fixed mandrel. Another purpose of the sealing means is to provide a pressure seal.

In one embodiment, the piston or the fluid pressure transition element(s) is/(are) further provided with a scraper ring. The purpose of the scraper ring is to provide a further seal of the annulus between the piston and the mandrel body.

In one embodiment, the fluid pressure transition element(s) is/are provided with scraper cap instead of said scraper ring.

According to a second aspect of the present invention there is provided a method for facilitating operation of a mandrel arrangement for use in a wellbore tubing wherein the arrangement comprises: a mandrel body housing at least one piston, the at least one piston being movable in relation to the mandrel body between a first position and a second position by a fluid force acting on the piston; and a cavity arranged adjacent the piston for communicating wellbore fluid pressure between the wellbore tubing and the piston, wherein the method comprising providing the cavity with drainage means for allowing removal of any particles present in at least a lower portion of the cavity.

The following describes a non-limiting example of a preferred embodiment illustrated in the accompanying drawings, in which:

FIG. 1 a-1c illustrates one example generic use o the invention;

FIG. 2 illustrates a prior art side pocket mandrel housing a mechanical cycle open mechanism forming an integral part of a tubing;

FIG. 3 shows in larger scale a prior art mechanical cycle open mechanism;

FIG. 4 a-4d illustrates various steps of operating the mechanical cycle open mechanism in FIG. 3;

FIG. 5 illustrates a prior art mechanical cycle open mechanism provided by means of an annular mandrel instead of a side pocket mandrel as illustrated in FIG. 2;

FIG. 6 illustrates a prior art mechanical cycle open mechanism provided by means of an annular mandrel instead of a side pocket mandrel as illustrated in a larger scale in FIG. 2;

FIG. 7 a illustrates a mechanical cycle open mechanism according to the present invention;

FIG. 7 b illustrates a mechanical cycle open mechanism in FIG. 7a provided with further details;

FIG. 8 a illustrates an alternative embodiment of the mechanical cycle open mechanism in FIG. 7a;

FIG., 8b illustrates an alternative embodiment of the mechanical cycle open mechanism in FIG. 8a; and

FIG. 9 is a view through line A-A in FIG. 8a and 8b.

FIG. 1 a-1c illustrates a borehole 101. Casing 102 is used to prevent the borehole from collapsing during drilling and subsequent production, and to seal off the borehole wall to prevent unwanted leakage to or from strata/zones in the underground and ultimately to provide a barrier between the pressurized hydrocarbon reservoir and the open environment. In most cases, the casing is cemented to the rock wall as will be appreciated by any person skilled in the art and thus not illustrated herein. A generic well completion is illustrated. In this illustrated case, the lower completion comprises a cemented production liner 103 which is open towards the hydrocarbon reservoir via perforations 104. A person skilled in the art will know that the design and configuration of the production liner 103 may vary significantly from what is illustrated herein. The production liner 103 is anchored to and forms a seal towards the casing 102 by means of a liner hanger system 105.

The upper completion comprises the production tubing 106, which is stung into the lower completion by means of a seal stinger assembly 107. A sealing arrangement 108 comprising a barrier 114 according to the present invention is installed below the production packer 109. In the top of the well, the tubing 106 is terminated in the wellhead 110. The completion design may vary significantly from what is shown in FIG. 1, and there are common completion components that are not illustrated herein, such as a downhole safety valve. These facts will be appreciated by a person skilled in the art. Similarly, the device according to the present invention can be used for other completion designs than what is shown herein, and FIG. 1 provides an example only,

When running the completion in the hole, the production parker 109 is not activated, as illustrated in FIG. 1a.

The centerline 115 of the tubular is illustrated for reference.

Now considering FIG. 1b, a pump 111 is put in fluid communication with the wellhead 110. In order to set the production packer 109, meaning to expand the mechanical anchors and seal elements to engage with the casing 102, the pump 111 is used to apply high pressure to the fluid inside the tubing 106. This is possible due to the sealed enclosure formed by the tubing 106, the sealing arrangement 108, the wellhead 110 and the pump 111. After setting the packer 109, the barrier 114 is no longer required in the well. The next step is to remove the barrier 114 so that the well can be put on production or injection.

To remove the barrier 114, the fluid inside the tubing 106 is pressure-cycled described earlier in this document, using the pump 111. For each complete pressure cycle, a mechanical cycle open mechanism 112 is operated one step. After a certain number of steps, the mechanical cycle open mechanism 112 will interact with an activation module 113 that triggers the opening and/or removal of the barrier 114. In summary, after a certain number of cycles, i.e. pressurizing and de-pressurizing the tubing fluid, the barrier 114 opens. FIG. 1c illustrates the well completion after the barrier 114 has been removed.

FIG. 2 illustrates one potential location of a mechanical cycle open mechanism 112 in a well completion. Here, a side pocket mandrel 201 housing the mechanical cycle open mechanism 112 forms an integral part of the tubing 106. When pressurizing the tubing, the internal tubing pressure will be exposed to and operate a piston member of the cycle open mechanism 112 as a result of fluids in piston chamber 202 being in fluid communication with the center of the tubing via port 203, When the cycle open mechanism 112 has finalized all the cycle steps and opened an internal pressure manifold, the working pressure to operate a related valve or other tooling (as explained in FIG. 1) is routed to said tooling via control line 204. In alternative embodiments, control line 204 could be replaced with drilled holes in side pocket mandrel 201, and the relevant tooling could also form an integral part of side pocket mandrel 201 or alternative housing design that houses cycle open mechanism 112. Such design features will he known to a person skilled in the art and not further referred to herein.

FIG. 3 illustrates details of a mechanical cycle open mechanism 112 as per prior art. Only a selected section of the side pocket mandrel 201 is shown. Relation to the tubing 105 geometry is illustrated via centre line 115.

The cycle open mechanism of FIG. 3 comprises an outer housing 301 with outer seals 302a, 302b in top and bottom. Moreover, the outer housing 301 includes a fixed retch 303 section. The main moving member of cycle open mechanism 112 is the piston 304 comprising piston seal 305 and dynamic retch 306.

In the described embodiment, the piston 304 is hollow, with center channel 307 running through it in the longitudinal direction. The piston chamber 202, being in fluid contact with center channel 307, is sealed off from the cavity 308 of cycle open mechanism 112 by means of bottom plug 309 and seal mandrel 310 interacting with mandrel seals 311a, 311b. In a preferred embodiment, cavity 308 contains a compressible fluid in order to provide piston 304 with the necessary degrees of freedom to operate. Seal mandrel 310 is secured to piston 304 with shear pins 312 to provide for mechanical stability, and avoid that seal mandrel 310 moves preliminary versus piston 304 due to vibrations or shock experienced when deploying the system into the wellbore.

In the bottom, piston 304 is terminated in a flange 313, having perforations 314. A spring 315 is iodated below flange 313, the lower end of the spring 315 being supported by the lower section/flange of outer housing 301.

A traveling member 316 is initially placed in an upper position of cavity 308, between the fixed retch 303 and dynamic retch 305 as illustrated in the figure. The cycle open mechanism 112 is now in its starting position.

In a preferred embodiment, the spring 315 is pretensioned and will not become compressed until the pressure inside piston chamber 202 exceeds a predefined value.

The stop edges 317 of the outer housing 301 allows for pretensioning the spring without the piston 304 being pushed out of the outer housing 301.

The control line 204, attached to the side pocket mandrel 201 by fastening nut 318 is also illustrated. The seal systems for forming a seal between side pocket mandrel 201 and control line 204 are known to those skilled in the art and not illustrated herein.

FIG. 4 a illustrates the first step of operating the cycle open mechanism 112 to open. Here, the tubing 106 is pressurized so that high pressure is exposed to the piston 304 as illustrated by the arrows 401, 402.

When the tubing pressure exceeds the relevant level, the piston 304 starts to move (this level can be set by pre-compressing the spring 315, or pre-pressurizing cavity 308 to a given set-pressure or a combination of both). FIG. 4a illustrates a situation where the the piston is moved down a distance slightly exceeding the length of one step of the fixed ratch 303. In a real life embodiment, there would be a stop edge to limit the maximum allowed travel of the piston 304, however such would be known to a person skilled in the art and not illustrated herein.

The traveling member 316 is typically made in a fashion where it has a radial spring-functionality, allowing it to be compressed radially when travelling down. Moreover, the traveling member 316 radially opens in the upper and as per the illustration. This design allows the traveling member to be pushed downwards in the mechanism, but prevents upward movement across the edge of a ratch unit.

FIG. 4 b illustrates the first bleed down sequence after the first step of pressurising the tubing 106. In the absence of high pressure in the piston chamber 202, the spring 315 will push the piston 304 back to its upper position. The travelling member will not be able to move upwards due to its interaction with the fixed ratch 303, hence it remains in a position one step further down the fixed ratch. However, the dynamic ratch 306, hence piston 304, will not be locked from moving up versus the travelling member 316.

Further to normal industry definition, FIGS. 4a and 4b has illustrated what is normally referred to as one cycle of the mechanical cycle system 112.

FIG. 4 c illustrates the situation after the travelling member 316 has been cycled to a position where the next full cycle entails interaction with the seal mandrel 310. When pressurizing and bleeding down the tubing the next time, the travelling member 316 will be located between the bottom of the fixed retch and the top of the seal mandrel 310. When bleeding down the tubing 106 pressure, the spring force will cause the shear pins 312 to shear, whereupon the seal mandrel 310 is shifted downwards with respect to the piston 304. This is illustrated in FIG. 4d.

At this stage, there is fluid communication between the internals of the tubing 106 and the cavity 308, and high pressure fluids will be avowed to flow down control line 204 to activate the associated tooling (valve, barrier, etc).

FIG. 5 and FIG. 6 illustrates annular designs of the same prior art, as an alternative to a side pocket design, but instead of a side pocked mandrel 201, an annular mandrel 501 is used. Also, rather than a control line 204, a drilled hole 502 is illustrated as the route for the high pressurized fluids to flow from the cycle open mechanism 112 to associated tooling to be operated.

A significant problem with the prior art design cycle open mechanisms is that debris inside the wellbore entail a significant potential for jamming the system, Further to the explanation provided in FIGS. 2-6: During repeated pressure cycles required to move the travelling member 316 to the stage where it interacts with the seal mandrel 310, well fluids and whatever debris and impurities there is, is cycled in and out of the piston chamber 202 via port 203. When entering piston chamber 202 via port 203, the impure well fluid experiences a transition from high flow velocity when in the port 203 to a slower velocity when inside the piston chamber 202. Moreover, the operation of piston 304 also entails a need for up to several 90 degree changes in flow direction, Such flow patterns entail a potential for making particles or low viscosity agents to leave the fluid solution and settle inside piston chamber 202. Moreover, because of the geometrical enclosures defining piston chamber 202, any particles entering piston chamber 202, whether forced to settle out of the fluid solution or not, face the risk of getting trapped inside piston chamber 202. Should the local area of the well contain larger amounts of debris and other impurities, there is a risk that the piston chamber 202 is filled with so much debris that the cycle open system 112 will malfunction. One failure mode that is immediately perceivable is that the piston chamber 202 is so filled with debris that the spring 315 is unable to bring the piston 304 back to its starting position after having pressurized and then de-pressurised the tubing 106 pressure. When such a situation happens, the dynamic ratch 306 is unable to re-engage with the travelling member 316, hence the sequential movement of this will halt.

FIG. 7 a illustrates an embodiment of a cycle open mechanism 112 according to the present invention. In the embodiment shown, the piston chamber 202 and associated port 203 shown in the prior art FIGS. 2-6 are removed and replaced with an open geometry cavity shown in the form of a recess 701 in the annular mandrel 501. The cavity is defined by a first portion 705, a second portion 709 and a side portion 707 bridging said first portion 705 and second portion 709. In the embodiment shown in FIG. 7a the second portion 709 includes the surface of the piston 304 and the first portion 705 is inclined upwards from the side portion 707 of the annular mandrel 501 towards the wellbore centerline 115. A part of the second portion 709 is inclined downwards in a direction towards the wellbore centerline 115. Thus, in the embodiment shown the first portion 705 is inclined away from the second portion 709. By means, the potential for particles leaving the fluid solution due to centrifugal or other flow related forces will be removed or at least considerably reduced. Moreover, design features that carry the potential to trap particles and prevent return of the piston 304 are eliminated. Also shown in FIG. 7a is a top scraper ring 702 mounted on the piston 304 to prevent impurities from entering the micro annuli between the piston 304 and the fixed mandrel. Such impurities could be a factor contributing to system jamming in system designed as per prior art.

FIG. 7 b illustrates an alternative to the embodiment shown in FIG. 7a. In FIG. 7b a skirt section 703 forms part of annular mandrel 501. The reason for including the skirt section 703 may be to protect the piston 304 from falling objects, or to limit the exposure of the recess 701 towards the internals of the tubing to avoid potential conflict of interest with future well service tasks, for example the intervention of service toolstrings that carries the risks of said service toolstrings getting caught in the recess 701 should this be of a too open geometry. Further to the embodiment illustrated in FIG. 7b, the skirt section 703 may be provided with fluid communication channels 704 to provide increased ventilation and/or circulation when operating/pressure cycling the system, to minimize the risk of debris getting caught. In one embodiment, the fluid communication channels are of a different and far more open geometry than illustrated in FIG. 7b. The cavity 701 is in the embodiment shown in FIG. 7b defined by a first portion 705, a second portion 709, a side portion 707 as described above with regards to FIG. 7a, and also the skirt section 703.

In an alternative embodiment (not shown) the fluid communication channel 704 is inclined with respect to the wellbore centerline 115. Said inclined communication channel may provide an “extension” of the inclined first portion 705 of the recess 701,

FIG. 8 a illustrates an alternative embodiment further to the invention. Here the piston 304 is not in direct communication with the tubing fluid. Instead, the ring-shaped piston 304 has smaller, rod-shaped pistons 801 attached to it, the rod-shaped pistons protruding through bores in the annular mandrel 501, into a recess 701 (see FIG. 7a) that is in fluid communication with the inside of the tubing. The rod-shaped pistons 801 open for even further design features that could be incorporated;

• • The scraper ring 702 could be replaced with a scraper cap (not illustrated), mounded in the tip of the rod-shaped pistons 801. This would essentially remove all possibilities for galling due to particles entering the micro annulus between the rod-shaped pistons 801 and the annular mandrel 501.
  • The rod-shaped pistons 801 could have a cut in the tip, in a certain angle or shape that is allowing for the piston to “dig” its way through even high-viscous debris slurries.
  • By adding removing rod-shaped pistons 801, the effective piston area of the cycle open mechanism 112 can be altered; this could be an efficient method for adjusting the system to higher/lower well pressure conditions. Rather than changing spring parameters dramatically, the number of rod-shaped pistons 801 is changed instead.

The cavity 701 is in the embodiment shown in FIG. 8a defined by a first portion 705, a second portion 709, a side portion 707 as described above with regards to FIG. 7a.

FIG. 8 b illustrates the scraper ring 702 of FIG. 8a being replaced with a scraper cap 702′, mounded in the tip of the rod-shaped pistons 801. Said scraper cap 702′ could be made of Teflon® or similar, PEEK or other suitable material. The main reason for using such a scraper cap 702′ is to minimize the radial gap between the piston 801 and the conduit/cylinder surrounding the piston 801. Scraper rings or scraper caps made in somewhat flexible materials as mentioned allow for a very small radial clearance (tolerance), hence minimizing the risk of debris entering the area along the piston rod, hence minimizing the risk of the piston galling and getting stuck in a fixed position.

FIG. 9 further exemplifies the use of three rod-shaped pistons 801 shown in cut A-A on FIGS. 8a and 8b, it will be apparent to those skilled in the art that the number of fluid pressure transition elements 801 may be more than or less than the three shown in FIG. 9 and that the force acting on the piston 304 shown in FIG. 8a and 8b depends on the total surface area of the rod(s) exposed to the fluid. Hence, in order to provide possibilities for altering the total surface area of the rod-shaped pistons 801 acting on the piston 304, the mandrel body 501 may be provided with a relatively high number bores arranged for receiving rod-shaped pistons 801. Any bore(s) not utilized in a specific embodiment must be sealed by means of a sealing element(s) so that the piston 304 is isolated from the fluid. Such a sealing element is not shown, but may be e.g. a cap.

Claims

1. A mandrel arrangement for use in a wellbore tubing, the arrangement comprising: a mandrel body housing at least one piston, the at least one piston being movable in relation to the mandrel body between a first position and a second position by a fluid force acting on the piston; anda cavity arranged adjacent the piston for communicating wellbore fluid pressure between the wellbore tubing, and the piston, wherein the cavity is provided with drainage means comprising an opening arranged for communicating fluid between the cavity and the wellbore tubing, thereby facilitating removal of any particles present in at least a lower portion of the cavity.

2. The mandrel arrangement according to claim 1, wherein the opening is inclined downwards in a direction from the cavity towards a wellbore centerline.

3. The mandrel, arrangement according to claim 1, wherein the cavity is a recess open to the wellbore fluid, the recess being defined by a tint portion, a second portion, and as side portion bridging said first portion and second portion, the second portion including the surface of the piston or a fluid pressure transition element extending from the cavity to the piston.

4. The mandrel arrangement according to claim 3, wherein the first portion of the recess is inclined away from the second portion in a direction from the side portion of the recess towards the wellbore centerline.

5. The mandrel arrangement according to claim 3, wherein the second portion of the recess is provided with a surface inclined away from the first portion in a direction towards the wellbore centerline.

6. The mandrel arrangement according to claim 1, wherein the mandrel body comprises an outer mandrel portion and an inner mandrel portion, the inner mandrel portion facing the fluid in the wellbore, and wherein the piston is arranged between the outer mandrel portion and the inner mandrel portion.

7. The mandrel arrangement according to claim 1, wherein the piston is provided with sealing means arranged for sealing off an annulus between the piston and the mandrel body.

8. The mandrel arrangement according to claim 1, wherein the piston is provided with a scraper ring arranged for sealing off an annulus between the piston and the mandrel body in order to prevent impurities from entering between the piston or the fluid pressure transition element(s) and the fixed mandrel body.

9. The mandrel arrangement according to claim 3, wherein the at least one thud pressure transition element is provided with a scraper cap facing the fluid in the cavity.

10. A method for facilitating operation of a mandrel arrangement for use in a. wellbore tubing, wherein the arrangement comprises: a mandrel body housing at least one piston, the at least one piston being movable in relation to the mandrel body between a first position and a second position by a fluid force acting on the piston; and a cavity arranged adjacent the piston for communicating wellbore fluid, pressure between the wellbore tubing and the piston, the method comprising providing the cavity with drainage means flowing removal of any particles present in at least a lower portion of the cavity.

11. The method according to claim 10, further comprising moving the piston by means of at least one fluid pressure transition element extending between the cavity and the piston.

12. The method according to claim 11, further comprising adjusting the three from the fluid acting on the piston by adding or removing the number of fluid pressure transition elements extending between the cavity and the piston.