GB2589544A

GB2589544A - Sealing method and associated apparatus

Info

Publication number: GB2589544A
Application number: GB1912971.7A
Authority: GB
Inventors: Michael Larkins Bronson
Original assignee: Wellvene Ltd
Current assignee: Wellvene Ltd
Priority date: 2019-09-09
Filing date: 2019-09-09
Publication date: 2021-06-09
Anticipated expiration: 2039-09-09
Also published as: GB201912971D0; GB2589544B

Abstract

Downhole apparatus and methods for providing a subsurface safety valve or SSV 16. The apparatus has an upper seal assembly 12 with seal element 19 for sealing within a bore uphole of a control line port, and a lower seal assembly 14 with seal element 21 for sealing within said bore downhole of the control line port 32. The apparatus has a mandrel with a central bore passage, the mandrel extending between the upper and lower seals. The apparatus has a fluid passage that in use extends from the control line port, the fluid passage being sealingly separated from the central bore. The apparatus is mechanically activatable to set at least one of the upper and lower seals. The apparatus may be deployed to sit within a previously-installed subsurface safety valve as a replacement. The apparatus may be retrievable by wireline.

Description

SEALING METHOD AND ASSOCIATED APPARATUS

TECHNICAL FIELD

The present invention relates to a method of sealing in a downhole bore, particularly, but not exclusively, for inserting or operating a safety valve; and associated apparatus.

BACKGROUND

Oil/gas wellbores have a number of valves for controlling flow or pressure in/from wellbores. In particular, subsurface safety valves (SSVs) are commonly used to shut-in oil and/or gas wells. The SSV is housed in tubing in a hydrocarbon producing well and operates to block upward flow of formation fluid through the tubing.

SSVs are typically "normally closed", being biased to a closed position as a default, such as with a flapper valve. During normal production, the valve is maintained open, such as by supply of a hydraulic pressure transmitted to the SSV by a hydraulic control line positioned in an annulus between production tubing and casing. A drop in the hydraulic supply pressure can close the valve. Accordingly, the valve can fail in a closed state; or be actively reconfigured to the closed state by controlling the hydraulic pressure supplied via the control line.

It may be an object of one or more aspects, examples, embodiments, or claims of the present disclosure to at least mitigate or ameliorate one or more problems associated with the prior art, such as described herein or elsewhere.

SUMMARY

According to a first aspect, there is provided an apparatus for use downhole. The apparatus may be for providing and/or operating a downhole valve. The downhole valve may comprise an insert safety valve. The apparatus may comprise the downhole valve. The apparatus may comprise a seal. In at last some examples, the apparatus may comprise a pair of seals. The apparatus may comprise an upper seal. The apparatus may comprise a lower seal. The apparatus may be for sealing a control line. The apparatus may be for sealing above and/or below a control line. In at least some examples, the apparatus may be for sealing above and below a control line port. The apparatus may be configured to straddle the control line port. The apparatus may be configured to provide a sealed flowpath from the control line to a device. The device may comprise the downhole valve.

The control line port may comprise a lateral hydraulic port for receiving hydraulic pressure and/or fluid laterally, such as from an annulus laterally external to a production bore. The apparatus may be for sealing so as to provide a sealed flowpath from the control line port. The sealed flowpath may be laterally offset from a central longitudinal axis of the bore. The apparatus may define a fluid chamber or passage for connection to control line. The fluid passage or chamber may comprise an annular passage or chamber. The fluid passage or chamber may be at least partially defined by an exterior portion of the apparatus. In at least some examples, a portion of the fluid passage or chamber may be defined in an annulus between an exterior of a mandrel of the apparatus and an interior surface of the tubing into which the apparatus is positionable. The mandrel may comprise an intermediate mandrel, connecting the upper seal assembly of the apparatus with the lower seal assembly of the apparatus.

The upper seal may comprise an upper seal assembly. The upper seal assembly may comprise a seal element. The seal element may comprise an external seal element.

The external seal element may be for sealing to an external apparatus or device, such as the previously-installed tubing for receiving a downhole safety valve. The upper seal may comprise a single seal element. The lower seal may comprise a lower seal assembly. The lower seal assembly may comprise a seal element. The lower seal may comprise a single seal element. In at least some examples, each of the upper and lower seals may comprise only a single seal element respectively. The upper and/or the lower seal may comprise an annular seal. The seal/s may be for sealing against a sealing surface of a previously-installed tubing, such as a damaged tubing for receiving a subsurface safety valve. The apparatus may be configured to position a subsurface safety valve offset from the previously-installed tubing. The apparatus may position the subsurface safety valve axially offset from the previously-installed tubing, such as in a location not intended or defined by the previously-installed tubing. The apparatus may allow positioning of the subsurface safety valve outside previously-installed tubing. The apparatus may comprise an adaptor for connection to the previously-installed tubing to enable positioning of the subsurface safety valve relative to the previously-installed tubing, particularly the control line port thereof. The apparatus may position the subsurface safety valve beyond or downhole of the previously-installed tubing. The apparatus may be configured to allow positioning of a different gauge of subsurface safety valve. The apparatus may be configured to allow a smaller gauge subsurface safety valve to be run-in through the previously-installed tubing to a location downhole thereof, such as a smaller gauge relative to a gauge of subsurface safety valve initially intended when the tubing was previously installed. The apparatus may comprise a The upper and/or lower seal/s may be reconfigurable between a sealing configuration and a non-sealing configuration. The seal/s may be reconfigurable between configurations by a change in dimension. The change in dimension may comprise a change in diameter. For example, the seal/s may be reconfigurable from a non-sealing configuration to a sealing configuration by an increase in external diameter.

The upper seal may be for sealing an upper portion of the apparatus to an upper bore portion and the lower seal may be for sealing the apparatus to a lower bore portion. The apparatus may comprise a bore passage. The bore passage may comprise a central bore passage. The bore passage may comprise a throughbore. The central bore may be for the passage or flow of fluid, such as production fluid. The central bore may allow a flow of fluid, in at least some configurations.

In addition to the single seal element/s, the apparatus may comprise one or more internal seal/s. The internal seal/s may be for sealingly connecting components of the apparatus to each other. The internal seal/s may help define the fluid path for the control line fluid. The internal seal/s may separate the apparatus's bore passage from the control line fluid.

The apparatus may comprise a carrier for a valve. The apparatus may comprise the valve. The valve may comprise a safety valve. The valve may comprise an insert valve.

The valve may comprise a replacement or substitute valve. The valve may comprise a valve for supplementing or replacing a previously-positioned valve, such as a previously-positioned tubing valve, or a portion thereof, wherein the previously-positioned valve is no longer functional or no longer satisfactorily functional. In at least some examples, the apparatus may comprise a replacement or substitute sub-surface safety valve and a carrier therefor.

The apparatus may comprise a sealing apparatus. The apparatus may be for sealing within a downhole valve, or a portion thereof. The apparatus may be configured for running-in to the downhole valve. The downhole valve may comprise a tubing mounted safety valve. The downhole valve may comprise a tubing retrievable downhole safety valve. The downhole valve may be in situ prior to running-in of the apparatus of the present disclosure. For example, the downhole valve may comprise a previously-installed safety valve. The apparatus of the present disclosure may be configured to be run-in to position at the previously-installed valve. The apparatus may be configured to seal to or within the previously-installed valve, or portion/s thereof. In at least some examples, the apparatus may be configured to land in the previously-positioned tubing valve. The apparatus may be configured to seal against a previously-installed sealing surface.

The seal element/s of the upper and/or lower seal/s may comprise a radially expandable seal element. The radially expandable seal element may be radially expandable without substantially decreasing in axial length, the axial length being in the axial direction of the bore. Accordingly, the seal element may maintain a substantially same axial length in an expanded and a rest or contracted configuration. The seal element may comprise a similar axial length in a sealing configuration as in a non-sealing configuration. The seal element may be reconfigurable from the non-sealing configuration to the sealing configuration by an increase in outer diameter of the sealing element. The increase in outer diameter of the sealing element may be effected by an increase in an inner diameter of the sealing element. The seal assembly may comprise a member, such as a cam member, for radially expanding the sealing element from within an inner diameter. The member may be axially movable to effect a change in diameter of the sealing element. The member may comprise a sleeve, such as a sleeve with a tapered or chamfered diameter connecting a portion of greater diameter to a portion of lesser diameter. Engaging the sealing element with the portion of greater diameter may force and maintain the sealing element at a greater outer diameter of the sealing element, such that the outer diameter of the sealing element may engage an exterior surface, such as an external inner bore sealing surface of a tubing. Disengaging the sealing element with the portion of greater diameter may allow the sealing element to disengage. The sealing element may be resilient so as to radially contract upon removal of the portion of greater diameter. Accordingly, the sealing element may be selectively engageable and disengageable by axially moving the member relative to the sealing element. The sealing element may maintain an axial position during axial movement of the activating member. The sealing element may maintain an axial length. The sealing element may not comprise a V packing. The sealing element may comprise a non-V-packing sealing element. The sealing element may comprise bi-directional sealing element, such as configured to and/or rated to withstand a pressure or pressure differential in an uphole and a downhole direction.

The sealing element may be maintained in position by one or more sleeves or mandrels within which the activation member is slidably mounted. The activation member may be slidably mounted relative to the rest of the apparatus. The rest of the apparatus may be maintained in position, such as longitudinally maintained in position relative to an external tubing. The apparatus may be maintained in position by one or more gripping members, such as one or more sets of lock dogs or keys.

The apparatus may comprise a pair of activation members, one for each of the single sealing elements. Accordingly, the apparatus may comprise an upper activation sleeve and a lower activation sleeve. The upper and lower activation sleeves may be similarly activated. For example, the upper and lower activation sleeves may be activated by a similar mechanism or means. In at least some examples, the upper and lower activation sleeves may be activated by an axial movement in a same direction. The same direction may comprise a downhole direction. The upper and lower activation sleeves may be activatable by a same movement of a running tool. The upper and lower activation sleeves may be simultaneously activatable by a mechanical movement of the running tool or string, such as a downward jarring thereof. The positioning or gripping member/s, such as the lock dogs or keys, may be similarly activatable, such as by the/an activation sleeve. For example, the positioning or gripping member/s may be extendable into a receiving recess, such as a key recess in the external tubing, by a longitudinal movement of a/the mandrel/s. The positioning or gripping member/s may be simultaneously activatable with the activation sleeves, optionally with the sealing elements. In at least some examples, each of the upper and lower sealing elements and the gripping or positioning member/s may be activatable by a similar mechanism or means. Each of the upper and lower sealing elements and the gripping or positioning member/s may be activatable by a relative axial movement/s of a/the sleeve/s. Each of the upper and lower sealing elements and the gripping or positioning member/s may be activatable by a same operation. For example a jarring of the running tool or string may activate each of the gripping or positioning member/s and the upper and lower sealing elements. The apparatus may be configured such that each of the upper and lower sealing elements and the gripping or positioning member/s may be activatable simultaneously. The apparatus may be configured such that each of the upper and lower sealing elements and the gripping or positioning member/s may be activated sequentially. For example, the apparatus may be configured such that activation extends the gripping or positioning member/s before the sealing element/s. An axial stroke/s may be associated with the activation of each of the upper and lower sealing elements and the gripping or positioning member/s. Extension of at least one of the upper and/or lower sealing elements and/or the gripping or positioning member/s may be associated with a different section of the axial stroke. For example, the gripping or positioning member/s may extendable during a first portion of the stroke, prior to extension of the upper and/or lower sealing element/s.

At least one of the activation members may comprise an engaging element such as to limit a position of the activation member. The position limitation may be an axial position or movement limitation, such as to limit or prevent a movement of the activation member in at least one axial direction. For example, the engaging element may comprise a ratchet element, for engaging a corresponding ratchet element on an other portion of the apparatus. Accordingly, the activation member may have at least a portion of its stroke limited to a single axial direction, at least whilst downhole. The engaging element may be configured to resist or prevent unintended or undesired movement of the activation member, such as in response to a downhole fluid flow and/or pressure. The engaging element may prevent uphole movement of the activation member.

The sealing element may comprise an annular sealing element. The annular sealing element may comprise a substantially rectangular cross-section. The sealing element may comprise a profiled surface. The sealing element may comprise a profiled outer surface for sealing engagement, such as with an inside wall, such as an inside wall of the previously-positioned valve. The profiled outer surface may comprise a plurality of features. The plurality of features may comprise annular protrusions and/or recesses.

For example, the sealing element may comprise a plurality of ring-shaped fins or ribs.

The plurality of fins or ribs may extend continuously around an outer circumference of the sealing element.

The gripping or positioning member/s may comprise floating lock-dogs or keys. The gripping or positioning member/s may be unbiased. Accordingly, the gripping or positioning member/s may be freely extendable by a radial propulsion associated with an axial movement of a key activation sleeve or mandrel; and freely retractable in an absence of radial propulsion by the key activation sleeve. The apparatus may comprise lock dogs for securing the apparatus to a profile downhole. The profile downhole may be of the previously-installed tubing for receiving a subsurface safety valve. The lock dogs may be mechanically activatable. The lock dogs may be mechanically activatable with the setting of at least one of the upper and lower seals. The lock dogs may be mechanically activatable by axial movement of a lock dog cam member. The lock dogs may be unbiased in an inactivated configuration. The lock dogs may be floating. The lock dogs may be configured to be retractable by removal or repositioning of the cam member. The apparatus may comprise a singe set of lock dogs or keys. The lock dogs or keys may be positioned above the upper sealing element. The lock dogs or keys may maintain an axial position of the upper and/or lower sealing assemblies. The upper and lower sealing assemblies may be fixed relative to each other. The upper and lower sealing assemblies may be at a fixed axial separation from each other. The fixed axial separation may correspond to an axial separation of a pair of inner bore sealing surfaces of the previously-installed tubing. The lock dogs or keys may at least assist in maintaining an axial position of the apparatus, such as when and/or for engaging the sealing element/s.

The apparatus may comprise a shoulder. The shoulder may comprise a no-go. The shoulder may be configured to engage a tubing shoulder of the previously-installed tubing. The apparatus shoulder may be configured to position the lock dogs or keys and/or the upper sealing element and/or the lower sealing element, such as to position each/the feature/s at a corresponding axial location of a portion of the tubing, such as a corresponding tubing profile or receiving surface.

The apparatus may comprise a downhole apparatus for an intervention operation. The apparatus may comprise a workover apparatus. The apparatus may position a subsurface safety valve, such as for continuation or resumption of production flow therethrough. The wellbore may be a subsea wellbore. The wellbore may be a production wellbore.

According to an aspect there is provided a method of providing or performing a downhole operation. The method may comprise inserting or positioning a downhole valve. The valve may comprise a subsurface safety valve, such as a replacement insert subsurface safety valve. The method may comprise running the valve in on an apparatus. The method may comprise running the valve in on a carrier or adaptor apparatus. The method may comprise positioning the apparatus within a previously-positioned tubing downhole. The previously-positioned downhole tubing may comprise a tubing mount for receiving a subsurface safety valve. The tubing may comprise a damaged tubing, such as by wireline gouging, corrosion or the like. The method may comprise running in the apparatus on a running tool. The running tool may comprise a wireline running tool. The wireline running tool may comprise a slickline running tool. The wireline running tool may comprise non e-line wireline (i.e. without e-line). The method may comprise running-in the valve without requiring electrical and/or electronic and/or hydraulic control lines in the string. The method may comprise running and setting the apparatus mechanically. The method may comprise setting the apparatus by jarring. The method may comprise running-in the apparatus on a wireline with a jarring tool. Activation of the jarring tool, such as mechanically and/or hydraulically, may mechanically set the apparatus.

The method may comprise engaging inner bores of the previously-installed tubing above and below a control line port in the tubing. The method may comprise engaging sealing surfaces of the tubing. The method may comprise engaging each of a respective upper and lower tubing inner bore sealing surface with a respective single upper and lower sealing element.

The method may comprise only radially expanding the sealing element's. The method may comprise engaging the sealing element's without requiring a back-up for the sealing element's. The method may comprise engaging and/or disengaging the sealing elements without any change in an axial length of the sealing elements.

The method may comprise setting the apparatus only mechanically. The method may comprise setting each of the upper and lower sealing elements and the gripping or positioning member/s with a relative movement of a running tool. The method may comprise setting each of the upper and lower sealing elements and the gripping or positioning member/s with a relative movement of a running tool in a downhole direction. Accordingly, each of the upper and lower sealing elements and the gripping or positioning member/s may be set with a downhole movement of the running tool, such as a downhole jarring.

The method may comprise providing a hydraulic flowpath from the tubing control line port to the valve positioned downhole by the apparatus. The method may comprise providing an internal flowpath for control fluid within the apparatus, such as within an annulus or annular portion of the apparatus. The method may comprise hydraulically activating the valve downhole with hydraulic pressure via the hydraulic control line port in the tubing. The method may comprise maintaining the valve downhole open with hydraulic pressure via the flowpath through the apparatus. The method may comprise withdrawing the running tool, leaving the apparatus and replacement insert subsurface safety valve downhole. The method may comprise producing fluid through the downhole valve and apparatus. Accordingly, the apparatus may comprise an inner bore defining a portion of a production bore once the running tool has been withdrawn.

The method may comprise retrieving the apparatus, such as subsequent to an operation and/or production. Retrieving the apparatus may comprise a fishing method.

Retrieval may comprise only pushing and/or pulling the apparatus. Retrieval may comprise fishing with a fishing tool. The fishing tool may comprise a GS type fishing tool, such as for engaging a GS fish neck of the apparatus. The method may comprise a pushing action with the fishing tool. The method may comprise pushing, optionally, jarring with the fishing tool to extend a member downhole or further downhole. The member being extended may be an activation member of a sealing element. The method may comprise pushing to disengage at least one of the seals. The method may comprise pulling to disengage at least one of the seals. In at least some examples, the method may comprise pushing to disengage a first seal, such as the lower seal; and pulling to disengage a second seal, such as the upper seal. The method may comprise sequentially disengaging the first, such as the lower, seal and then the second seal, such as the upper seal. The method may comprise pulling and/or pulling to allow keys or lock dogs to be disengaged. The method may comprise pulling to axially remove a support or activation member for the keys or lock dogs. The method may comprise allowing the keys or lock dogs to freely float. Accordingly, the keys or lock dogs may be free to retract in an absence of the support or activation member. The keys or lock dogs may be pushed in by an external member, such as a profile or portion of a profile of the previously-installed tubing.

According to an aspect, there is provided a kit or array of apparatuses or devices. The kit may comprise the apparatus of any other aspect. The kit may comprise the device/s of any other aspect. The kit may comprise the apparatus of one aspect or example and the valve. In at least some examples, the kit may comprise an apparatus of the first aspect and a safety valve. The kit may comprises a plurality of apparatuses, each apparatus configured to fit in a different tubing. For example, a first apparatus may be configured to fit and seal within a first tubing with upper and lower bore sealing surfaces of a first gauge and a first axial separation; and a second apparatus may be configured to fit and seal within a second tubing with upper and lower bore sealing surfaces of a second gauge and a second axial separation.

According to an aspect, there is provided a system comprising a controller according to an aspect, claim, embodiment or example of this disclosure, or a system arranged to perform a method according to an aspect, claim, embodiment or example of this disclosure.

According to an aspect, there is provided computer software which, when executed by a processing means, is arranged to perform a method according to aspect, claim, embodiment or example of this disclosure. The computer software may be stored on a computer readable medium. The computer software may be tangibly stored on a computer readable medium. The computer readable medium may be non-transitory.

Any controller or controllers described herein may suitably comprise a control unit or computational device having one or more electronic processors. Thus, the system may comprise a single control unit or electronic controller or alternatively different functions of the controller may be embodied in, or hosted in, different control units or controllers. As used herein the term "controller" or "control unit" will be understood to include both a single control unit or controller and a plurality of control units or controllers collectively operating to provide any stated control functionality. To configure a controller, a suitable set of instructions may be provided which, when executed, cause said control unit or computational device to implement the control techniques specified herein. The set of instructions may suitably be embedded in said one or more electronic processors. Alternatively, the set of instructions may be provided as software saved on one or more memory associated with said controller to be executed on said computational device. A first controller may be implemented in software run on one or more processors. One or more other controllers may be implemented in software run on one or more processors, optionally the same one or more processors as the first controller. The controller/s may be located downhole and/or at surface and/or remotely, such as at a remote control location. Other suitable arrangements may also be used.

Within the scope of this application it is expressly intended that the various aspects, embodiments, examples and alternatives set out in the preceding paragraphs, in the claims and/or in the following description and drawings, and in particular the individual features thereof, may be taken independently or in any combination. That is, all embodiments and/or features of any embodiment can be combined in any way and/or combination, unless such features are incompatible. The applicant reserves the right to change any originally filed claim or file any new claim accordingly, including the right to amend any originally filed claim to depend from and/or incorporate any feature of any other claim although not originally claimed in that manner.

The invention includes one or more corresponding aspects, embodiments or features in isolation or in various combinations whether or not specifically stated (including claimed) in that combination or in isolation. For example, it will readily be appreciated that features recited as optional with respect to the first aspect may be additionally applicable with respect to the other aspects without the need to explicitly and unnecessarily list those various combinations and permutations here (e.g. the apparatus or device of one aspect may comprise features of any other aspect). Optional features as recited in respect of a method may be additionally applicable to an apparatus or device; and vice versa.

In addition, corresponding means for performing one or more of the discussed functions are also within the present disclosure.

The above summary is intended to be merely exemplary and non-limiting.

Various respective aspects and features of the present disclosure are defined in the appended claims.

It may be an aim of certain embodiments of the present disclosure to solve, mitigate or obviate, at least partly, at least one of the problems and/or disadvantages associated with the prior art. Certain embodiments may aim to provide at least one of the advantages described herein.

Examples of the present disclosure are provided in the clauses below, noting that these clauses are non-limiting and not to be interpreted as defining the scope of protection, also noting the claims appended or to be appended hereto are distinct from these clauses.

CLAUSES

1. A downhole apparatus for providing a subsurface safety valve, the apparatus comprising: an upper seal assembly comprising an upper seal for sealing within an upper portion of a section of bore, the upper portion being uphole of a control line port; a lower seal assembly comprising a lower seal for sealing within a lower portion of the section of bore, the lower portion being downhole of the control line port; and a mandrel extending between the upper and lower seals, the mandrel defining a central bore through a radial interior of the apparatus; wherein the apparatus defines a fluid passage from the control line port, the fluid passage being sealingly separated from the central bore; and wherein the apparatus is mechanically activatable to set at least one of the upper and lower seals.

2. The apparatus of clause 1, wherein the subsurface safety valve comprises a replacement subsurface safety valve; and the apparatus is configured to seal within another, previously-installed subsurface safety valve.

3. The apparatus of clause 2, wherein the apparatus comprises the replacement subsurface safety valve.

4. The apparatus of any preceding clause, wherein the apparatus is configured to set both the upper and lower seals with mechanical activation.

5. The apparatus of clause 4, wherein the apparatus is configured to set the seals simultaneously by jarring.

6. The apparatus of any preceding clause, wherein the apparatus is mechanically acfivatable to unset at least one of the upper and lower seals.

7. The apparatus of clause 6, wherein both the upper and lower seals are configured to be unset simultaneously by pulling the apparatus, such as with a fishing tool.

8. The apparatus of any preceding clause, wherein the apparatus is configured to be run-in and retrieved without shearing or deforming any components such that the apparatus can be re-run without requiring replacement of a component.

9. The apparatus of any preceding clause, wherein each of the upper seal and the lower seal respectively comprises a single sealing element.

The apparatus of clause 9, wherein each single sealing element comprises a radially expandable, resilient annular sealing element, the sealing element being reconfigurable between a non-sealing configuration and a sealing configuration whilst maintaining its axial length.

11 The apparatus of clause 10, wherein the apparatus comprises a profile, such as a cam member, the profile being movable relative to the sealing element to radially push the sealing element outwards from the non-sealing configuration to the sealing configuration.

12 The apparatus of any of clauses 9 to 11, wherein the sealing element comprises a profiled exterior, the profiled exterior comprising a plurality of annular features, the annular features extending continuously around a circumference of the sealing element.

13 The apparatus of any preceding clause, wherein the apparatus comprises lock dogs for securing the apparatus to a profile downhole, the lock dogs being mechanically activatable with the setting of at least one of the upper and lower seals.

14 The apparatus of clause 12, wherein the lock dogs are activatable by axial movement of a lock dog cam member; and the lock dogs are unbiased in an inactivated configuration.

A method of providing a subsurface safety valve, the method comprising: running the valve in on a carrier or adaptor apparatus; positioning the apparatus within a previously-positioned tubing downhole; activating a upper seal assembly comprising an upper seal to engage and seal within an upper portion of a section of bore of the previously-positioned tubing, the upper portion being uphole of a control line port; activating a lower seal assembly comprising a lower seal for sealing within a lower portion of the section of bore, the lower portion being downhole of the control line port; defining a central bore through a radial interior of the apparatus with a mandrel extending between the upper and lower seals; and defining a fluid passage from the control line port, the fluid passage being sealingly separated from the central bore; wherein the method comprises mechanically activating to set at least one of the upper and lower seals.

16 Computer software which, when executed by a processing means, is arranged to perform a method according to clause 15.

17 The computer software of clause 16 stored on a computer readable non-transitory medium.

BRIEF DESCRIPTION OF THE DRAWINGS

An embodiment of the invention will now be described by way of example only and with reference to the accompanying drawings, in which: Figure 1 shows an example of an apparatus according to the present invention; Figure 2 shows the apparatus of Figure 1 with sealing elements engaged; Figure 3 shows the apparatus of Figures 1 and 2 with the sealing elements subsequently disengaged; Figure 4 shows a detail view of a portion of the apparatus of Figure 1 with a sealing element disengaged; Figure 5 shows the portion of the apparatus of Figure 4 with the sealing element engaged; Figure 6 shows the portion of the apparatus of Figure 5 showing a flowpath for a control fluid; Figure 7 shows a schematic diagram of a method according to the present invention; Figure 8 shows a partial cutaway of an example of a running tool for the apparatus of Figure 1; Figure 9 shows another view of the running tool of Figure 8; Figure 10 shows the apparatus of Figure 1 with the running tool of Figures 8 & 9; Figure 11 shows the apparatus of Figure 10 with the sealing elements engaged; and Figure 12 shows the apparatus of Figures 10 & 11 in a retrieval operation.

DETAILED DESCRIPTION

Referring to Figure 1, there is shown an apparatus 10. The apparatus comprises an upper sealing assembly 12 and a lower sealing assembly 14. As shown here, the apparatus is mounted to a replacement insert SSV 16, the SSV 16 being mounted at a downhole end of the apparatus 10 As shown here, the apparatus' 10 upper sealing assembly 12 comprises an upper seal 18 which is a single upper sealing element 19. The lower sealing assembly 14 also comprises a lower seal 20 with a similar single lower sealing element 21.

Each seal assembly 12, 14 comprises a respective cam sleeve member 84, 86, for radially expanding the sealing elements 19,21 from within an inner diameter. The respective cam sleeve members 84, 86 are axially movable to effect a change in diameter of the sealing elements 19, 21. Accordingly, the sealing elements 19, 21 are selectively engageable and disengageable by axially moving the respective cam sleeve member 84, 86 relative to the sealing element 19, 21. The respective cam sleeve members 84, 86 are linked and movable with respective lower and upper activation sleeves 82, 88. The respective single sealing elements 19, 21 comprise bi-directional sealing element, configured to and rated to withstand a pressure or pressure differential in both an uphole and a downhole direction.

As shown in Figure 1, a wellbore (not shown) has a previously-installed tubing 22 with a landing nipple for receiving a SSV. With over 7800 wells drilled and completed in the UKCS alone, there can be a wide variation of Tubing Retrievable downhole safety valves (DHSV's), and VVireline Retrievable DHSV's, installed within these completions. Historically DHSV Hold Open / Protection Sleeves were commonly run as part of an intervention campaign to protect the TRDHSV upper and lower seal bore from any potential damage through wire tracking, scoring etc. However, there was a period of time whereby the installation of such sleeves became less common within UKCS operations. As the present applicant has also observed, as well stock in the UKCS has aged, a number of TRDHSV's have since become problematic due to wear and tear of functioning components through time and well conditions over the life cycle of the well. Subsequently, over the past few years, the present applicant has observed that a significant number of TRDHSV's have failed in service and require to be locked open in preparation for an insert valve to be installed, have proved problematic when trying to achieve a seal on the upper and lower TRDHSV seal bores with the insert DHSV. The present applicant has surmised that this is mainly due to the wire tracking and also erosion / corrosion over the life cycle of the well. Investigation work into the root cause has identified wire tracking across both the upper and lower seal bore to be significant contributor in being unable to achieve a test with standard insert DHSV packing stack arrangements.

The landing nipple within the tubing may become damaged by operations that occur through the nipple prior to setting the SSV in the landing nipple. For example, operations such as snubbing and tool running using coiled tubing and slick line can gouge or wear the inside surface of the nipple as the lines through the nipple. Further, any debris on the inside surface of the nipple or any out of roundness of the nipple may prevent proper sealing of the SSV within the nipple. Failure of the SSV to seal in the nipple due to surface irregularities in the inner diameter of the nipple can prevent proper operation of the actuator to open the SSV and can prevent the SSV from completely shutting-in the well when the SSV is closed since fluid can pass through the annular area between the SSV and the nipple due to the irregularities. Operating the well without a safety valve or with a safety valve that does not function properly presents a significant danger. To ensure safety, one option is to replace damaged nipples. However, such operations can be expensive and time-consuming and can be mitigated or replaced by the presently-disclosed apparatus 10 as outlined in detail below.

The apparatus 10 here has an intermediate portion 22 rigidly connecting the upper and lower sealing assemblies 12, 14. Here, the valve 16 is a 3rd party Insert downhole safety valve (DHSV) attached to the bottom of the apparatus 10. As shown in Figure 1, the upper seal 18 aligns with an upper seal bore 26 of the tubing 22 and the lower seal 20 aligns with the lower seal bore 28 within the tubing 22 (which may be of a Tubing Retrievable DHSV or a Ported Nipple profile). In general, downward jarring on slickline closes a fishneck on a lock and moves an inner mandrel down to expand both sealing elements 19, 21 out into the relevant seal bores 26, 28, as shown in Figure 2. Accordingly, the presently-disclosed apparatus 10 offers an alternative and unique seal design with various benefits over conventional WRDHSV options.

As shown in Figure 2, when the apparatus 10 is run-in on slickline into the tubing 22, a no-go shoulder 30 is engaged by the apparatus 10 to limit and define an axial position of the apparatus 10. Accordingly, each sealing assembly 12, 14 is appropriately located within the nipple profile. As shown in the transition from Figure 12 to Figure 2, each sealing element 19, 21 is then expanded out into the seal bore 26, 28 to create the required seal.

The apparatus 10 shown is qualified to API 11D / ISO 14310 Grade VU Q1 where required. Grade VO 01 comprises gas testing with pressure & temperature reversal cycling to zero bubble leak rate. The apparatus 10 may be configured and/or rated to a working pressure up to at least 10,000psi; optionally greater. The apparatus 10 may be configured and/or rated to an operating temperature from 0°C to 150°C. The element seal 19, 21 design eliminates use of V-Packings. The apparatus 10 may eliminate a Straddle Installation or upper completion workover. The seal 18, 20 outer diameters are sized to be below a plug body outer diameter for protection whilst running in hole and for ease of entry through and into seal bores 26, 28. The seal elements 19, 21 may be configured and/or rated to seal within damaged seal bores. The seal elements 19, 21 may be configured and/or rated to hold pressure from above, below and from sudden reversals. The apparatus 10 may be retrofitted to suit most size and types of existing OEM landing nipple profiles.

The apparatus 10 here is for sealing a control line (not shown). The apparatus 10 is for sealing above and below a control line port 32 (indicatively shown). The apparatus 10 is configured to straddle the control line port 32. As shown in Figure 6, the apparatus 10 is configured to provide a sealed flowpath from the control line port 32 to a device, such as the valve 16 as shown here. The control line port 32 comprises a lateral hydraulic port for receiving hydraulic pressure and fluid laterally, such as from an annulus laterally external to a production bore (e.g. between an annulus external to the tubing 22 to an interior of the tubing 22). The apparatus 10 is for sealing so as to provide the sealed flowpath from the control line port 32. The sealed flowpath 32 is laterally offset from a central longitudinal axis 36 of the bore 38. The apparatus 10 defines a annular fluid chamber or passage for connection to the control line. The fluid passage or chamber 40 is at least partially defined by an exterior portion of the apparatus 10. As shown in Figure 6, a portion of the fluid passage or chamber 40 is defined in the annulus between an exterior of an intermediate mandrel 42 of the apparatus 10 and an interior surface of the tubing 22 into which the apparatus 10 is positioned. The intermediate mandrel 42 rigidly connects the upper seal assembly 12 of the apparatus 10 with the lower seal assembly 14 of the apparatus 10.

With particular reference to Figure 7, a method 110 of deployment and operation of the apparatus 10 is hereby described in general. The apparatus 10 is run-in in a first step 112; activated in a subsequent step 114 to engage the seals 12, 14 as shown in an associated step 116. In many methods 110, further optional steps are included, such as one or more tests 118 (e.g. as to the integrity of the seals 12, 14); operations can be performed 120; and the apparatus 10 retrieved 122.

With further reference to Figures 8 to 12, the apparatus 10 and its deployment 110 are described in more detail. Figure 8 shows a partial cutaway of an example of a running tool 50 for the apparatus 10 and Figure 9 shows a side view of the running tool 50. The running tool 50 comprises: running tool keys 52, a check pull shear pin 54, setting shear screws 56 and a snap ring 58. As shown in Figures 10, 11 and 12, the running tool 50 can be used to run-in and set the apparatus 10 within the tubing 22. It will be appreciated that the running tool 50 is connected to slickline (not shown), with the apparatus 10 being connected to the slickline via the running tool 50. When the running tool 50 is assembled into the apparatus 10, the running tool keys 52 locate in the fish neck profile 70 of the apparatus 10 and an array of shear screws 56 keep it in the runin-hole position. The shear pin 54 is installed to provide a check pull. It will be appreciated the running tool 50 may be sufficiently long to extend through the central bore 80 of the apparatus 10 to maintain the valve 16 open during run-in (e.g. to eliminate or minimise pressure drop, allow fluid flow therethrough, etc).

As shown in Figure 10 (and Figure 1), the slickline string comprising the running tool 50 and the apparatus 10 connected to the valve 16 is run-in to the bore, into the tubing 22 until the apparatus 10 tags the TRDHSV or Ported Nipple no-go 30 and lands off the apparatus 10 within a profile of the tubing 22. Operation of the running tool 50 then jars down to shear the running tool shear screws 56 and allow the running tool keys 52 to retract to disengage from the fish neck profile 70. The jarring down also positions and sets locking dogs 60 of the apparatus 10. Jarring down expands the seal elements 19, 21 into upper and lower seal bores 26, 28, as shown in Figure 11 (and Figure 2). During setting an inner portion 72 of the running tool 50 remains relatively static, whilst an outer running tool mandrel 74 moves downwards. Once the apparatus 10 has fully set, the running tool keys 52 are collapsed and the snap ring 58 falls in to a groove 59 to lock the outer running tool mandrel 74 to the inner portion 72 of the running tool 50, as shown in Figure 11. Optionally, an operator can take an overpull to verify the apparatus 10 is positively set: picking up and taking an overpull against the shear pin to confirm the apparatus 10 is set. If the apparatus 10 has not set fully it will be retrieved from the profile. Once overpull is achieved, to release the running tool 50 from the apparatus 10, the running tool 50 is jarred up, as shown in Figure 12. The running tool can be pulled uphole, typically out of the hole. An operator can use running tool tell tale to verify that the apparatus 10 is set in the correct position. Accordingly, the apparatus 10 is set as shown in Figure 2, providing an unobstructed central bore 80, such as for passage of fluid, and optionally other apparatus or devices. An engaging element in form of a ratchet element 92 for engaging a corresponding ratchet element 94 on another portion of the apparatus 10. Accordingly, the lower seal cam sleeve 84 has at least a portion of its stroke limited to a single axial direction, being downhole at least whilst downhole. Accordingly, the lower seal 20 is held against undesired upward movement, such as could otherwise be associated with a flow or pressure differential related to downhole fluid (e.g. production). Accordingly, the apparatus 10 can be run-in on slickline and set with a dedicated mechanical setting tool 50.

Although not shown, it will be appreciated that a conventional fishing tool, such as a GS fishing tool can be used to retrieve the apparatus 10. As shown in Figure 3, the apparatus 10 is retrievable with a simple operation, which may be a slickline operation.

The fishing tool is provided with a prong for insertion into the central bore 80, to push down on the lower seal activation sleeve 82. Downward movement of the lower seal activation sleeve 82 progresses the lower seal cam sleeve 84 to a seal disengagement axial position whereby a smaller diameter portion of the cam sleeve 84 is positioned adjacent the lower sealing element 21. Accordingly, the resilient lower sealing element 21 radially contracts to disengage the bore sealing surface 28. The prong may extend through the central bore 80 of the apparatus 10 to maintain a flapper of the valve 16 open. The fishing tool is jarred up to retract the lock dogs 60 and collapse the upper seal 18, as shown in Figure 3. The fish neck profile 70 of the apparatus 10 is latched with the GS pulling tool and the apparatus 10 can be recovered to surface.

For wells that have a failed Tubing Retrievable DHSV or no TRDHSV and rather a Ported Nipple, an Insert Wireline Retrievable DHSV may have been conventionally installed. However, the sealing options for an insert WRDHSV are in the form of a V-Packing Style Arrangement. V-Packing Stacks are not a bi-directional seal, so must be provided in a particular configuration to allow for pressure to be held from both directions. However, the v-Packings are typically sized in that they must be worked into the seal bore due to the tolerance fit. Furthermore, V-Packings are not configured for or rated to use in damaged or wire tracked bores. In contrast, the single sealing elements 19,21 of the presently-disclosed apparatus 10 are radially expandable seal elements. The radially expandable seal elements 19, 21 are radially expandable without substantially decreasing in axial length, the axial length being in the axial direction of the bore 38. Accordingly, the seal elements 19, 21 maintain a substantially same axial length in an expanded and a rest or contracted configuration. The seal elements 19, 21 comprise a similar axial length in the sealing configuration as in the non-sealing configuration. The seal elements 19, 21 are reconfigurable from the non-sealing configuration to the sealing configuration by an increase in outer diameter of the sealing element. The increase in outer diameter of the seal elements 19, 21 is effected by an increase in an inner diameter of the seal elements 19, 21.

The apparatus 10 can provide one or more benefits over conventional apparatus and methods. For example, the apparatus 10 can provide an expanding element DHSV Pack Off to be set on Slickline. The apparatus 10 can be set with mechanical setting only. The apparatus 10 can be set without electronic and/or hydraulic control. The apparatus 10 can eliminate a need for setting on E-Line with Electronic Setting Tools. The apparatus 10 can be set without setting either of the sealing elements 19, 21 in any flow couplings; or tubing above and below the TRDHSV.

The apparatus 10 can eliminate use of V-Packings. The apparatus 10 can eliminate potential for Straddle Installation or upper completion workover. The apparatus 10 can be provided with a seal OD sized below plug body OD for protection whilst running in hole and ease of entry through and into seal bores. The seals 12, 14 can be configured to and rated for damaged seal bores, such as TRDHSV seal bores damaged by gouging and/or corrosion. Each single sealing element 19, 21 provides true bid-directional sealing in each of the upper and lower seal bores 26, 28. The apparatus 10 can be run by core crew wireline personnel to ensure cost saving through reduced persons on board. The apparatus 10 may be configured to be run and set with a single running-in operation, typically slickline; and unset and retrieved in a single retrieval operation, typically slickline.

It will be appreciated that, although shown here within a particular tubing 22, the apparatus may be run-in and set within other tubings or bores. For example, although shown here with a particular SSV 16, the apparatus 10 may be configured for additional or alternative operations. For example, the apparatus 10 may be made up and run without such a SSV 16 mounted at a downhole end of the apparatus 10. For example, the apparatus, with its lock dogs 60 and upper and lower seals 12, 14 may be used for other applications, such as in conjunction with a tubing hanger; a DHSV barrier plug; sliding sleeve door (SSD) applications. The apparatus 10 may be configured for use in subsea plug and abandonment operations. The apparatus 10 may be supplied with one ore more of: prong, melon or pump open equalising sub. The apparatus 10 may be crossed over to a supplied remotely activated equalising device. The apparatus 10 may be configured to eliminates requirement and costs associated with bridge plug setting equipment and/or skilled personnel. The apparatus 10 may be configured for high deviation applications; such as due to the undersized and protected seals 12, 14.

It will be appreciated that embodiments of the present invention can be realised in the form of hardware, software or a combination of hardware and software. Any such software may be stored in the form of volatile or non-volatile storage such as, for example, a storage device like a ROM, whether erasable or rewritable or not, or in the form of memory such as, for example, RAM, memory chips, device or integrated circuits or on an optically or magnetically readable medium such as, for example, a CD, DVD, magnetic disk or magnetic tape. It will be appreciated that the storage devices and storage media are embodiments of machine-readable storage that are suitable for storing a program or programs that, when executed, implement embodiments of the present invention. Accordingly, embodiments provide a program comprising code for implementing a system or method as disclosed in any aspect, example, claim or embodiment of this disclosure, and a machine-readable storage storing such a program. Still further, embodiments of the present disclosure may be conveyed electronically via any medium such as a communication signal carried over a wired or wireless connection and embodiments suitably encompass the same.

All of the features disclosed in this specification (including any accompanying claims, abstract and drawings), and/or all of the steps of any method or process so disclosed, may be combined in any combination, except combinations where at least some of such features and/or steps are mutually exclusive. The applicant indicates that aspects of the present disclosure may consist of any such individual feature or combination of features. It should be understood that the embodiments described herein are merely exemplary and that various modifications may be made thereto without departing from the scope of the disclosure. For example, it will be appreciated that although shown here with a GS fish neck, other fish neck profiles may be incorporated in other embodiments.

Each feature disclosed in this specification (including any accompanying claims, abstract and drawings), may be replaced by alternative features serving the same, equivalent or similar purpose, unless expressly stated otherwise. Thus, unless expressly stated otherwise, each feature disclosed is one example only of a generic series of equivalent or similar features.

The invention is not restricted to the details of any foregoing embodiments. The invention extends to any novel one, or any novel combination, of the features disclosed in this specification (including any accompanying claims, abstract and drawings), or to any novel one, or any novel combination, of the steps of any method or process so disclosed. The claims should not be construed to cover merely the foregoing embodiments, but also any embodiments which fall within the scope of the following claims.

Claims

CLAIMS1. A downhole apparatus for providing a subsurface safety valve, the apparatus cornprising: an upper seal assembly comprising an upper seal for sealing within an upper portion of a section of bore, the upper portion being uphole of a control line port; a lower seal assembly comprising a lower seal for sealing within a lower portion of the section of bore, the lower portion being downhole of the control line port; and a mandrel extending between the upper and lower seals, the mandrel defining a central bore through a radial interior of the apparatus; wherein the apparatus defines a fluid passage from the control line port, the fluid passage being sealingly separated from the central bore; and wherein the apparatus is mechanically activatable to set at least one of the upper and lower seals.
2. The apparatus of claim 1, wherein the subsurface safety valve comprises a replacement subsurface safety valve; and the apparatus is configured to seal within another, previously-installed subsurface safety valve.
3. The apparatus of claim 2, wherein the apparatus comprises the replacement subsurface safety valve.
4. The apparatus of any preceding claim, wherein the apparatus is configured to set both the upper and lower seals with mechanical activation.
5. The apparatus of claim 4, wherein the apparatus is configured to set the seals simultaneously by jarring.
6. The apparatus of any preceding claim, wherein the apparatus is mechanically activatable to unset at least one of the upper and lower seals.
7. The apparatus of claim 6, wherein both the upper and lower seals are configured to be unset simultaneously by pulling the apparatus, such as with a fishing tool.
8. The apparatus of any preceding claim, wherein the apparatus is configured to be run-in and retrieved without shearing or deforming any components such that the apparatus can be re-run without requiring replacement of a component.
9. The apparatus of any preceding claim, wherein each of the upper seal and the lower seal respectively comprises a single sealing element.
10 The apparatus of claim 9, wherein each single sealing element comprises a radially expandable, resilient annular sealing element, the sealing element being reconfigurable between a non-sealing configuration and a sealing configuration whilst maintaining its axial length.
11 The apparatus of claim 10, wherein the apparatus comprises a profile, such as a cam member, the profile being movable relative to the sealing element to radially push the sealing element outwards from the non-sealing configuration to the sealing configuration.
12 The apparatus of any of claims 9 to 11, wherein the sealing element comprises a profiled exterior, the profiled exterior comprising a plurality of annular features, the annular features extending continuously around a circumference of the sealing element.
13 The apparatus of any preceding claim, wherein the apparatus comprises lock dogs for securing the apparatus to a profile downhole, the lock dogs being mechanically activatable with the setting of at least one of the upper and lower seals.
14 The apparatus of claim 12, wherein the lock dogs are activatable by axial movement of a lock dog cam member; and the lock dogs are unbiased in an C\I inactivated configuration.sa)
15 A method of providing a subsurface safety valve, the method comprising: running the valve in on a carrier or adaptor apparatus; positioning the apparatus within a previously-positioned tubing downhole; activating a upper seal assembly comprising an upper seal to engage and seal within an upper portion of a section of bore of the previously-positioned tubing, the upper portion being uphole of a control line port; activating a lower seal assembly comprising a lower seal for sealing within a lower portion of the section of bore, the lower portion being downhole of the control line port; defining a central bore through a radial interior of the apparatus with a mandrel extending between the upper and lower seals; and defining a fluid passage from the control line port, the fluid passage being sealingly separated from the central bore; wherein the method comprises mechanically activating to set at least one of the upper and lower seals.
16. Computer software which, when executed by a processing means, is arranged to perform a method according to claim 15.
17 The computer software of claim 16 stored on a computer readable non-transitory medium.