GB2439399A

GB2439399A - Downhole Lock

Info

Publication number: GB2439399A
Application number: GB0612605A
Authority: GB
Inventors: David Glen Martin
Original assignee: Caledyne Ltd
Current assignee: Caledyne Ltd
Priority date: 2006-06-23
Filing date: 2006-06-23
Publication date: 2007-12-27
Anticipated expiration: 2026-06-23
Also published as: GB2439399B; GB0612605D0

Abstract

A downhole lock contains a housing 4 and a burst or rupture disc 5. A moveable mandrel 15 is held in place by a shear screw 17, locating in a groove on an inner sleeve 8. The mandrel 15, fishing neck 1 and housing 4 form an upper hydrostatic chamber 18 of a piston assembly. A lower hydrostatic chamber 19 is formed by the housing 4, rupture disc 5 and mandrel 15. Spring 9 biases the inner mandrel 12 upwards, with shear screw 17 preventing the mandrel 15 moving and inadvertently activating the keys 11 of the locking mechanism. A predetermined well pressure is defined to activate the lock via the rupture disc. A thread 20 is used to connect the lock to accessories and hence to the central conduit, by which means the lock assembly is conveyed to the appropriate point in the well tubing string. The lock does not require the use of a dedicated running tool.

Description

I Down-hole Lock 3 This invention relates to a down-hole lock assembly

for 4 use in oil and water/gas well operations, and comprises a lock mandrel assembly.

7 Down-hole lock assemblies are known, in which the lock 8 mandrel is used in conjunction with different 9 accessories which are required for well control in down-hole oil, water/gas well operations, being used to 11 anchor and seal the accessory in position in the well 12 tubing string.

14 Existing designs of lock assemblies require the use of a running tool to install the assembly and to position and 16 activate the lock anchoring system within in the well 17 tubing string. A typical lock system is described in 18 patent GB2207157 (Zwart, Down-hole Lock Assembly).

In certain instances, it is desirable to install a 21 conduit within the existing well tubing string, using a 22 lock mandrel to suspend this new conduit within. It is a 23 limitation of the current art that the running tool used 24 to install and position the lock, prevents a single conduit being installed in one trip. It is necessary to I install multiple sections; with a lock mandrel at the 2 top of each section and to connect to previously 3 installed lower sections. This involves more time and 4 expense.

6 One particular instance is to install coil tubing 7 deployed electric submersible pumps (ESPs) below the 8 existing well tubing string mounted safety valve. In 9 applications where the regulatory authorities require the use of a fail-safe safety valve within the well 11 tubing string, the conduit used to carry the power 12 cables to the ESP have to pass through the existing 13 tubing mounted safety valve. The act of passing the 14 conduit through the valve makes this device redundant.

16 With reference to international patent application 17 number PCT/GB2005/004216, the safety valve described in 18 this application allows a central conduit to pass 19 through the valve via a penetrator. In the particular application of the coil tubing deployed ESP, it is 21 desirable to maintain a single conduit with the electric 22 cable from the ESP motor to the exit point for the cable 23 at surface.

1 As it can be seen, this central conduit prevents the use 2 of existing lock mandrel and running tool combinations 3 for installing the safety valve or other well control 4 accessories.

6 To overcome the limitations in the art an apparatus and 7 method is described to install the lock without the use 8 of a dedicated running tool and hence allow a central 9 conduit to pass through the lock mandrel.

11 The lock is activated and hence anchored in the well 12 tubing by application of pressure to the tubing.

14 The lock contains preferably two or more hydrostatic chambers.

17 One of the hydrostatic chambers is filled with well 18 fluids or gas when there is a certain application of 19 pressure to the tubing.

21 As this chamber is filled, a differential pressure 22 generated by the pressure difference between the 23 hydrostatic chamber and the pressure in the well tubing 24 string acts on a piston or pistons to move a sleeve which then anchors the lock.

1 A particular embodiment of the invention will now be 2 described with reference to the accompanying drawings in 3 which: Figure 1 shows a cross section of the lock mandrel in 6 the "run-in" position with the locking mechanism 7 disengaged.

9 Figure 2 shows a cross section of the lock mandrel in the "anchored" position with the locking mechanism 11 engaged.

13 Figure 3 shows an assembly containing the lock; an 14 example safety valve as described in PCT/GB2005/o04216 in conjunction with a coil tubing deployed ESP.

17 Figure 4 shows a drop bar assembly releasing the lock, 18 allowing the entire assembly to be removed from the well 19 tubing string in one trip.

21 In figure 1, the lock comprises a fishing neck 1 which 22 is attached to a housing 4 containing a burst or rupture 23 disc 5. Burst or rupture discs are commercially 24 available from many suppliers. A moveable inner sleeve 15 is held in place by a shear screw 17, threaded to 1 item 1 and locating in a groove on the inner sleeve 15.

2 The inner sleeve 15, fishing neck 1 and housing 4 form 3 the upper hydrostatic chamber 18. Seals 2, 3 and 16 seal 4 this chamber. The lower hydrostatic chamber 19 is formed by the housing 4, rupture disc 5 and inner sleeve 15.

6 Seals 14 and 16 seal it.

8 A wiper seal 6 prevents fines and other debris clogging 9 the key/inner mandrel mechanism.

11 The lock body 7 contains pockets, in which the lockout 12 keys 11 sit. The inner sleeve 15 holds the inner mandrel 13 12 in such a position that the keys 11 are held within 14 the outside diameter of the lock. The combination of springs stops 8 and 10 and the spring 9 bias the inner 16 mandrel 12 upwards. However the shear screw 17 prevents 17 the inner sleeve 15 moving, which in turn prevents the 18 spring 9 expanding to move the inner mandrel 12, which 19 in turn expands the keys 11 into the locking profile within the well tubing string. A thread 20 is used to 21 connect the lock to any accessory devices required and 22 hence to the central conduit, by which means the lock 23 assembly is conveyed to the appropriate point in the 24 well tubing string. A no-go 21 on the lock body 7 1 engages with a shoulder in the well tubing string at the 2 anchor point.

4 The seals 2 and 14 are configured in such a way that pressure applied externally does not have any effect on 6 the inner sleeve 15.

7 The inner sleeve 14 is moved in the following manner.

8 When the lock is conveyed to the appropriate anchor 9 point (nipple profile) the fluids in the well bore exert a pressure all around the assembly. With the particular 11 configuration of the seals 2 and 14, there is no net 12 effect on the piston formed by seals 2, 14 and 16. The 13 differential pressure acting on the rupture disc is 14 determined by the internal pressure of the hydrostatic chamber, typically atmospheric pressure and the well 16 pressure at the anchor point. The burst value of the 17 rupture disc is set at a value above the expected well 18 pressure, so when pressure is applied to the well, the 19 disc bursts, flooding the chamber 19. The seals 2 and 16 forming chamber 18, now form a piston acting on chamber 21 18. The force generated by the piston is enough to shear 22 the screw 17 and allow the inner sleeve 15 to move, with 23 chamber 18 reducing in volume as shown in figure 2, 24 chamber 18A.

1 With the restraint of the inner sleeve 15 now gone, the 2 spring 9 expands as shown in figure.2, item 9A, urging 3 the inner mandrel 12 upwards, which in turn expands the 4 lockout keys 11 to position hA.

6 In another embodiment, the inner mandrel 12 may be 7 shearably connected to the inner sleeve 15. The inner 8 sleeve 15 can travel further than the inner mandrel 12.

9 At the point where the inner mandrel 12 reaches the end of it's travel, the inner sleeve 15 shears off from the 11 inner mandrel 12 and continues until the end of it's own 12 travel.

14 Figure 3 shows the method of deployment. The lock A is attached to a central conduit B, in this instance coil 16 tubing, via a down-hole flow control device C, in this 17 instance a safety valve. The ESP D is connected to the 18 conduit. The full assembly is conveyed into the well 19 tubing string until the lock no-go engages with the nipple profile E in the tubing string F. At this point 21 the valve C is closed and pressure is applied to the 22 tubing to burst the rupture disc 5 and hence anchor the 23 lock in position.

I Figure 4 shows the method of removal. A drop bar 2 assembly G is released from surface and conveyed by 3 gravity to the lock A. Drop bars are known for 4 activating down-hole tools. The drop bar is generally cylindrical in shape and slides down the outside surface 6 of the central conduit. The drop bar G engages with the 7 inner mandrel 12, allowing the keys 11 to collapse. The 8 entire assembly may then be removed from the well tubing 9 string.

Claims

1 Claims 2 1. A downhole lock assembly, which comprises a lock 3

mandrel assembly containing preferably two or more 4 hydrostatic chambers and a shearable device, which maintain an inner mandrel in such as position as 6 to allows keys to remain within the major diameter 7 of the lock mandrel, with the said inner mandrel 8 resiliently urged upwards to actuate the said keys 9 to lock the assembly within a profile in the well tubing string, where well pressure is used to 11 activate the assembly and allow the inner mandrel 12 to expand the keys and so does not require the use 13 of a dedicated running tool and hence allow a 14 central conduit to pass through the lock mandrel. * * * *.* S..

" 16
2. A downhole lock assembly of claim 1, in which a 17 plurality of hydrostatic chambers are used to S..

* 18 maintain the lock in such as position as it can be 19 installed in the well tubing string.

* " 20 21
3. A downho].e lock assembly of claim 2, where by 22 flooding one of the hydrostatic chambers with well 23 pressure, urges the inner mandrel or releases a 24 following inner mandrel to expand the locating keys.

2
4. A downhole lock assembly of claim 3, whereby 3 breaching a rupture disc allows the said 4 hydrostatic chamber to be flooded.

6
5. A downhole lock assembly of claim 1, where the 7 assembly is deployed on a central conduit, rather 8 than a running tool, where the central conduit 9 does not need to interact with the lock mandrel for it to be activated. 11*

12
6. A downhole lock assembly of claim 1, which may be 13 released from the well tubing string with by 14 moving the inner mandrel to the run in position by .s 15 means of a retrieving tool, after the central 16 conduit is removed. * a. * . . **** S..

* 18
7. A downhole lock assembly of claim 1, where a drop 19 bar assembly is used to release the lock assembly * 20 from the well tubing string by moving the inner 21 mandrel to the run-in position.