Patent Description:
The necessity of extracting a fluid from a subterranean location is well known. In particular the extraction of water, oil and other fluids through a borehole is widely utilised. Boreholes are generally drilled into the ground in order to access subterranean fluid deposits. Depths of boreholes may therefore vary from a few metres to tens of thousands of meters depending on the depth of the fluid deposit. Wellbore systems often include a borehole drilled for the purpose of fluid extraction. These can include one or more downhole tubing arrangements extending into the borehole. Often more than one downhole tubing arrangement is utilised. Conventionally the outer circumference of the borehole is lined with securing material, often concrete, including perforations which allow fluid to ingress into the borehole from fluid deposits at least partially surrounding a portion of the borehole. The space between the tubing arrangement and the borehole lining provides an annulus which can permit fluid flow within the bore. A tubing bore defined by and within the tubing arrangement also provides a passageway for fluid flow and is often the fluid passageway through which fluid is extracted from downhole regions of the borehole. This is particularly useful in a wellbore system that requires artificial lift. The wellbore is often capped by further production apparatus which, particularly in oil and gas production applications, is a wellhead apparatus. In subsea wellbore systems, the wellhead apparatus is often a subsea tree.

Wellbore systems may contain substantial internal pressure such that a desired fluid is ejected from the subterranean location and through the borehole or tubing bore naturally. Often though it is necessary to artificially provide lift to the wellbore system to extract the fluid from downhole regions of the borehole. In fact, most wellbore systems will require a degree of artificial lift at some point in their production lifetimes. Many methods of providing artificial lift are known in the art and the utilisation of a particular method largely depends on its suitability for a particular wellbore system, particularly considering the environment of the wellbore system, and the degree of lift required. One such method with particular relevance to both on land and subsea wellbore applications involves the use of one or more Electric Submersible Pumps (ESPs).

An ESP is a downhole device used to artificially generate lift at a subterranean location and is used particularly in oil and water production applications. ESPs are generally positioned in a borehole as part of/within the downhole tubing arrangement. ESPs are often centrifugal pumps (which may be multistage centrifugal pumps) and therefore include an impeller (or a series of impellers) which rotates to move fluid up the tubing arrangement. An ESP is generally located in a section of the tubing arrangement directly above one or more inlet ports and towards the downhole-most end of a particular tubing arrangement. The rotating impeller of the ESP thereby imparts a pressure differential across the tubing section such that fluid is drawn into the tubing arrangement from the annulus via the inlet port and fluid in the tubing arrangement is moved towards the surface of the borehole. As fluid is drawn into the tubing further fluid from the fluid deposits may ingress into the annulus via the borehole perforations.

There may be instances which require the ESP to be switched off. Examples of such occasions include instances wherein artificial lift is not required (either due to the natural pressure of the wellbore system being sufficient for fluid extraction through the borehole/tubing arrangement or during a lapse in fluid production of the wellbore system) and instances wherein maintenance of the ESP or other apparatus (downhole or otherwise) is required. Conventionally reduced lift due to switching off the ESP can result in fluid inside the tubing arrangement falling towards a downhole tubing end under gravity or other such mechanisms. Fluid in the tubing arrangement above the ESP can therefore fall through the ESP in the absence of lift thereby forcing the impeller to rotate in a direction opposed to its intended direction of operation. This forced rotation may cause damage to the ESP which can be costly and time consuming to repair and can render the whole wellbore system inactive for a period of time thereby incurring further substantial costs and profit loss. Subterranean fluids such as oil can also carry a wide variety of debris such as rock particulates and sand and the like, particularly in a wellbore system wherein a borehole has been drilled. This debris can enter the ESP causing significant damage and can form plugs/blockages in the tubing arrangement above the ESP thereby reducing function of the wellbore system or rendering it inactive.

Tubing drain valve apparatus are known in the art. Generally tubing drain valves are located in a portion of the downhole tubing arrangement between a first fluid communication region at a substantially downhole location and within the tubing arrangement and a further fluid communication region within the tubing arrangement at a downhole location that is further towards the surface relative to the first fluid communication. Tubing drain valves are intended to operate to inhibit fluid communication between the first and further fluid communication regions (thereby inhibiting fluid trapped above the ESP in the tubing falling through the ESP) while provide a lateral port/draining passageway into the annulus (thereby allowing fluid trapped inside the tubing proximate to the further fluid communication region to drain into the annulus). Tubing drain valves are also intended to operate to connect the first fluid communication region and the further fluid communication region when lift is provided by the ESP while closing the lateral port/draining passageway to the annulus thereby allowing fluid extraction through the tubing arrangement.

Conventional tubing drain valves are limited to use in particular wellbore systems. In particular, it is desirable in some wellbore systems to allow fluid to flow into the tubing arrangement from the annulus via the lateral port/draining passageway. Some examples of these wellbore systems are free flowing wells and dual-completion systems. Dual-completion systems are wellbore systems in which fluid can be extracted from two fluid deposits simultaneously and often contain more than one tubing arrangement. Dual-completion systems have become a relatively common wellbore system in recent years. However, it has been found that some conventional tubing drain valves are not suitable for use in some free flowing or dual-completion or similar wellbore systems. In particular, it has been found that a fluid pressure in the annulus can result in the closing of the lateral port/draining passageway and connecting the first and further fluid communication regions thereby forcing fluid through the ESP. In some conventional systems this annular fluid pressure has been found to be around <NUM> - <NUM> psi however it will be understood that this pressure may vary significantly between systems. This results in reduced production and an inability to implement such tubing drain valves in some free flowing or dual-completion or similar wellbore systems.

It is an aim of the present invention to at least partly mitigate one or more of the above-mentioned problems.

It is an aim of certain embodiments of the present invention to selectively connect a first fluid communication region in a tubing bore to a further fluid communication region in a tubing bore.

It is an aim of certain embodiments of the present invention to provide a tubing drain valve suitable for dual-completion wellbore systems and /or wellbore systems with adequate natural lift and/or any wellbore system in which fluid from an annulus flows into the tubing bore in the absence of artificial lift such as when the ESP is shutdown.

It is an aim of certain embodiments of the present invention to provide a tubing drain valve in which at least one biasing element, which optionally is at least one magnet, determines a particular threshold pressure, which optionally is around <NUM> psi, which must be overcome by a fluid pressure proximate to a first fluid communication region in the tubing bore to connect the first fluid communication region to a further fluid communication region in the tubing bore.

It is an aim of certain embodiments of the present invention to provide a tubing drain valve comprising at least one biasing element, which optionally is at least one magnet, that does not include frictional components or introduce substantial friction to the tubing drain valve.

It is an aim of certain embodiments of the present invention to provide apparatus comprising at least one lateral port being open to an annulus and a biasing element, which optionally is at least one magnet, wherein the biasing element determines a threshold pressure, which optionally is around <NUM> psi, which must be overcome by a fluid pressure proximate to a first fluid communication region in the tubing bore to close the lateral port to the annulus.

<CIT> discloses methods and apparatus for utilizing a valve with a pump rotor passage with a downhole production string, the pump rotor being on a rotatable rod with a bobbin moving along the rod between a position for opening the passage to fluid flow, when the bobbin is not seated on a shuttle seat, and a position for closing the passage to fluid flow, when the bobbin is seated on the shuttle seat. The pump rotor and rod are removable through the passage while leaving the pump stator in place upstream of the valve.

<CIT> discloses a tubing drain valve in a production tubing string, positioned above a pump, operated to open drain ports in the housing for draining produced fluids from the production tubing when the pump is shut off. The drain valve incorporates a check valve assembly which is freely moveable within the drain valve to shift a sleeve to open and close the drain ports.

<CIT> discloses a fluid flow control device, which may be particularly useful for controlling flow of fluid in a hydrocarbon production tubing and which includes a body member, preferably in the form of a cylindrical tube having a throughbore formed therein. The throughbore is arranged into first and second throughbore portions where there is at least one bypass port formed in the body member. The device also includes a moveable member which may be in the form of a sleeve which is moveable between a first configuration which defines a first fluid flow path between the first and second throughbore portions and a second configuration which defines a second fluid flow path between the first throughbore portion and the bypass port(s).

<CIT> discloses a drain-back check valve assembly including a body having a passageway with an inlet and an outlet. A bypass port extends from the passageway to an outer surface of the valve body. A main poppet valve assembly is disposed in the passageway and moveable between a closed position which prevents fluid flow from the outlet to the inlet and an open position which allows fluid flow from the inlet to the outlet.

According to a first aspect of the present invention there is provided apparatus for selectively connecting a first fluid communication region to a further fluid communication region at a downhole location, comprising:.

Aptly in a first mode of operation, the sheath member is biased towards the first end portion and the shuttle member is disposed in a first position providing a sealed relationship with the sheath member;.

Aptly the housing comprises at least one first lateral port that are each proximate to the further fluid communication region; and.

Aptly the apparatus further comprises a sleeve member axially slidable within the housing and disposed between the housing and the shuttle member, wherein the sleeve member is disposed to at least partially leave open the first lateral port in the first mode of operation, and the sleeve member is disposed to close the first lateral port in the intermediate and further mode of operation.

Aptly the biasing element comprises at least one magnetic element and optionally the housing comprises a seat in which the magnetic element is disposed; wherein
the seat provides an abutment surface against which the sheath member abuts in the first mode of operation to thereby set one extent of axial movement of the sheath member.

Aptly the biasing element is at least partially covered by protective cladding.

Aptly said a fluid pressure is determined by operation of an Electric Submersible Pump (ESP) locatable at or proximate to the first fluid communication region.

Aptly the apparatus further comprises at least one further biasing element to bias the sheath member, the shuttle member and optionally the sleeve member towards the first fluid communication region, and wherein optionally the further biasing element is a spring.

Aptly the apparatus further comprises at least one catch element on an inner surface of the housing disposed to prevent the sheath member, and optionally the sleeve member, from axially moving towards the further fluid communication region, or optionally towards the first fluid communication region, beyond a predetermined distance.

Aptly the housing, sheath member and shuttle member are installed in multi-pump or dual completion system within a wellbore.

According to a second aspect of the present invention there is provided a method of selectively connecting a first fluid communication region to a further fluid communication region at a downhole location, comprising:.

Aptly the method further comprises axially moving the shuttle member and the sheath member together away from the first fluid communication region or towards the further fluid communication region when the fluid pressure exceeds the threshold pressure; and
axially moving the shuttle member independently of the sheath member away from the first fluid communication region or towards the further fluid communication region when the sheath member is axially moved to a predetermined distance away from the first fluid communication region or towards a further fluid communication region.

Aptly the method further comprises providing at least one catch element that determines a predetermined distance that the sheath member is axially movable away from the first fluid communication region or towards the further fluid communication region.

Aptly the housing includes at least one first lateral port proximate to the further fluid communication region and the shuttle member includes at least one further lateral port locatable in an at least partially aligned relationship with the first lateral port, the method further comprising:
axially moving the shuttle member away from the first fluid communication region or towards the further fluid communication region such that the first lateral port and the further lateral port are axially non-aligned.

Aptly the housing includes a sleeve member axially slidable within the housing and disposed between the housing and the shuttle member such that the sleeve member is disposed to leave the first lateral port at least partially open, the method further comprising:
axially moving the sleeve member away from the first fluid communication region or towards the further fluid communication region such that the sleeve member is disposed to close the first lateral port.

Aptly the method further comprises providing a biasing element that comprises at least one magnetic element.

Aptly the method further comprises providing at least one further biasing element to bias the sheath member, the shuttle member and optionally the sleeve member towards the first fluid communication region, and wherein optionally the further biasing element is a spring.

Aptly the method further comprises providing an ESP at or proximate to the first fluid communication region which can be operated to determine the fluid pressure.

Aptly the method further comprises providing a dual-completion system within the wellbore.

Certain embodiments of the present invention provide a tubing drain valve suitable for use in a dual-completion wellbore system and/or wellbore system with substantial natural lift such that artificial lift is not required.

Certain embodiments of the present invention provide ESP protection against the backflow of fluid in a tubing arrangement or from unintentional forced fluid flow through the ESP, particularly when the fluid contains particulate matter, thereby reducing maintenance costs and lost profit due to inactivity of fluid extraction.

Certain embodiments of the present invention provide a tubing drain valve that requires a predetermined threshold pressure to be exceeded by a fluid pressure of a fluid at/proximate to a first fluid communication region to connect the first fluid communication region with a further fluid communication region thereby providing greater control over selective connection of the first and further fluid communication regions.

Certain embodiments of the present invention provide a tubing drain valve wherein pressure fluctuations in the wellbore system, particularly in the annulus and/or tubing arrangement, do not limit fluid flow between the annulus and the tubing bore through the lateral port until a predetermined threshold pressure is exceed by a fluid pressure of a fluid at/proximate to the first fluid communication region.

Certain embodiments of the present invention provide a tubing drain valve including lateral ports, selectively connecting the tubing bore to the annulus, which do not prematurely disconnect the tubing bore from the annulus responsive to variable pressures in the annulus.

Certain embodiments of the present invention will now be described hereinafter, by way of example only, with reference to the accompanying drawings in which:.

<FIG> illustrates how a system for generating artificial lift can be implemented in a wellbore system <NUM> for aiding in the extraction of oil or other such fluids from a subterranean location through a borehole <NUM>. It will be understood that such a system can be implemented on land or at a subsea location. At least one tubing arrangement <NUM> is located vertically inside a borehole such that the tubing arrangement extends significantly into the ground <NUM> and at least to a fluid deposit <NUM>. In the wellbore system illustrated in <FIG>, two tubing arrangements are located in series in a dual-completion system. The tubing arrangement <NUM> provides a tubing bore which defines a fluid communication pathway within the tubing arrangement <NUM>. The tubing arrangement <NUM> also provides an annulus <NUM> as a space between the tubing arrangement <NUM> and the inner circumference of the borehole <NUM> which defines an annular fluid flow passage. A section of the tubing arrangement <NUM> provides a tubing drain valve <NUM> which acts to selectively connect a first fluid communication region <NUM> located within the tubing arrangement at a subterranean location at the fluid deposit <NUM> to a further fluid communication region <NUM> located within the tubing arrangement and vertically above the first fluid communication region <NUM> (closer to the surface of the borehole <NUM>). The tubing arrangement comprises at least one inlet port <NUM> relatively proximate to the first fluid communication region <NUM>. In the tubing arrangement illustrated a ring of inlet ports <NUM> extend circumferentially around the body of the tubing arrangement.

Fluid from the fluid deposit <NUM> can ingress into the borehole <NUM> through perforations <NUM> in the borehole circumferential surface. Optionally this fluid is oil. Optionally this fluid is hydrocarbon. Optionally this fluid is water. Optionally this fluid is any other suitable fluid or combination of fluids and particulate matter. It will be understood that the borehole is often lined with a structurally supportive material which intentionally includes the perforations <NUM>. Optionally this material is concrete. Optionally this material is any other suitable material. Optionally the borehole comprises no lining. Fluid in the borehole <NUM> from the fluid deposit <NUM> can enter the tubing through the inlet port <NUM>. An Electric Submersible Pump (ESP) <NUM> is located in the tubing arrangement <NUM> above the inlet port <NUM>. The ESP <NUM> includes an impeller which rotates to move the fluid up the tubing arrangement <NUM> thereby generating lift in the wellbore system <NUM>. As the impeller rotates and moved fluid through the ESP, a local pressure differential is generated across the ESP. This pressure differential results in further fluid being drawn into the tubing arrangement from the borehole <NUM> via the inlet port <NUM> to replace fluid moved upwards by the impeller. A motor <NUM> associated with the ESP <NUM> is located below the inlet port <NUM> and optionally a seal is provided between the inlet port <NUM> and the motor <NUM>. A sensor <NUM> is optionally located at the downhole terminal end of the tubing arrangement <NUM>.

The tubing drain valve <NUM> is located between the first fluid communication region <NUM> and the further fluid communication region <NUM>. The tubing drain valve <NUM> can selectively connect the first fluid communication region <NUM> and the further fluid communication region <NUM> responsive to a fluid pressure at the first fluid communication region <NUM>. The tubing drain valve <NUM> further comprises at least one lateral port <NUM> which selectively opens the tubing bore within the tubing drain valve <NUM> region of the tubing arrangement <NUM> to the annulus <NUM>. In the tubing arrangement illustrated a ring of lateral ports <NUM> extend circumferentially around the body of the tubing arrangement. This allows for the draining of fluid within the tubing bore above the tubing drain valve to the annulus <NUM> in the absence of lift in the wellbore system <NUM>. This also allows for the ingress of fluid from the annulus <NUM> into the tubing bore when where required. Closing the tubing bore to the annulus <NUM> via the lateral ports allows for fluid flow from the inlet port <NUM> to the upper terminus of the tubing arrangement <NUM> when lift is provided by the ESP <NUM>.

<FIG> illustrates a cross-section of a tubing drain valve in a first mode of operation <NUM>. <FIG> illustrate enlarged versions of the section of <FIG> contained within the upper dashed-line box and the lower dashed-line box respectively. As illustrated in <FIG>, the tubing drain valve <NUM> provides a section of the tubing arrangement <NUM>, which provides a fluid communication pathway, between the first fluid communication region <NUM> and the further fluid communication region <NUM>. The section of tubing enclosing the tubing drain valve <NUM> provides an elongate housing <NUM> which comprises a first end portion <NUM> associated with the first fluid communication region <NUM>. Optionally the housing <NUM> is made of a rigid material. Optionally this material is steel or some other suitable metal, alloy or composite. Optionally this material is any other suitable material. Optionally the housing <NUM> is manufactured as a single part. Optionally the housing <NUM> comprises multiple parts which are locked/joined together. The housing <NUM> comprises at least one first lateral port <NUM> proximate to the further fluid communication region <NUM>, the first lateral port <NUM> being open to the borehole <NUM>. The housing illustrated comprises a ring of first lateral ports arranged circumferentially. As illustrated in <FIG>, the space between the tubing arrangement <NUM> and the circumferential edge of the borehole <NUM> provides an annulus <NUM>. The annulus <NUM> is in fluid communication with the first lateral port <NUM>.

Located within the housing <NUM> is an elongate shuttle member <NUM> that is movable as an axially slidable member within the housing <NUM>. The shuttle member <NUM> comprises at least one further lateral port <NUM> proximate to the further fluid communication region <NUM> and a plug member <NUM> at a terminal end of the shuttle member <NUM> proximate to the first fluid communication region <NUM>. The shuttle member illustrated comprises a ring of first lateral ports arranged circumferentially. A sheath member <NUM> located within the housing <NUM> and is movable as an axially slidable member within the housing <NUM>. The sheath member <NUM> is arranged to provide a reduced internal diameter of the tubing bore into which the plug member <NUM> can intrude thereby forming a sealed relationship between the shuttle member <NUM> and the sheath member <NUM>. Optionally the plug member comprises sealing rings comprised of polymeric material or any other suitable material to ensure complete fluid sealing between the plug member <NUM> and the sheath member <NUM>. Optionally the sheath member comprises sealing rings composed of polymeric material or any other suitable material to ensure complete fluid sealing between the plug member and the sheath member. Optionally the shuttle member <NUM> and/or the sheath member <NUM> are composed of a rigid material. Optionally this material is steel or some other suitable metal, alloy or composite. Optionally this material is any other suitable material.

In the first mode of operation of the tubing drain valve <NUM>, the first lateral ports <NUM> and the further lateral ports <NUM> are at least partially arranged in an aligned relationship, which is determined by the relative position of the shuttle member <NUM> to the housing <NUM>. A sleeve member <NUM> is located between the shuttle member and the housing <NUM>. The sleeve member <NUM> is movable as an axially slidable member within the housing <NUM>. Optionally the sleeve member <NUM> is composed of a rigid material. Optionally this material is steel or some other suitable metal, alloy or composite. Optionally this material is any other suitable material. In the first mode of operation of the tubing drain valve <NUM>, the sleeve member <NUM> is disposed to ensure that the first lateral ports <NUM> are at least partly open to the annulus <NUM> by being located at a maximum axial displacement towards the first fluid communication region <NUM>.

The housing comprises a seat <NUM> on its internal surface proximate to the first fluid communication region. The seat provides an abutment surface on which a downhole-facing surface of the sheath member <NUM> abuts in the first mode of operation. The seat <NUM> comprises at least one biasing element <NUM> configured to bias the sheath member <NUM> towards the first fluid communication region <NUM> such that the sheath member <NUM> abuts and remains abutted against the seat <NUM>. The tubing drain valve <NUM> illustrated comprises a biasing element <NUM> that is a magnet. Optionally the biasing element is at least one magnet. Optionally the magnet is an array of magnets. Optionally the magnet or magnet array is configured to focus the magnetic field towards the abutting surface of the sheath member <NUM>. Optionally the biasing element <NUM> is at least partially surrounded by cladding <NUM> for the purpose of either protection or insulation. Optionally this cladding is formed of a polymeric material. Optionally the cladding is formed of polyether ether ketone (PEEK). Optionally this cladding is a nylon. Optionally this cladding is metallic. Optionally this cladding is formed of any other suitable material. As illustrated in <FIG>, the sheath member <NUM> may comprise an internal portion extending into the tubing bore beneath the seat <NUM> towards the first fluid communication region <NUM> which may aid in sealing.

The biasing element <NUM> provides a predetermined biasing force on the sheath member <NUM> thereby biasing the sheath member <NUM> towards the first fluid communication region <NUM> and ensuring its abutment against the seat <NUM>. It will be understood that the biasing force determines a threshold cracking force that must be applied directionally towards the further fluid communication region in order to separate the sheath member <NUM> from the seat <NUM>. The biasing element <NUM> is deliberately chosen in manufacturing to provide a particular cracking force. This cracking force can be provided by fluid pressure at the first fluid communication region <NUM> incident on the plug member <NUM>. In this way the cracking force, and therefore the choice of biasing element <NUM>, determines a threshold pressure that must be exceeded by a fluid at the first fluid communication region <NUM>. Optionally this threshold pressure is between <NUM> psi and <NUM> psi. Optionally this threshold pressure is around <NUM> psi.

It will be understood that the sheath member <NUM> can also include a biasing element which optionally is a magnet or a magnet array to provide further attraction between the sheath member <NUM> and the seat <NUM>. It will also be understood that the biasing element <NUM> can be incorporated into the sheath member <NUM> instead of the seat <NUM>.

The tubing drain valve <NUM> additionally comprises at least one further biasing element <NUM>, <NUM> which act to bias the shuttle member <NUM> towards the first fluid communication region <NUM>. The tubing drain valve <NUM> illustrated comprises two further biasing elements <NUM>, <NUM>. The further biasing elements <NUM>, <NUM> are springs which partially surround the shuttle member <NUM> at two positions within the housing <NUM>. Optionally these springs can abut against a number of flared out portions <NUM>, <NUM> of the shuttle member <NUM> thereby resisting motion of the shuttle member <NUM> towards the further fluid communication region <NUM>. One such flared out portion provides a locking ring <NUM>. Optionally a further flared out portion of the shuttle member <NUM> can abut against a further biasing element. Optionally the sleeve member abuts against a further biasing element <NUM>.

The locking ring <NUM> is a flared-out ring portion of the shuttle member <NUM> and comprises a recess <NUM> around its circumference. The sheath member <NUM> comprises at least one sheath collet <NUM> and the sleeve member comprises at least one sleeve collet <NUM>. As can be seen in <FIG>, in the first mode of operation of the tubing drain valve <NUM> the sheath collet <NUM> and the sleeve collet <NUM> intrude into the locking ring recess <NUM>. In the first mode of operation of the tubing drain valve <NUM>, the relative position of the shuttle member <NUM> and the housing <NUM> does not allow for the sheath collet <NUM> and the sleeve collet <NUM> to move out of the locking ring recess <NUM>. Therefore, the shuttle member <NUM>, the sheath member <NUM> and the sleeve member <NUM> are prohibited from moving independent of each other.

The first mode of operation of the tubing drain valve <NUM> disconnects the first fluid communication region <NUM> from the further fluid communication region <NUM> via the sealed relationship between the plug member <NUM> and the sheath member <NUM> whilst also determining a particular threshold pressure of fluid at the first fluid communication region <NUM> to permit connection of the first and further fluid communication regions thereby preventing unwanted connection of the first and further fluid communication regions until such a desired threshold pressure is achieved. The first mode of operation of the tubing drain valve <NUM> also provides axial alignment of the first lateral ports <NUM> and the further lateral ports <NUM> thereby allowing fluid communication between the annulus <NUM> and the tubing bore above the plug member <NUM> (including the further fluid communication region <NUM>). The portion of the tubing bore below the plug member remains in fluid communication with the annulus <NUM> via the inlet port <NUM>. The inability of the shuttle member <NUM>, the sheath member <NUM> and the sleeve member <NUM> to move independently of each other ensures the at least partial alignment of the first lateral ports <NUM> and the further lateral ports <NUM>, ensures that the first lateral ports <NUM> remains at least partially open to the annulus <NUM>, and ensures that the first fluid communication region <NUM> and the further fluid communication region <NUM> are disconnected via the sealed relationship between the sheath member <NUM> and the plug member <NUM>.

The first mode of operation of the tubing drain valve <NUM> corresponds to a situation in which the ESP <NUM> is switched off and no lift is thereby artificially introduced into a particular tubing arrangement <NUM> in a wellbore system <NUM>. If the ESP <NUM> is switched off due to certain requirement of the wellbore system, the first lateral port <NUM> and the further lateral port <NUM> remain open to the annulus <NUM> thereby allowing fluid to ingress into and out of the tubing bore via the first and further lateral ports. The first and further fluid communication regions remain disconnected as to limit forced fluid flow through the ESP <NUM>.

<FIG> illustrates a cross section of a tubing drain valve <NUM> in an intermediate mode of operation <NUM>. <FIG> illustrate enlarged versions of the section of <FIG> contained within the upper dashed-line box and the lower dashed-line box respectively. The intermediate mode of operation corresponds to a situation wherein the tubing drain valve was recently in the first mode of operation (<FIG>, <FIG>) and the ESP <NUM> has recently been switched on. The pressure of fluid at the first fluid communication region <NUM> has thereby recently exceeded the threshold pressure. The pressure of fluid acts on the base of the plug member <NUM> and in a direction towards the further fluid communication region <NUM>. The sheath member <NUM> and the seat <NUM> are thereby separated. The sheath member <NUM> and the shuttle member <NUM> are moved towards the further fluid communication region <NUM> relative their positions with respect to the housing <NUM> in the first mode of operation <NUM> of the tubing drain valve <NUM> (<FIG>, <FIG>) and remain in a sealing relationship. This is due to the sheath collet <NUM> being unable to escape from the locking ring recess <NUM> thereby prohibiting independent movement of the shuttle member <NUM> with respect of the sheath member <NUM>. The separation between the sheath member <NUM> and the seat <NUM> is thus achieved by axial sliding of the sheath member together with the shuttle member towards the further fluid communication region <NUM> responsive to the fluid pressure.

The axial sliding of the shuttle member <NUM> relative to the housing <NUM> results in an axial non-alignment of the first lateral ports <NUM> and the further lateral ports <NUM> thereby closing the annulus <NUM> to the section of tubing bore above the plug member <NUM> (including the further fluid communication region <NUM>). This results in a situation wherein the first and further fluid communication regions are disconnected via the sealing relationship between the plug member <NUM> and the sheath member <NUM> whilst the annulus <NUM> is simultaneously disconnected from the section of tubing bore above the plug member <NUM>. Therefore, fluid cannot ingress into/out of the section of tubing bore above the plug member <NUM> from/to the first fluid communication region <NUM> and simultaneously through the first and further lateral ports which, in the instance of ESP <NUM> shutdown for example, may damage or block the ESP <NUM>.

The axial movement of the shuttle member <NUM> towards the further fluid communication region <NUM> also results in equivalent movement of the sleeve member <NUM> due to the sleeve collet <NUM> being imprisoned in the locking ring <NUM>. In the intermediate mode of operation of the tubing drain valve <NUM> the sleeve member <NUM> is disposed to close the first lateral ports <NUM> to the annulus <NUM> to further ensure that the annulus is disconnected from the section of tubing bore above the plug member <NUM>. The sleeve member <NUM> moves with the shuttle member <NUM> until it abuts against an upper sleeve catch element <NUM> on the housing <NUM>. This position of the shuttle member <NUM> and the sleeve member <NUM> relative to the housing <NUM> allows the sleeve collet <NUM> to escape the locking ring recess <NUM> via a first collet recess <NUM> in the inner surface of the housing <NUM>. The shuttle member <NUM> comprises a lower sleeve catch element <NUM> which abuts against the sleeve member <NUM> when the shuttle member moves towards the first fluid communication region <NUM>, and therefore towards the first mode of operation <NUM> of the tubing drain valve <NUM>, thereby opening the first lateral port <NUM>.

The intermediate mode of operation <NUM> of the tubing drain valve <NUM> may correspond to an instance in which the ESP <NUM> is switched off and the tubing drain valve, previously in a further mode of operation <NUM> of the tubing drain valve <NUM> ( <FIG>, <FIG>), is returning to the first mode of operation <NUM> of the tubing drain valve <NUM> (<FIG>, <FIG>) under the influence of the biasing element <NUM> and/or the further biasing elements <NUM>, <NUM>. Fluid in the tubing arrangement <NUM> is therefore prevented from falling through the ESP <NUM>.

<FIG> illustrates a cross section of a tubing drain valve <NUM> in a further mode of operation <NUM>. <FIG> illustrate enlarged versions of the section of <FIG> contained within the upper dashed-line box and the lower dashed-line box respectively. In the further mode of operation <NUM> of the tubing drain valve <NUM> the first fluid communication region <NUM> is connected to the further fluid communication region <NUM>. This relates to a situation wherein the ESP <NUM> is switched on and the fluid pressure exceeds the threshold pressure thereby separating the sheath member <NUM> from the seat <NUM>. The sheath member <NUM> is located further towards the further fluid communication region <NUM> relative to its position with respect to the housing <NUM> in the intermediate mode of operation <NUM> and the first mode of operation <NUM> of the tubing drain valve <NUM> (by axially sliding together with the shuttle member <NUM>) and is at a maximum distance from the seat <NUM>. This distance or catch point <NUM> is determined by a catch element <NUM> located on the internal surface of the housing <NUM> which abuts against an upper surface of the sheath element <NUM>. The catch element <NUM> prevents the sheath member <NUM> from further axially sliding towards the further fluid communication region <NUM>, together with the shuttle member <NUM>, relative to the housing <NUM> responsive to the fluid pressure. Optionally this catch element <NUM> may also provide an abutment surface on which the locking ring of the shuttle member may abut in the first mode of operation <NUM> of the tubing drain valve <NUM> (<FIG>, <FIG>) which defines a maximum displacement of the shuttle member towards the first fluid communication region <NUM>. Locating the sheath member <NUM> at its maximum displacement towards the further fluid communication region <NUM>, such that the sheath member <NUM> abuts against the catch element <NUM>, allows the sheath collet <NUM> to escape the locking ring <NUM> into a further collet recess <NUM> in the inner surface of the housing <NUM>. The shuttle member <NUM> may then axially move independently of the sheath member <NUM> (and the sleeve member <NUM>).

Upon abutment of the sheath member <NUM> with the catch element <NUM> and release of the sheath collet <NUM> from the locking ring <NUM>, fluid pressure acting on the plug member <NUM> results in further axial sliding of the shuttle member <NUM> towards the further fluid communication region <NUM> relative to the sheath member <NUM> and the housing <NUM>. The further biasing elements <NUM>, <NUM> bias the shuttle member <NUM> towards the sheath member <NUM> and the first fluid communication region <NUM> however, the fluid pressure in the further mode of operation <NUM> of the tubing drain valve <NUM> is sufficient to further axially slide the shuttle member <NUM> towards the further fluid communication region <NUM> and away from the sheath member <NUM>. It will be understood that the two further biasing elements <NUM>, <NUM> illustrated in <FIG> are present in the intermediate mode of operation <NUM> and the further mode of operation <NUM> of the tubing drain valve <NUM> and are not shown in <FIG> for illustrative clarity only. The two further biasing elements <NUM>, <NUM> are springs.

This further sliding of the shuttle member locates the shuttle member <NUM> (and therefore the plug member <NUM>) in a non-sealing relationship with the sheath member <NUM> wherein the plug member <NUM> and the sheath member <NUM> are separated. The shuttle member <NUM> comprises at least one channel proximate to, or within, the plug member <NUM> through which fluid from the first communication region <NUM> can flow thereby connecting the first fluid communication region <NUM> and the further fluid communication region <NUM>. It will be understood that the channel <NUM> will be closed to the first fluid communication region <NUM> when the plug member <NUM> and the sheath member <NUM> are disposed in a sealed relationship. It will also be understood that further axial movement of the shuttle member <NUM> towards the further fluid communication region <NUM> relative to its position with respect to the housing in the intermediate mode of operation <NUM> of the tubing drain valve <NUM> (<FIG>, <FIG>) disposes the first lateral ports <NUM> and the further lateral ports <NUM> in a non-aligned relationship. The sleeve member <NUM> remains disposed to close the first lateral port <NUM> to the annulus.

Upon switching the ESP off, it will be understood that the further biasing elements <NUM>, <NUM> and/or the biasing element <NUM> will bias the sheath member to axially move towards the first fluid communication region to abut against the seat due to the reduced fluid pressure in the absence of artificial lift. Such a reduction in fluid pressure due to switching off the ESP will also result in the further biasing elements <NUM>, <NUM> biasing the shuttle member towards the first fluid communication region such that the shuttle member <NUM> returns to be in a sealing relationship with the sheath member <NUM> via the plug member <NUM>. Depending on the pressure drop and properties of the first and further biasing elements <NUM>, <NUM>, the tubing drain valve <NUM> may, for a short time period or instantaneously, return to the intermediate mode of operation <NUM> before returning to the first mode of operation <NUM> wherein the first and further fluid communication regions are disconnected. It will be understood that the sleeve collet <NUM> and the sheath collet <NUM> will return to in imprisoned state within the locking ring <NUM> in the absence of lift thereby ensuring that the sleeve member <NUM>, the sheath member <NUM> and the shuttle member cannot axially move independently once interlocked.

<FIG> illustrates a biasing assembly <NUM> that may be integrated into the housing <NUM> of the tubing drain valve <NUM>. The biasing assembly <NUM> is viewed along an axis that corresponds to the major axis of the tubing arrangement when installed. In particular, the biasing assembly <NUM> is integrated into the seat <NUM>. It will be understood that the biasing assembly <NUM> can optionally be included at a different position in the housing <NUM>. It will also be understood that biasing assembly <NUM> can be included in the sheath member <NUM>. The biasing assembly <NUM> comprises the biasing element <NUM>. The biasing element optionally comprises a magnet <NUM>. Optionally the magnet <NUM> is a ring-shaped magnet. Optionally the biasing element <NUM> can comprise segmented magnets arranged in a ring. Optionally the biasing element <NUM> can comprise multiple magnets arranged in any suitable configuration. Optionally the biasing element <NUM> can comprise any other suitable biasing device. Optionally, when installed in a tubing drain valve <NUM>, the magnet <NUM> provides a biasing force of between <NUM> N and <NUM> N on a sheath member <NUM>. Optionally, when installed in a tubing drain valve <NUM>, the magnet <NUM> provides a biasing force of around <NUM> N on a sheath member <NUM>. Optionally the biasing force decays so that at distances of less than a metre from the magnet the magnitude of the biasing force is significantly reduced. Optionally the biasing force decays so that at distances of around a few cm from the magnet the magnitude of biasing force is significantly reduced.

The biasing element <NUM> sits inside a ring-shaped pot <NUM>. The pot <NUM> comprises a cutaway region in which the biasing element <NUM> is positioned such that the biasing arrangement <NUM> is ring-like. Optionally the biasing element <NUM> is secured to the pot <NUM>. Optionally the biasing element <NUM> is secured to the pot by an adhesive. Optionally this adhesive is/comprises epoxy resin. Optionally this adhesive is Loctite <NUM>. Optionally any other suitable adhesive. Optionally the biasing element <NUM> is secured to provide a biasing element <NUM> to pot <NUM> pull force of up to <NUM> N/mm<NUM>. Optionally the biasing element <NUM> to pot <NUM> pull force is around <NUM> N/mm<NUM>. Optionally the biasing element <NUM> to pot <NUM> pull force is provided over between <NUM><NUM> and <NUM><NUM>. Optionally the biasing element <NUM> to pot <NUM> pull force is provided over around <NUM><NUM>.

The biasing element <NUM> and the pot <NUM> are arranged to surround an internal space <NUM> that provides a portion of the tubing bore through which fluid can flow. Optionally one or more other materials can be arranged between the biasing element <NUM> and the internal space <NUM>. Optionally one or more other materials can be arranged between the pot <NUM> and the internal space <NUM>. Optionally these materials are polymeric. Optionally the biasing element <NUM> is at least partly covered in cladding <NUM>. Optionally this cladding is formed of a polymeric material. Optionally the cladding is formed of polyether ether ketone (PEEK). Optionally this cladding is a nylon. Optionally this cladding is metallic. Optionally this cladding is formed of any other suitable material. Optionally the cladding <NUM> is between <NUM> and <NUM> thick. Optionally the cladding <NUM> is between <NUM> and <NUM> thick. Optionally the cladding <NUM> is between <NUM> and <NUM> thick. Optionally the cladding covers the exposed surfaces of the biasing element <NUM>. Optionally the surface or surfaces of the biasing element <NUM> in contact with (and optionally adhered to) the pot <NUM> do not include cladding.

<FIG> illustrates a cross section of a biasing assembly <NUM> along the A-A axis illustrated in <FIG>. The arrangement of the biasing element <NUM> which sits in a cutaway region <NUM> of the pot can be seen more clearly. The ring-shaped arrangement of the biasing assembly <NUM> at least partially enclosing the internal space <NUM> is shown. Abutment surfaces <NUM>, <NUM> of the biasing element <NUM> which optionally may be adhered to the pot are indicated. Exposed surfaces <NUM>, <NUM>, which optionally may be covered in cladding <NUM> are indicated. It will be understood that the biasing element <NUM> in <FIG>, <FIG>, <FIG>, <FIG>, <FIG>, <FIG>, <FIG> is a magnet.

Throughout the description and claims of this specification, the words "comprise" and "contain" and variations of them mean "including but not limited to" and they are not intended to (and do not) exclude other moieties, additives, components, integers or steps.

Claim 1:
Apparatus for selectively connecting a first fluid communication region (<NUM>) to a further fluid communication region (<NUM>) at a downhole location, comprising:
an elongate housing (<NUM>), locatable in a wellbore, comprising a first end portion (<NUM>) associated with a first fluid communication region, the first fluid communication region being locatable at a substantially downhole location;
a sheath member (<NUM>) axially slidable within the housing and being biased towards the first end portion via at least one biasing element (<NUM>); and
an elongate shuttle member (<NUM>) axially slidable within the housing and slidably locatable in a sealed relationship or non-sealed relationship with the sheath member; wherein
the biasing element provides a predetermined biasing force that determines a threshold pressure which must be exceeded by a fluid pressure at the first fluid communication region to permit axial movement of the sheath member towards the further fluid communication region, the further fluid communication region being locatable at a downhole location that is further towards a wellbore surface relative to the first fluid communication region.