WO2007031723A2 - Garniture - Google Patents

Garniture Download PDF

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Publication number
WO2007031723A2
WO2007031723A2 PCT/GB2006/003361 GB2006003361W WO2007031723A2 WO 2007031723 A2 WO2007031723 A2 WO 2007031723A2 GB 2006003361 W GB2006003361 W GB 2006003361W WO 2007031723 A2 WO2007031723 A2 WO 2007031723A2
Authority
WO
WIPO (PCT)
Prior art keywords
packer
fluid
expandable member
radially expandable
chamber
Prior art date
Application number
PCT/GB2006/003361
Other languages
English (en)
Other versions
WO2007031723A3 (fr
Inventor
Iian Morrison Macleod
Stephen Reid
Philip Egleton
Original Assignee
Petrowell Limited
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from GB0518686A external-priority patent/GB0518686D0/en
Priority claimed from GB0612899A external-priority patent/GB0612899D0/en
Application filed by Petrowell Limited filed Critical Petrowell Limited
Publication of WO2007031723A2 publication Critical patent/WO2007031723A2/fr
Publication of WO2007031723A3 publication Critical patent/WO2007031723A3/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/127—Packers; Plugs with inflatable sleeve
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/128—Packers; Plugs with a member expanded radially by axial pressure

Definitions

  • This invention relates to a packer, and to a method for setting a packer.
  • Packers are conventional items in oil and gas wells. They are disposed in the annulus between an inner pipe and an outer pipe, or between the inner pipe and the borehole wall, and are radially expanded in the annulus after insertion of the inner pipe in order to seal the annulus.
  • the function of the packer is sometimes mechanical anchorage of the inner string, but it is usually deployed for sealing the annulus in order to prevent fluid communication through the annulus between the zone below the packer, and the zone above it.
  • different zones of formation can be isolated from one another, and produced independently, by setting packers at the boundaries of these zones and using valves etc within the inner string between the packers to control the flow of production fluids. In this way, parts of the reservoir that produce fluids with a high water content can be isolated from more productive areas, and the overall recovery of hydrocarbons from the well can be increased.
  • Packers can be mechanical, e.g. in the form of slips or wedges that slide relative to one another within the annulus in order to cause the radial expansion.
  • they can be hydraulic and can have a bag or bladder that can be inflated within the annulus.
  • Inflatable packers are generally inflated with cement or another settable substance, so that after the cement has cured, the packer is fixed in place.
  • the adjustment of packers after the initial setting has traditionally been very difficult, particularly in the case of inflatable packers, because the setting procedure allows the cement to harden and thereby prevents any further movement of the cement plug to compensate for leaks. Also, temperature fluctuations can cause the inflation medium to expand and contract.
  • a packer for a well comprising a radially expandable member and a fluid injection device adapted to cause expansion of the radially expandable member, and having a one-way device to maintain the expansion of the radially expandable member.
  • the invention also provides a method of setting a packer in a well, the method comprising injecting fluid into a chamber to cause expansion of a radially expandable portion, and preventing fluid egress from the chamber in order to maintain the expansion of the radially expandable member.
  • the well is typically an oil, gas or water well.
  • the fluid injection device can inject fluid direct into a chamber in the radially expandable member to cause direct inflation thereof.
  • the fluid injection device can indirectly cause expansion of the radially expandable member, for example by injecting fluid into a chamber that is remote from the radially expandable member, but which transmits a signal causing mechanical actuation of the radially expandable member without direct inflation of the radially expandable member by the fluid.
  • the fluid injection device can comprise a cylinder and piston arrangement, usually an annular cylinder and piston, typically located in the annulus adapted to be occluded by the packer.
  • the cylinder can optionally be sealed to the outer surface of the inner string sealed by the packer, and the piston can typically move freely within the annular cylinder relative to the inner string.
  • the piston is typically sealed within the cylinder, and pressure changes across the piston typically induce movement of the piston to cause injection of fluid thereby leading to radial expansion of the radially expandable member.
  • the radially expandable member typically incorporates the container for containing the fluid, and in some embodiments this may comprise a bag or bladder or other similar flexible device.
  • Typical fluid containers are flexible but not resilient, so that the shape of the container can change, but not the internal volume.
  • Semi-rigid bladders can be adopted, typically fashioned from malleable metals such as light gauge stainless steel, but more flexible bladders optionally comprising reinforcing substances such as Kevlar TM can also be used. A good combination of reinforced and resilient material would be rubber with steel cable.
  • Typical materials for the bladder can comprise 316 stainless steel, lnconel TM or Elgiloy TM, or any material that can optionally be reinforced by steel grade or Kevlar TM.
  • the bladder typically retains the fluid injected from the fluid injection device.
  • the radially expandable member typically also comprises a resilient pad or bag formed around the bladder, and the expansion of the bladder typically drives the radial expansion of the pad.
  • the function of the resilient pad or bag is to deform to create a seal between the outer surface of the radially expanded bladder and the inner surface of the outer pipe or wall of the borehole.
  • the pad or bag can be resilient to deform against uneven surfaces of the inner wall of the borehole, and create a fluid tight seal to prevent passage of fluid past the packer after it has been set.
  • the pad can usefully be formed from a resilient material such as Nitrile or Aflas TM with a typical durometer value of 70 to 90, and with capacity to resist heat above 120C.
  • the pad can be in the form of a bag that is pre-moulded into the radially expanded configuration that is adopted when it is set, but which is stretched flat for insertion into the well, so that once the device is radially expanded in place, the stresses applied to the inflated bag are reduced, and it is firmly supported and compressed between the outer surface of the bladder and the inner surface of the borehole wall.
  • the pad typically has good extrusion resistance, and good elongation and strength properties.
  • the bag can optionally be supported on its outer face by fingers or cones of malleable metals or other materials that are more rigid than the bag and bladder.
  • the metal supports serve to control more precisely the deformation of the radially expanding portion within certain parameters, and prevent over-expansion in the axial direction.
  • the back-up supports are in the form of cones or collet fingers made from 316 stainless steel, 1018 steel or any other materials that have good strength properties and elongation.
  • the back-up supports are manufactured from highly deformable materials, but are typically less deformable and more rigid than the materials of the bladder or the bag.
  • the fluid that is injected from the fluid injection device into the bladder can be any suitable fluid.
  • the fluid can be setting or can remain as a fluid within the set packer, depending on the desired period of adjustment required.
  • the fluid will be setting but will have a very long set time, allowing for numerous adjustments to be made in the expansion of the packer before the fluid has set hard and locked the packer within the set configuration.
  • the fluid can remain in a fluid state indefinitely, enabling infinite adjustment of the fit of the packer after setting.
  • Typical fluids that are useful to inflate the packer can include liquids and solids that behave like fluids.
  • the fluid can comprise solid rubber balls (2-8mm diameter) or a mixture of steel and rubber balls of around those sizes in order to create a pseudo-solid flowable material that can be injected by means of the piston and piston chamber.
  • the fluids used are slightly resilient, so that energy can be stored in the fluid as it is compressed.
  • the rubber materials typically have a durometer value of around 70 to 90.
  • the bladder can be injected with fluid that itself can expand its own volume, for example a mixture of Aflas TM and diesel can be used in order to inflate the bladder by chemical means, without mechanical operation of pistons etc.
  • the bladed can be filled with a foam that expands as a result of a reaction initiated by temperature changes.
  • the initial expansion of the radial expandable member can be triggered by pressure differentials across the piston, or by mechanical means, such as axial compression of the device in order to change the configuration of the radial expandable member from a stretched configuration where it is held in tension close to the outer surface of the inner pipe, into an expanded configuration where it adopts its normal axially compressed and radially expanded configuration substantially occluding the annulus between the inner and the outer string, or between the inner string and the borehole wall.
  • Final expansion of the expandable member in order to set the packer is usually then accomplished by pressure differentials exerted across the piston causing movement of the piston to expel the fluid from the piston chamber into the bladder.
  • the pressure differential across the piston can be actuated by generating pressure pulses in the tubing, and a conduit through the tubing wall into the piston chamber can be provided in order to transmit these pressure pulses to the piston.
  • the piston can incorporate a resilient means such as a spring, and in particular a beam spring, in order to store compressive force applied during setting in order to maintain a pressure on the fluid in the bladder after the initial setting procedure has been completed and the externally applied setting force has been removed.
  • the piston and piston chamber can be replaced by other fluid injection means, such as secondary bladders, responsive to pressure differentials in order to inject the fluid into the bladder in the radial expandable member.
  • the one-way device can comprise a ratchet means. More than one one-way device can be provided.
  • the ratchet means can be deployed on hydraulic systems or mechanical systems.
  • the ratchet means can typically be provided on the piston and piston chamber in hydraulic systems, or in mechanical systems, it can be deployed on the radial expandable member itself.
  • other one way devices can be quite suitable, for example in hydraulic embodiments, simple one way valves such as flapper or check valves can be provided in a conduit delivering fluid to the radially expandable member.
  • Multiple oneway devices can be employed on a single radially expandable member, and are typically of different types, for example one hydraulic (e.g.
  • valve type one way device can be deployed below the radially expandable member, and one mechanical (e.g. ratchet type) device can be employed above it, or vice versa, so that loads can be consistently applied to the radially expandable member in the event in varying well conditions such as varying pressure differentials.
  • the fluid has an inherent resilience and can be compressed extensively during the setting procedure, to release some of the potential energy gained during that compression after the setting procedure has been completed and the initial setting force has been removed. The maintenance of the pressure resulting from the resilient inflation fluid maintains the seal of the packer across the annulus.
  • energy can be stored during the setting action, either in mechanical features of the device (such as the beam spring) or in the inherent properties of the materials such as the resilient fluid, and the stored energy can be used to compensate for loss of seal after completion of the setting procedure.
  • Fig. 1 is a side sectional view of a packer in its unexpanded configuration
  • Fig. 2 is a similar view to Fig. 1 , showing the packer in its expanded configuration;
  • Fig. 3 is a close up view of a portion of the Fig. 1 packer;
  • Fig. 4 is a side sectional view of a third embodiment of a packer of the invention.
  • FIGs. 5-7 are expanded views of sequential parts of Fig. 3;
  • Fig. 8 is an end sectional view through the line A-A in Fig. 6; and Figs 9-14 are sequential side sectional views (bottom to top) of a fourth embodiment of a packer of the invention.
  • a packer 1 is disposed on the outer surface of a length of tubing such as production tubing T.
  • the packer 1 is disposed within an annulus A situated between the outer surface of the a
  • the production tubing T has conventional box and pin connections enabling it to connect with conventional drill pipe (not shown), so that the packer 1 can reside on a discrete packer sub.
  • the production tubing T has an integral shoulder S1 extending radially from the outer surface of the tubing T, and so the section of production tubing T is specifically designed for carrying the packer, but the shoulder S1 could equally be a simple threaded ring attached to a conventional length of tubing T.
  • the packer 1 comprises an expandable portion 15 and an inflation device 5.
  • the expandable portion comprises a flexible bladder 16 surrounding the outer surface of the production tubing T, and concentric therewith.
  • the flexible bladder 16 is typically formed from a strong but flexible material such as 316 stainless steel, lnconel TM, Elgiloy TM, or a similar metal.
  • the bladder comprises a cylindrical Kevlar sheet having an outer diameter that exceeds the outer diameter of the tubing T, but which is folded so as to lie close to the outer diameter of the tubing T in the unexpanded configuration shown in Fig 1.
  • the bladder 16 is securely fastened at its lower end to a threaded ring 20 that is secured to the outer surface of the tubing T, and which abuts the upper surface of the shoulder S1.
  • the annulus A is sealed off from the area between the bladder 16 and the tubing T by means of a seal 20s.
  • the bladder 16 is connected to a cylindrical piston chamber 6 that is concentrically mounted on the outer surface of the tubing T.
  • the piston chamber 6 has a cap 7 at its upper end that is sealed at 7s against the outer surface of the tubing T.
  • the piston chamber 6 is slidable on the outer surface of the tubing T, and the bore of the piston chamber is sealed off from the annulus A by means of the seal 7s.
  • the annular piston 8 is sealed within the annulus 6a by means of seals 8s, and in the unexpanded configuration, the piston 8 is securely connected to the piston chamber 6 by means of a shear pin 9.
  • the radially outermost surface of the piston 8 also carries a ratchet face 8r which mates with a corresponding ratchet face 6r on the inner surface of the piston chamber 6, thereby restricting the axial movement of the piston 8 within the annulus 6a to a single direction, i.e. axially downwards towards the expandable member 15, in the direction of the arrow shown in Fig 3.
  • the packer 1 When the apparatus is to be run into the hole, the packer 1 is maintained in the position shown in Fig. 1 , with the piston chamber 6 attached to the piston 8 by means of the shear pin 9, and the whole of the fluid injector 5 being axially pulled up towards the top of the tubing, thereby stretching out the resilient bladder 16 so that it lies flat against the tubing T in the configuration shown in Fig. 1.
  • the fluid injector device 5 When the fluid injector device 5 is pulled upwards, the normally doughnut-shaped radially expandable device 15 is stretched out flat against the tubing T as shown in Fig. 1 , and the fluid 19 held therein is distributed evenly within the annular spaces 6a and 16a, contained by the seals 8s and 20s.
  • the piston chamber 6 is locked in the upper position by a latch (not shown) in order to keep the radially expandable member 15 in the stretched position and stop it from springing back into its at rest radially expanded position shown in Fig. 2.
  • the piston chamber 6 When the tubing T is in the correct position in the wellbore and the packer 1 is ready to be deployed, the piston chamber 6 is released from the latch and moved axially down the outer surface of the tubing T to the position shown in Fig. 2 where the inherent energy stored in the stretched out radially expandable member 15, and the axial compression applied by the piston chamber 6, causes the radially expandable member 15 to bulge radially outward from the outer wall of the tubular T, and to adopt its normal resting position in its radially expanded state as shown in Fig. 2. This pushes the outer face of the resilient pad 17 against the inner face of the borehole wall W.
  • the radial expandable device 15 is axially compressed between the piston chamber 6 and the static shoulder s1 , and further downward force of the piston chamber 6 against the upper surface of the radially expandable member 15 will compress the outer pad 17 of resilient Nitrile against the inner wall of the borehole, either against the casing, or against the naked borehole wall if the packer is being deployed in an uncased hole.
  • sufficient force can be exerted by the axial compression of the piston housing 6 against the expandable device 15 in order to set the packer 1 within satisfactory parameters.
  • a secondary setting mechanism is also provided.
  • a second annular shoulder s2 is provided on the outer surface of the tubing T in order to arrest downward movement of the piston housing 6 at the optimum position, with the port 10 straddled, and the radially expandable member 15 in the expanded position in Fig 2, with the pad 17 pressed lightly against the wall W. At that point, the pressure in the bore of the tubing T can be increased in order to exert a pressure differential across the seals 8s on the piston 8.
  • the ratchets 6r and 8r engage, thereby restricting upward movement of the piston 8. Because the ratchets 6, 8r are engaged between the piston housing 6 and the piston 8, the removal of the pressure differential across the piston 8 does not result in upward movement of the piston 8, and it maintains its axial position relative to the tubing T and the housing 6, thereby maintaining the pressure on the fluid 19 within the annulus 6a and 16a, and maintaining the radial expansion of the expandable portion 15 in order to press the resilient pad 17 tightly against the borehole wall W and maintain the seal on the packer.
  • the piston housing 6 is optionally maintained in the set position shown in Fig. 2 by mechanical means such as latches etc (not shown).
  • the packer 1 can be adjusted in order to recover the seal. This is achieved by simply reinstating the pressure differential across the seals 8s by pressurising the bore of the tubing T. The pressure in the tubing T is increased until it exceeds the pressure in the fluid 19 trapped between the seals 8s and 2Os 1 at which point the piston 8 moves axially downwards in order to compress the fluid 19 within the annulus 16a, and push the pad 17 more tightly against the borehole wall W.
  • the engaged ratchets 8r/6r permit this further downward movement and the piston ratchets 8r move down a few teeth on the chamber ratchets.
  • the ratchets 8r/6r restrict the upward movement of the piston in the annulus 6a from its new position, and thus radial expansion of the expandable portion 15 is maintained even after the pressure differential across the piston 8 is subsequently removed.
  • the fluid used in the embodiment shown in Figs. 1 and 2 is typically a resilient mixture of rubber and steel balls of diameter 2-8mm, and the fluid therefore has an inherent resilience that stores additional energy upon compression and this can be used to enhance the seal of the pad 17 against the inner wall of the borehole W after the initial setting force has been removed.
  • the fluid therefore has an inherent resilience that stores additional energy upon compression and this can be used to enhance the seal of the pad 17 against the inner wall of the borehole W after the initial setting force has been removed.
  • other non-resilient fluids can be used with this or any other embodiment.
  • Fig. 3 shows an enlarged view of the ratchet system of the packer 1 illustrating how the teeth 8r on the piston 8 mesh with the teeth 6r on the piston housing in order to restrict movement of the piston 8 to a direction of the arrow shown in Fig. 3, i.e. downwards towards the radially expandable member 15 and the shoulder S1.
  • Fig. 4 shows a second embodiment of a packer 31 which is similar in function to the packer 1 , but which is illustrated in more detail.
  • the packer 31 is deployed on a length of tubing T, and resides in an annulus A between the tubing T and the wall of the wellbore W as previously described.
  • the major difference between the packer 31 and packer 1 is that whereas the packer 1 has a single piston to actuate the expandable member 15 from above, the packer 31 has a piston device above and below it on the tubing T.
  • the packer 31 comprises a first fluid injection device 35, a radially expandable member 45, and a second fluid injection device 35'.
  • the fluid injection devices 35, 35' are located on either side of the radially expandable member 45.
  • the two fluid injection devices are substantially identical, but are oriented in opposite directions, to actuate the radially expandable member from either side.
  • the same reference numbers are used to designate the same component in each fluid injection device 35, 35'.
  • the upper fluid injection device 35 comprises an upper sleeve 32 that is screwed onto a thread on the tubing T at 32t.
  • the upper sleeve 32 is therefore immobilised on the tubing T.
  • the upper sleeve 32 is secured to a piston housing 36 by means of a dog 36d, and the two components together define an annulus between the outer surface of the tubing T and the inner surface of the two components 32, 36. This annulus houses the main piston and locking components of the fluid injection system.
  • the piston assembly in the upper fluid injection device 35 comprises a piston 38, a dog ring 39, and a beam spring 37.
  • the beam spring 37 has a head 37h bearing seals 37s that seal the annulus 36a between the piston housing 36 and the tubing T, and thereby contain the fluid to be injected within the annulus 36a below the head 37h.
  • the piston 38 abuts against a dog 38d that is pressed radially outwards into a recess on the inner surface of the upper sleeve 32 by a lock ring 33.
  • the lock ring 33 is held in place by means of shear screws and test pins (not shown) that are connected between the upper sleeve 32 and the lock ring 33 in a circumferential arrangement of recesses 32a, 33a. Only one pair of recesses is shown in the drawings, but all recesses spaced around the circumference of the packer are identical.
  • the shear screws and test pins disposed alternately in each respective pair of recesses differ only in that the shear pins are adapted to shear along the shear line between the two recesses 32a, 33a, whereas the test pins will resist shear forces.
  • the number and shear strength of shear screws provided can be varied according to the circumstances and pressures required.
  • Each recess can contain either a test pin or a shear screw.
  • the lock ring 33 is sealed to each side of the annulus by means of seals 33s, and also has an energised circlip 33c compressed into a recess on the outer surface of the lock ring by the inner surface of the upper sleeve 32.
  • a port 40 is provided through the wall of the tubing T, and the packer 31 is located so that the port 40 is straddled by the seals 33s and 38s on the lock ring 33 and piston 38 respectively.
  • the body lock ring 34 On the lower end of the inner surface of the upper sleeve 32, there is an internal ratchet face against which is disposed a body lock ring 34, between the upper sleeve 32 and the piston 38.
  • the body lock ring 34 has a coarse external ratchet face that engages with the ratchet face inside the upper sleeve 32, so as to restrict downward movement of the body lock ring 34 relative to the upper sleeve 32.
  • the body lock ring can simply be secured immovably to the inner face of the upper sleeve 32 by means of a screw thread.
  • the inner bore of the body lock ring has a finer ratchet 34r face that engages with an opposing ratchet 38r face on the outer surface of the piston 38, so that when the two ratchet faces 34r, 38r are engaged, the piston 38 cannot move upwards relative to the body lock ring 34 and the upper sleeve 32, and can only move downwards in the direction of the arrow X.
  • the packer 31 is shown disposed on a raised area of tubing T, but they can optionally be fitted onto any suitable length of tubing T.
  • the fluid injection device 35' at the lower end of the packer 31 is substantially identical, but is arranged in the opposite direction to the fluid injection device 35.
  • the body lock ring 34'and the piston 38' in the lower sleeve 32' are restricted by the ratchet devices of the serrations 34t, 34r, 38r, and the piston 38 can only move upwards in the direction of arrow X'.
  • conduit rings 41 and 41' respectively at upper and lower end of the radially expandable member 45.
  • the conduit rings 41 , 41' each have a circumferential arrangement of narrower conduits 41c for injection of fluid from the annulus 36a of each piston into the radially expandable member 45.
  • the arrangement of the radially expandable member 45 is substantially identical to the member 15 described in the first embodiment, having a bladder 46 to contain fluid 49, a resilient, compressible pad 47 on the outer surface of the bladder 46, and upper 48 and lower 48' support cups/fingers on the outer surface of the pad 47.
  • the pad 47 is securely attached and sealed to the upper and lower conduit rings 41 , 41' respectively, for example by gluing, moulding or welding etc.
  • the packer 31 Before being set, the packer 31 is first pressure tested with the test pins in place in order to prevent actuation of the packer 31. After testing, the test pins are removed from the apertures 32a, 33a.
  • the pressure in the tubing T is increased to a predetermined amount sufficient to shear the shear screws in the apertures 32a, 33a.
  • the shear screws shear, the pressure in the tubing T forces the lock ring 33 upwards, which allows the circlip 33c to expand radially into the recess 32r and thereby secures the lock ring in the upward position.
  • This upward movement of the lock ring 33 means that the dog 38d is no longer supported on its radially inner face, which allows the dog 32d to move radially inward out of the recess, thereby disengaging the piston 38 from the upper sleeve 32.
  • the downward force of the piston 38 is transmitted to the beam spring 37, and to the head 37h, thereby comprising the fluid in the annulus 36a, and forcing it through the conduits 41c and into the annulus 46a in the radially expandable member 45.
  • the force applied to the piston by the initial setting pressure also energises the beam springs 37, 37', and the stored energy in the compressed springs is maintained and released automatically to compensate for slight losses of sealing integrity over time.
  • the fluid used for inflating the expandable member 45 is the same as that used for inflating the first embodiment, although other types of inflation medium can of course be used.
  • the second embodiment of the packer can be set by hydraulic means using only the pressure differentials in the tubing T. After the initial setting procedure has been completed and the pressure differential is removed from the pistons, the expanded configuration of the expandable member 45 will be maintained by the ratchets. If at any time after the initial setting procedure has been completed, the seal across the annulus A is judged to be deficient, the pressure differential can be reapplied (or increased) in order to expand the radially expandable member 45 still further, and to enhance the seal across the annulus A.
  • FIG. 14 a further embodiment of a packer 50 in accordance with the invention is shown.
  • the lower end of the packer is shown in figure 9
  • the upper end of the packer closest to the wellhead is shown in figure 14, with intermediate sections in the remaining figures.
  • the packer 50 is mounted on tubing T as with earlier embodiments, and has conventional tubing connectors above and below the packer in order to connect the packer into a conventional tubing string in the well.
  • the packer 50 has a radially expandable member 55, with a bladder 56 and a resilient pad 57, in common with earlier embodiments.
  • the bladder 56 is inflated with fluid 59 as with earlier embodiments, injected into the bladder 56 from an annular piston chamber 58.
  • the mechanism of actuation of the packer 50 is slightly different to the earlier embodiments, as will now be described.
  • the radially expandable member 55 is actuated in the packer 50 by a differential in the hydrostatic pressure in a hydrostatic chamber at the lower end of the packer 50.
  • the lower end of the packer 50 has an outer hydrostatic housing 61 surrounding a hydrostatic mandrel 63, between which an annular hydrostatic chamber 62 is created.
  • the hydrostatic chamber 62 is sealed at its lower end by a seal sub 64.
  • the hydrostatic mandrel 63 is located radially in between the hydrostatic housing 61 and the tubing T, and shoulders on a step on the tubing T, so that the hydrostatic mandrel 63 can be withdrawn from the annular hydrostatic chamber 62 by removing the seal sub 64, but its upward travel along the outer surface of the tubing is restricted by the shoulder.
  • the hydrostatic chamber 62 is filled with fluid at atmospheric pressure.
  • the outer hydrostatic housing 61 is connected via screw threads at its upper end to locking sleeves 66, 69, which in turn are connected via screw threads to a beam spring 80.
  • One of the locking sleeves 66 is keyed by a dog 65 to the tubing T, so that the whole assembly of the hydrostatic housing 61 , the locking sleeves 66 and 69, and the beam spring 80 are all secured against motion relative to the tubing T while the dog 65 is engaged between the locking sleeve 66 and the tubing T.
  • the other locking sleeve 69 has a ratchet device 67, which engages with a wicker thread on the outer surface of the tubing T, in order to permit upward movement of the outer housing assembly, but prevent downward movement relative to the tubing T.
  • the dog 65 is radially supported from beneath by a support dog 68, which in turn is prevented from inward radial movement by a lower release sleeve assembly 7Ol located on the inner surface of the tubing T.
  • the lower release sleeve assembly 7Ol comprises a release sleeve 71 , a locking sleeve 72, and a release mandrel 73 that engages with the release sleeve 71 by means of a collet 74.
  • the release sleeve assembly 7Ol is connected to a wash pipe p for deployment of the packer, and when the packer is being run into the well in its inactive configuration, the wash pipe and release sleeve assembly is in the configuration shown in fig 10, with the release sleeve 71 below the locking sleeve 72, and connected thereto by means of a shear pin, and with the collet 74 engaged beneath the lower end of the release sleeve 71.
  • the support dog 68 is radially supported by the release mandrel 73, which keeps the dog 65 engaged between the tubing T and the outer housing, thereby preventing relative movement of the two.
  • the wash pipe p which is connected to surface, is pulled up, thereby forcing the collet 74 against the lower surface of the release sleeve 71 , which eventually shears the shear pin connecting the release sleeve 71 to the locking sleeve 72.
  • This enables the mandrel 73 and release sleeve 71 to move up the bore of the tubing along with the wash pipe p, relative to the locking sleeve 72, which remains stationary, being locked to the tubing T by means of leaf spring that pulls the support dog 68 radially inwards.
  • the sloped outer surface of the release mandrel 73 moves upwards relative to the support dog 68, which moves radially inwards under the force of the leaf spring. This enables the dog 65 to move radially inwards, thereby disconnecting the tubing T from the outer housing 61 , 66, 69, 80, and permitting relative movement of the two.
  • the outer housing 61 is free to move upwards relative to the stationary hydrostatic mandrel 63, and the fluid at atmospheric pressure within the hydrostatic chamber 62 is compressed by the pressure differential across the seals on the seal sub 64, created by the high pressure outside the tool in the wellbore, until the pressure differential decreases to zero, or the upper surface of the seal sub 64 reaches the upper end of the hydrostatic chamber 62.
  • This upward movement of the outer housing 61 drives the locking sleeves 66, 69, and the beam spring 80 up the outer surface of the tubing T.
  • the ratchet device 67 on the locking sleeve 69 engages with the wicker thread on the outer surface of the tubing T, so as to restrict the relative movement to the direction of arrow X.
  • the radially expandable member 55 is shown in figs 13 and 14 in its stretched configuration for running into the hole.
  • the upper end of the radially expandable member 55 is connected to an outer housing assembly 90, which is keyed to the tubing T by dog 91.
  • the dog 91 is prevented from disengaging from the tubing T by means of a piston ring 92, which is sealed in an annular chamber 93, and is prevented from axial movement within the annular chamber 93 by means of a snap ring 94.
  • the lower side of the piston ring 92 is exposed to the pressure of the bladder 56, and at low bladder pressures the snap ring 94 maintains the piston ring 92 in the locked position within the annular chamber 93, thereby keeping the upper housing assembly 90 axially fixed relative to the tubing T.
  • Dog 95 is maintained in its radially outward position by an upper release sleeve assembly 7Ou, which functions in exactly the same way as the lower release sleeve assembly 7Ol previously described.
  • the bladder 56 is in fluid communication with the piston chamber 58, in which the fluid 59 is stored.
  • the piston chamber 58 contains a transfer piston 100 that is movable within the annular chamber 58 formed between the tubing T and the housing 85 in order to accommodate changes in the volume of the fluid 59 within the chamber 58 during running in.
  • an interlock device is keyed to the housing 80 and to the tubing T by dogs 105o and 105i.
  • the dogs are maintained in the engaged position is shown in fig 12 by means of an interlock sleeve 110 which is restrained on the housing 85 against axial movement by means of a shear pin.
  • the beam spring 80 is initially axially spaced from the interlock device, and held in that spaced configuration by means of the dog 65 held by the lower release sleeve assembly 70I.
  • the dog 65 disengages from the locking sleeve 66, and frees the lower assembly 61 , 66, 69, 80 to move upwards along the tubing T as the fluid within the hydrostatic chamber 62 is compressed as a result of the pressure differential.
  • This upward movement pushes the beam spring 80 axially upwards against the interlock sleeve 110, which shears the shear pin connecting to the outer housing 85, and moves axially upwards relative to the tubing T.
  • the piston ring 92 is moved axially upwards within the chamber 93 until the lower end of the piston ring 92 is above the dog 91 , at which point, the dog 91 is free to move out of engagement with the tubing T, thereby releasing the upper assembly 90 from the tubing T.
  • the fluid held at atmospheric pressure within the upper chamber 95 is compressed by the pressure differential exerted by the high wellbore pressure outside the housing, and this forces the upper assembly 90 to move axially down the outer surface of the tubing T.
  • a body lock ring 96 restricts axial movement of the upper assembly 90 to the direction of arrow y. This mechanism provide a useful post setting adjustment facility for the packer 50, so that transient fluctuations in the bladder pressure, which might lead to loss of seal integrity between the pad 57 and the borehole wall, can be accommodated.
  • the packer 50 is loaded by the beam spring 80 from beneath and by the upper assembly 90 from above, both of which react to different stimuli in order to vary their loading.
  • the beam spring 80 is an example of a mechanical loading device that applies continuous load to the radially expandable device 55 throughout the setting process.
  • the upper assembly 90 can be used to apply additional loading from hydrostatic forces in response to variations in the pressure in the bladder 56.
  • Embodiments of the invention can enable packers that are less temperature sensitive than existing packers, as the expandable member can be expanded after setting to accommodate any shrinkage due to temperature fluctuations in the set packer.
  • Most versions will be concentric with respect to the pipe T, but certain embodiments can be made eccentric, with a larger expansion at one side of the pipe.
  • Long term curing rubber or rubber foam are very useful fluids for inflation in certain embodiments.
  • the curing agent can be omitted altogether, so that the inflation medium remains as a fluid indefinitely, but in some cases, the curing agent can be added to enable setting of the fluid within a long time frame that allows enough time for adjustment after setting in order to accommodate leaks.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)

Abstract

La présente invention concerne une garniture pour puits de gaz de pétrole ou d'eau. Il est constitué d'un élément à expansion radiale permettant d'occlure un espace annulaire entre le cuvelage et le train de tiges portant la garniture. Cette garniture comporte une chambre à fluide, un dispositif d'injection de fluide conçu pour injecter du fluide dans la chambre à fluide de façon à provoquer l'expansion de l'élément à expansion radiale, et un dispositif anti-retour pour empêcher le reflux du fluide de la chambre à fluide après l'injection, et ainsi entretenir l'expansion de l'élément à expansion radiale à l'intérieur de l'espace annulaire. Ce dispositif anti-retour peut être un élément à encliquetage ou un élément de robinetterie.
PCT/GB2006/003361 2005-09-14 2006-09-12 Garniture WO2007031723A2 (fr)

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
GB0518686.1 2005-09-14
GB0518686A GB0518686D0 (en) 2005-09-14 2005-09-14 Packer
GB0612899A GB0612899D0 (en) 2006-06-29 2006-06-29 Packer
GB0612899.5 2006-06-29

Publications (2)

Publication Number Publication Date
WO2007031723A2 true WO2007031723A2 (fr) 2007-03-22
WO2007031723A3 WO2007031723A3 (fr) 2007-05-31

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Cited By (16)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7703539B2 (en) 2006-03-21 2010-04-27 Warren Michael Levy Expandable downhole tools and methods of using and manufacturing same
CN102155251A (zh) * 2011-02-28 2011-08-17 河南理工大学 一种水力封孔器
GB2483856A (en) * 2010-09-21 2012-03-28 Caledyne Ltd Inflatable packer
CN102493777A (zh) * 2011-12-14 2012-06-13 中国石油天然气股份有限公司 液压释放堵塞器
EP2565369A1 (fr) * 2011-08-31 2013-03-06 Welltec A/S Barrière annulaire dotée d'un dispositif de compensation
US20130087322A1 (en) * 2010-06-22 2013-04-11 Inflatable Packers International Pty Ltd Inflatable packer and control valve
WO2013090257A1 (fr) * 2011-12-13 2013-06-20 Schlumberger Canada Limited Alimentation d'un élément qui comporte un matériau thermiquement dilatable
US8789612B2 (en) 2009-11-20 2014-07-29 Exxonmobil Upstream Research Company Open-hole packer for alternate path gravel packing, and method for completing an open-hole wellbore
US9127533B2 (en) 2010-12-17 2015-09-08 Welltec A/S Well completion
US10253605B2 (en) 2012-08-27 2019-04-09 Halliburton Energy Services, Inc. Constructed annular safety valve element package
CN109799081A (zh) * 2019-02-20 2019-05-24 中国石油集团川庆钻探工程有限公司 封隔器试验装置及使用方法
WO2019221847A1 (fr) * 2018-05-18 2019-11-21 Baker Hughes, A Ge Company, Llc Dispositif attachable et détachable et procédé
US10494910B2 (en) 2009-05-27 2019-12-03 Morphpackers Limited Active external casing packer (ECP) for frac operations in oil and gas wells
EP2031181B1 (fr) * 2007-09-01 2021-06-23 Weatherford Technology Holdings, LLC Renforceur d'une garniture d'étanchéité
CN114439409A (zh) * 2020-11-06 2022-05-06 中国石油化工股份有限公司 封隔器
GB2604889A (en) * 2021-03-17 2022-09-21 Bernard Lee Paul Packer apparatus

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN108222857B (zh) * 2017-04-17 2019-08-20 中国石油化工股份有限公司 一种注水井管柱减振防磨补偿器及方法

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US3059695A (en) * 1960-03-07 1962-10-23 Jersey Prod Res Co Drill stem testing device
US3460625A (en) * 1967-04-14 1969-08-12 Schlumberger Technology Corp Methods and apparatus for bridging a well conduit
US5220959A (en) * 1991-09-24 1993-06-22 The Gates Rubber Company Gripping inflatable packer
WO2000034616A1 (fr) * 1998-12-09 2000-06-15 Devico As Appareil de forage dirige

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US2942669A (en) * 1957-11-29 1960-06-28 Jersey Prod Res Co Inflating pump for oil well packers
US3059695A (en) * 1960-03-07 1962-10-23 Jersey Prod Res Co Drill stem testing device
US3460625A (en) * 1967-04-14 1969-08-12 Schlumberger Technology Corp Methods and apparatus for bridging a well conduit
US5220959A (en) * 1991-09-24 1993-06-22 The Gates Rubber Company Gripping inflatable packer
WO2000034616A1 (fr) * 1998-12-09 2000-06-15 Devico As Appareil de forage dirige

Cited By (22)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7703539B2 (en) 2006-03-21 2010-04-27 Warren Michael Levy Expandable downhole tools and methods of using and manufacturing same
EP2031181B1 (fr) * 2007-09-01 2021-06-23 Weatherford Technology Holdings, LLC Renforceur d'une garniture d'étanchéité
US10494910B2 (en) 2009-05-27 2019-12-03 Morphpackers Limited Active external casing packer (ECP) for frac operations in oil and gas wells
US8789612B2 (en) 2009-11-20 2014-07-29 Exxonmobil Upstream Research Company Open-hole packer for alternate path gravel packing, and method for completing an open-hole wellbore
US20130087322A1 (en) * 2010-06-22 2013-04-11 Inflatable Packers International Pty Ltd Inflatable packer and control valve
GB2483856A (en) * 2010-09-21 2012-03-28 Caledyne Ltd Inflatable packer
US9127533B2 (en) 2010-12-17 2015-09-08 Welltec A/S Well completion
CN102155251A (zh) * 2011-02-28 2011-08-17 河南理工大学 一种水力封孔器
EP2565369A1 (fr) * 2011-08-31 2013-03-06 Welltec A/S Barrière annulaire dotée d'un dispositif de compensation
WO2013030284A1 (fr) * 2011-08-31 2013-03-07 Welltec A/S Barrière annulaire à dispositif de compensation
WO2013090257A1 (fr) * 2011-12-13 2013-06-20 Schlumberger Canada Limited Alimentation d'un élément qui comporte un matériau thermiquement dilatable
CN102493777A (zh) * 2011-12-14 2012-06-13 中国石油天然气股份有限公司 液压释放堵塞器
US10253605B2 (en) 2012-08-27 2019-04-09 Halliburton Energy Services, Inc. Constructed annular safety valve element package
US10577889B2 (en) 2012-08-27 2020-03-03 Halliburton Energy Services, Inc. Constructed annular safety valve element package
WO2019221847A1 (fr) * 2018-05-18 2019-11-21 Baker Hughes, A Ge Company, Llc Dispositif attachable et détachable et procédé
US10822898B2 (en) 2018-05-18 2020-11-03 Baker Hughes, A Ge Company, Llc Settable and unsettable device and method
GB2589228A (en) * 2018-05-18 2021-05-26 Baker Hughes Holdings Llc Settable and unsettable device and method
AU2019271866B2 (en) * 2018-05-18 2021-08-05 Baker Hughes Holdings Llc Settable and unsettable device and method
GB2589228B (en) * 2018-05-18 2022-06-08 Baker Hughes Holdings Llc Settable and unsettable device and method
CN109799081A (zh) * 2019-02-20 2019-05-24 中国石油集团川庆钻探工程有限公司 封隔器试验装置及使用方法
CN114439409A (zh) * 2020-11-06 2022-05-06 中国石油化工股份有限公司 封隔器
GB2604889A (en) * 2021-03-17 2022-09-21 Bernard Lee Paul Packer apparatus

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