EP2650468A2 - Bouchon de fond de trou - Google Patents

Bouchon de fond de trou Download PDF

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Publication number
EP2650468A2
EP2650468A2 EP13163387.7A EP13163387A EP2650468A2 EP 2650468 A2 EP2650468 A2 EP 2650468A2 EP 13163387 A EP13163387 A EP 13163387A EP 2650468 A2 EP2650468 A2 EP 2650468A2
Authority
EP
European Patent Office
Prior art keywords
borehole
throughbore
typically
downhole plug
mechanical anchoring
Prior art date
Legal status (The legal status 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 status listed.)
Withdrawn
Application number
EP13163387.7A
Other languages
German (de)
English (en)
Other versions
EP2650468A3 (fr
Inventor
Paul Hilliard
Jeffrey Paul Knight
Dominic Michael Hoben
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
WellTools Ltd
Original Assignee
WellTools Ltd
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
Application filed by WellTools Ltd filed Critical WellTools Ltd
Publication of EP2650468A2 publication Critical patent/EP2650468A2/fr
Publication of EP2650468A3 publication Critical patent/EP2650468A3/fr
Withdrawn legal-status Critical Current

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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
    • E21B33/129—Packers; Plugs with mechanical slips for hooking into the casing
    • 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
    • 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
    • E21B33/129—Packers; Plugs with mechanical slips for hooking into the casing
    • E21B33/1291—Packers; Plugs with mechanical slips for hooking into the casing anchor set by wedge or cam in combination with frictional effect, using so-called drag-blocks
    • E21B33/1292—Packers; Plugs with mechanical slips for hooking into the casing anchor set by wedge or cam in combination with frictional effect, using so-called drag-blocks with means for anchoring against downward and upward movement
    • 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
    • E21B33/129—Packers; Plugs with mechanical slips for hooking into the casing
    • E21B33/1294—Packers; Plugs with mechanical slips for hooking into the casing characterised by a valve, e.g. a by-pass valve
    • 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
    • E21B33/129—Packers; Plugs with mechanical slips for hooking into the casing
    • E21B33/1295—Packers; Plugs with mechanical slips for hooking into the casing actuated by fluid pressure

Definitions

  • This invention relates to an apparatus and method for the control of fluids in an oil and/or gas well, typically in the form of a downhole plug used to close the wellbore.
  • the production of oil and/or gas from a downhole well involves drilling of a borehole through a formation containing production fluids, typically oil or gas, to be recovered through the borehole.
  • production fluids typically oil or gas
  • the upper lengths of borehole are drilled and then typically cased with a tubular casing cemented in place to prevent inward collapse of the walls of the borehole.
  • Drilling operations then resume using a narrower diameter drill bit deployed through the casing, which drills a further length of the borehole into the formation below the casing.
  • Sequential radial steps in the inner diameter of the borehole can be formed in this manner, until the production zone of the reservoir is reached, and the production fluids can be recovered using a production string of tubulars deployed through the radially stepped central bore of the casing.
  • Drilling fluid also sometimes called drilling mud
  • Drilling fluid usually comprises a dense liquid, which helps to contain the reservoir fluids within the borehole, and has many other functions, such as lubricating the bit, and washing entrained cuttings back to surface.
  • Typical simple drilling fluids can include water, but often drilling fluids are highly engineered fluids with a high density designed to resist blowouts and other undesirable pressure changes as the drillbit cuts through the formation.
  • cavities in the formation can present significant challenges for well control, particularly affecting the practice of pumping well control fluids such as drilling fluid through the drillstring in order to control wellbore pressures.
  • Certain large cavities have such a high volume that the drilling fluid pumped into them simply flows away from the borehole through the cavity or is otherwise lost from the borehole, and is then ineffective to control the wellbore pressure changes, and to perform its other functions.
  • Without reliable pressure control, such a well often has to be plugged and abandoned, and an alternative path must be drilled, typically by side-tracking out of the existing borehole above the cavity.
  • Embodiments of the present invention typically provide a wellbore plugging tool and a method for plugging a wellbore.
  • a downhole plug for plugging a borehole in an oil or gas well comprising:
  • the body has a central axial throughbore, and has upper and lower connections at opposite ends of the body, communicating with the throughbore, and adapted to connect the body to a string of tubulars within the well.
  • the downhole plug is run within a drillstring, above a bottom hole assembly, and typically within a cased borehole.
  • the body is adapted to operate within conventional sizes of casing, for example casing with an outer diameter (OD) of 9 5/8 inch, 7 inch and 5 - 51 ⁇ 2 inch.
  • the downhole plug may be referred to as a tool.
  • the mechanical anchoring device is provided on the outer surface of the body of the tool, and is adapted to expand the anchoring member radially into contact with the inner surface of the casing in which the tool is being run.
  • the outer surface of the mechanical anchoring device has gripping formations adapted to grip the inner surface of the casing and resist axial movement of the body of the tool when the mechanical anchoring device is engaged.
  • the gripping formations can comprise teeth, or other abrasive or high friction formations or materials, which bite into the inner surface of the borehole, typically into the inner surface of the casing.
  • the mechanical anchoring device comprises one or more wedge devices typically in the form of slips or the like having tapered surfaces adapted to expand the radial dimensions of the anchoring member as a result of relative axial movement of the slips.
  • the slips are moved axially by an actuator of the mechanical anchoring device that moves axially relative to the body of the tool, and which typically takes the form of a piston.
  • the mechanical anchoring device comprises pairs of opposed slips, typically having opposed tapers on upper and lower axial facing surfaces of the anchoring member.
  • the anchoring member is typically in the form of a grapple device having collet fingers attached to the mechanical anchoring device in a cantilever manner, allowing the free ends of the fingers to move radially outwards from the axis of the body into contact with the inner surface of the borehole.
  • the other ends of the fingers are connected by a ring.
  • the mechanical anchoring device resists axial movement of the body of the tool in both axial directions across the device.
  • the mechanical anchoring device is adapted to expand as a result of axial force in either direction.
  • the annular sealing device comprises a resilient sleeve adapted to radially expand on an outer surface of the body, typically as a result of axial movement of an actuator relative to the resilient sleeve.
  • the resilient sleeve seals against the inner surface of the casing, substantially preventing fluid flow through the annulus between the inner surface of the casing and the outer surface of the body.
  • the annular sealing device is actuated by an actuating mechanism which changes the configuration of the annular sealing device between a first configuration, in which the resilient sleeve is radially unexpanded and does not engage the walls of the borehole, and a second configuration, in which the resilient sleeve has radially expanded to seal between the inner surface of the borehole (e.g. the casing) and the outer surface of the body.
  • the actuator mechanism causes axial sliding of different body parts relative to one another between the first and second configurations, typically compressing the ends of the resilient sleeve together, and causing the outward radial expansion of the resilient sleeve.
  • the annular sealing device is activated by setting weight down on the body from the surface, and can be de-activated by picking up weight on the body.
  • the annular sealing device resists fluid passage within the annulus in both directions across the device.
  • the annular sealing device is adapted to expand as a result of axial force in either direction.
  • the annular sealing device is moved from the radially unexpanded configuration to its radially expanded sealing configuration by setting weight down on the tool after the mechanical anchoring device has been activated and the body is locked in a fixed axial position within the borehole.
  • the throughbore plugging device comprises a plugging member adapted to engage on a seat within the throughbore in the body.
  • the throughbore plugging device has a sealing arrangement, typically in the form of an annular seal set in the inner surface of the throughbore adjacent to the seat, typically above the seat, and typically arranged such that when the throughbore plugging member is engaged with the seat, it is sealed against the annular sealing member in order to close the throughbore, and resist fluid passage through the throughbore.
  • the throughbore plugging device substantially prevents fluid passage through the throughbore of the body.
  • the throughbore plugging device resists fluid passage through the throughbore in both axial directions across the device.
  • the invention also provides a method of controlling fluids within a borehole of an oil or gas well, the method comprising:
  • the mechanical anchoring device may comprise an anchoring member on an outer surface of the body and the borehole may have an inner surface.
  • the step of activating the annular sealing device may include sealing the annulus between the outer surface of the body and the inner surface of the borehole.
  • the annular sealing device may be moved from a radially unexpanded configuration to a radially expanded sealing configuration by setting weight down on the well control device after the mechanical anchoring device has been activated and the body is locked in a fixed axial position within the borehole.
  • the step of activating the mechanical anchoring device includes expanding the mechanical anchoring device.
  • compositions, an element or a group of elements are preceded with the transitional phrase "comprising”, it is understood that we also contemplate the same composition, element or group of elements with transitional phrases “consisting essentially of”, “consisting”, “selected from the group of consisting of”, “including”, or “is” preceding the recitation of the composition, element or group of elements and vice versa.
  • apparatus for controlling the flow of fluid in a borehole in the form of a downhole plug has a body B, provided with a throughbore T extending between opposite ends of the body B, the two ends of the body B having box and pin connectors as are known in the art for connecting the body B into a string of tubulars in an oil or gas well.
  • the body B is connected within a drill string D, typically above a bottom hole assembly and drill bit, and is typically run into a wellbore within a casing string C, terminating at the lower end of the casing string with a casing shoe through which the drill string D is deployed.
  • the body B can have stabilisers and/or centralisers on its outer surface in order to space the body B away from the walls of the casing C.
  • the upper end of the plug nearest the well head and the surface is shown on the left, and the lower end is shown on the right, closest to the bottom of the well, although the skilled person will understand that in deviated wells, the "upper” end can be at the same depth or physically deeper than the “lower” end as a result of deviation of the borehole, so the terms “up”, “down”, “upper” and “lower” refer the depth of penetration in the borehole, rather than the actual depth below the wellhead and similar terms should be interpreted accordingly.
  • the body B comprises a plug sub 10 comprising a throughbore plugging device, a seal sub 30 comprising an annular sealing device, and an anchor sub 50 comprising a mechanical anchoring device, all of which are sequentially arranged from an upper part of the body B to a lower part but, in other embodiments, the order of the subs 10, 30, 50 can be changed.
  • the plug sub 10 has an outer housing 11 formed in three sections 11a, 11b and 11c, having screw thread connections between the end housing portions 11a and 11c and the central housing portion 11b, typically also allowing metal to metal seals to be formed between the housing portions.
  • the assembled housing 11 has a throughbore T which houses a sliding sleeve 12 which is biased upwardly within the bore T by a spring 13 held in compression between an upwardly facing end of the central portion 11b, and the downwardly facing surface of a dog collar 15 disposed in the annulus between the outer surface of the sleeve 12 and the inner surface of the upper portion of housing 11a.
  • the dog collar 15 has a series of circumferentially spaced recesses typically spaced substantially equidistantly around the circumference, and typically passing radially through the wall of the collar 15, to receive dogs 16, which are typically adapted to move radially outward from the collar to locate within an annular dog recess 17 in the outer surface of the sleeve 12.
  • the sleeve 12 has a shear pin recess 18 adapted to receive the inner end of at least one shear pin 20 passing through the body of the upper portion 11a of the housing, which serves to keep the sleeve 12 fixed axially in the configuration shown in Figure 5 , with the spring 13 held in compression between the dog collar 15 and the central portion 11b of the housing.
  • the shear pins 20 are arranged in pairs around the circumference.
  • the lower portion 11c has a seal recess to house a chevron type seal 19 which is disposed (optionally in radial compression) between the inner surface of the housing portion 11c, and the outer surface of the sleeve 12.
  • a chevron type seal 19 which is disposed (optionally in radial compression) between the inner surface of the housing portion 11c, and the outer surface of the sleeve 12.
  • Other types of seal can be used in other embodiments.
  • the seal 19 is radially compressed between the sleeve 12 and the housing portion 11c, and denies fluid passage within the annular space between the housing 11 and the sleeve 12.
  • the lower portion 11c of the housing typically has a stabiliser S which is typically adapted to space the body of the plug B radially from the walls of the tubular casing.
  • the upper portion of the housing 11a has at least one radial port 21 passing through the wall of the housing 11a above the shear pins 20 connecting the throughbore T with the exterior of the plug body B.
  • the sleeve 12 is held in the position shown in Figure 5 , in which the upper end of the sleeve 12 covers the ports 21.
  • the annulus between the sleeve 12 and the housing 11 is sealed, for example by O-ring seals, located above the ports 21, and by the seals 19 below them, in order to prevent fluid passing from the throughbore T through the ports 21 and reaching the exterior of the body B when the sleeve 12 is in the Figure 5 position.
  • the ports 21 can be circumferentially spaced around the body B, typically at a 180° spacing as shown in Figure 5 .
  • the shear pins 20 can be typically circumferentially spaced around the body B, typically at substantially equidistant spacing around the circumference, or alternatively, in some configurations, some of the bores in axial alignment with the shear pin 20 can be formed as simple ports, to permit additional fluid communication between the throughbore T and the exterior of the tool.
  • the wall of the upper portion 11a has an additional radial port 22 connecting the throughbore T with the exterior of the tool in the same way as the port 21, and typically terminating on the inner surface of the housing portion 11a within a recess on the inner surface of the housing 11.
  • the spring 13 typically has a spring sleeve 14 which surrounds the outer surface of the spring 13 within the annulus between the sleeve 12 and the upper housing portion 11a, in order to restrict the maximum compression of the spring 13.
  • the upper housing portion 11a connects the sleeve 12 and the housing 11 by means of the shear pins 20, so that the dogs 16 are pressed radially inwards into the recess 17 in the housing, thereby locking the collar 15 to the sleeve 12 in the Figure 5 configuration.
  • the sleeve 12 is free to move axially downwards within the throughbore T, until the collar 15 abuts the upper edge of the spring sleeve 14, and the dogs 16 are axially aligned with the recess on the inner surface of the housing, at which point the dogs 16 are free to move radially outwardly into the recess, and typically have ramped inner surfaces adapted to facilitate that radial movement, so that they move radially clear of the sleeve 12, allowing continued downward axial movement of the sleeve 12 independently of the collar 15 within the throughbore T.
  • the sleeve 12 can move axially down the throughbore T to bottom out at the upwardly facing shoulder at the lower end of the lower portion 11c.
  • the upper end of the sleeve 12 has a seat 25 to receive and seat a throughbore sealing device such as a dart or cylinder which has a solid structure with no throughbore and is adapted to close of fluid communication within the throughbore T.
  • the throughbore sealing device may be referred to as a plugging member.
  • the dart 26 is adapted to engage on the seat 25 as will be described below and has an outer surface adapted to seal against the seal 19 when the sleeve 12 has bottomed out on the upwardly facing shoulder at the lower end of the lower portion 11c.
  • the seal 19 may be an annular seal and may be set in an inner surface of the throughbore T, adjacent to the seat 25.
  • a seal sub 30 and anchor sub 50 are connected below the lower portion 11c of the housing 11 of the plug sub 10.
  • the seal sub 30 and anchor sub 50 are shown in this embodiment as an interdependent assembly, but can typically also be provided as separate subs within the plug.
  • the seal sub 30 comprises a housing 31 having an outer diameter that is continuous with that of the housing 11, and having a throughbore T communicating with the throughbore T in the housing 11.
  • the lower end of the housing 31 has a flat shoulder abutted against a sealing member in the form of a resilient sleeve 35.
  • the resilient sleeve 35 is slid over the outer surface of an inner tubular mandrel that is connected to the lower surface of the housing 31 by means of a screw thread connection and typically by seals so that the housing 31 and the mandrel 40 essentially move as a single unit.
  • the resilient sleeve 35 is optionally adapted to slide axially and to rotate relative to the inner tubular mandrel 40, and is adapted to be deformed as will be described below from its radially un-extended configuration shown in Figures 8 to 11 , in which the outer diameter of the resilient sleeve 35 is essentially the same as the outer diameter of the housing 31 and housing 11, to a radially expanded configuration in which the outer diameter of the resilient sleeve 35 has been radially expanded away from the axis of the throughbore T, to press against the inner surface of the casing wall surrounding the body B, thereby sealing the annulus between the body B and the casing C.
  • the inner tubular mandrel 40 also supports certain components of the anchor sub 50, which are mounted on the outer surface of the inner tubular mandrel 40 in the same way as the resilient sleeve 35.
  • the anchor sub 50 comprises an anchoring member having upper and lower slips 52, 53 and a grapple sleeve 55.
  • the slips 52 and 53 are typically in the form of sleeves that are slid over the inner tubular mandrel 40, and which are rotationally and axially movable relative to the inner tubular mandrel 40 so that they slide on its outer surface.
  • the inwardly facing opposed faces of the slips 51 and 52 have tapered edges.
  • the grapple sleeve 55 is disposed on the outer surface of the upper slip 51.
  • the grapple sleeve 55 is typically in the form of a circumferential arrangement of collet fingers 56 which are attached together only at their upper ends by means of a grapple ring 57, leaving their lower ends unattached, in a cantilever arrangement, and free to move radially relative to the axis of the throughbore T.
  • the inner faces of the fingers 56 have a tapered profile at their lower ends, which is typically tapered in at least one direction, but optionally, as shown in the current example, the section profile of the lower end of the fingers 56 can have a taper in two directions, typically at an angle matching the tapered opposing ends of the slips 51 and 52.
  • a piston sleeve 41 which is received within a larger diameter portion of the lower end of the inner tubular mandrel 40, and is typically connected to the inner tubular mandrel 40 by means of shear pins 42 passing through the wall of the enlarged portion of the inner tubular mandrel 40, and locating in an annular recess at the top of the piston 41.
  • the piston 41 is typically sealed to the inner surface of the bore of the inner tubular mandrel 40, and has a throughbore allowing fluid communication with the throughbore T.
  • the shear pins 42 are typically arranged in pairs around the circumference of piston, and between adjacent pins 42, there are typically provided ports (not shown in Figure 9 ) at the same axial position, permitting fluid communication between the throughbore T and the annulus between the piston 41 and the mandrel 40.
  • the piston sleeve 41 Beneath the shear pins 42, the piston sleeve 41 includes at least one additional shear pin 43, but typically, as is shown in this arrangement, there can be several pins 43, typically arranged in a circumferentially spaced pairs, passing radially through the wall of the inner tubular mandrel 40, and terminating in slots on the outer surface of the piston 41. Seals above and below the ports in line with the pins 42 prevent fluid passage between the throughbore T and the outside of the plug while the piston 41 is held by the shear pins 42 in the upper configuration shown in Figure 9 .
  • the upper face of the piston 41 has a seat for a ball or dart etc., adapted to be dropped from surface.
  • the diameter of the seat on the piston 41 is smaller than the diameter of the seat 25 on the sleeve 12, so a smaller ball adapted to seat on the piston 41 and cause its axial movement within the large lower portion of the inner tubular mandrel 40 can pass through the seat 25 in the sleeve 12 without activating it.
  • the lower end of the inner tubular mandrel 40 has a catcher device 45 adapted to catch the piston 41 and its activating device such as a ball etc. and prevent its onward travel axially within the body B.
  • the catcher device 45 has slots extending radially through its outer walls, allowing passage of fluid through the slots 46 into the annulus between the catcher device 45 and the lower housing 54 of the anchor sub 50.
  • the outer surface of the lower housing 54 typically has a stabiliser S.
  • Axial downward movement of the piston sleeve 41 uncovers the ports in line with the pins 42, allowing fluid communication between the throughbore T and an annulus formed and sealed between the outer surface of the radially enlarged lower portion of the inner tubular mandrel 40, and the inner surface of the lower slip 52.
  • Seals for example O-ring seals
  • O-ring seals are typically provided above and below the outer opening of the ports and pins 42, so the communication of pressurised fluid from the throughbore T to the annulus between the inner tubular mandrel 40 and the lower slip 52 creates a piston effect on the lower slip resulting from the difference in the sealed diameters on the lower slip 52, causing it to move axially upwards, closing the gap between the slips 51 and 52, and thereby causing the free ends of the fingers 56 on the grapple sleeve 55 to move radially outwards, expanding until they contact and grip the inner wall of the casing C surrounding the body B.
  • the outer surfaces of the fingers 56 typically have gripping formation such as teeth, abrasive surfaces such as tungsten carbide, or resilient devices etc. adapted to increase friction between the grapple sleeve 55 and the inner surface of the casing C.
  • the angle of the taper can be adjusted to increase or decrease the extent of radial expansion of the grapple sleeve 55 in accordance with the desired annular spacing between the body B and the inner surface of the casing C.
  • dropping the ball on the piston 41 causes actuation of the grapple sleeve 55 to grip the inner surface of the casing C and resist (typically substantially prevent) axial movement of the grapple sleeve 55 within the borehole.
  • the inner surface of the lower slip 52 has a ratchet surface 58 and the inner surface of the lower slip 52 has a cooperating ratchet device 59 abutting against a downward facing shoulder on the inside of the lower slip 52, which restricts axial movement to a single direction, i.e. upwards movement of the lower slip 52 relative to the inner tubular mandrel 40. Therefore, once the lower slip 52 moves up a notch in the ratchet surface 58, it cannot move down even if the pressure that caused the initial upward movement reduces.
  • the anchoring device can typically be actuated by pressuring up within the throughbore to a significantly higher pressure than would be encountered normally, causing upward movement of the lower slip 52 in a single direction by virtue of the ratchet mechanism 58, 59 until the anchoring member comprising the grapple sleeve 55 is securely set preventing further axial movement of the portion of the string below the grapple sleeve 55.
  • the string below the set anchoring device is essentially immovably anchored by the grapple sleeve 55, but the string above the set grapple sleeve 55 is still axially moveable within the borehole. Accordingly, setting weight down from the surface on the set grapple sleeve 55 slides the housing 31 and the inner tubular mandrel 40 to which it is attached axially down relative to the set grapple sleeve 55, causing the resilient sleeve 35 to be compressed between the movable housing 31 and the upper end of the immovable upper slip 51.
  • Setting weight down in this manner typically further energises the expansion of the grapple sleeve 55 as a result of the interaction between the tapered surface at the lower end of the upper slip 51, urging the tapered inner surfaces of the fingers 56 to push them further radially outwards against the inner surface of the casing C.
  • the weight of the string from surface is transferred through the housing 31 to the inner tubular mandrel 40, causing the ratchet mechanism 58, 59 to retain the plug in the radially expanded configuration with the resilient sleeve 35 radially expanded when the weight from surface is removed.
  • the action of setting down weight from surface typically activates the annular sealing device causing the sealing member provided by the resilient sleeve 35 to seal off the annulus, typically in both directions, thereby substantially preventing fluid from passing the expanded seal provided by the resilient sleeve 35, even when the weight is removed.
  • the throughbore T is typically sealed by dropping a dart from surface, to land on the seat 25 of the sleeve 12, causing the shear pins 20 to shear, and allowing the downward travel of the sleeve 12 such that the dogs 16 move into the recess on the inner surface of the upper portion 11a of the housing, and free the sleeve 12 to travel all the way down to the bottom of the plug sub 10.
  • the dart 26 is typically engaged against the chevron seal 19, thereby preventing fluid passage within the throughbore T.
  • the plug sub is typically activated by a subsequent action performed from surface once the mechanical anchoring device and the annular sealing device have been set.
  • each step of the procedure mechanical anchoring, annular sealing, and plugging of the throughbore, can typically be independently actuated, and testing of each step can be performed before subsequent actuations of the other components.
  • plug 10 described permits mechanical anchoring within the borehole, annular sealing between the string and the borehole, and plugging of the throughbore that had previously allowed fluid transfer through the string, in order to plug the well.
  • the plug sub 10 can be provided with a disconnect device further up the string, which can optionally be of conventional design, and can typically be provided immediately above the plug sub 10, allowing disconnect of the string above the plug after its activation and testing.
  • a disconnect device further up the string, which can optionally be of conventional design, and can typically be provided immediately above the plug sub 10, allowing disconnect of the string above the plug after its activation and testing.
  • the plug can be simply left in its activated state for many years, allowing possibility to revisit the plug for reversal of the abandonment procedures if desired, or for testing and monitoring of the efficacy of the seal.
  • the well can be permanently abandoned by cementing above the set plug after setting and testing procedures have been concluded and the casing string above the plug has been recovered if desired.
  • LCMs Loss Circulation Materials
  • wood fibre such as wood fibre, calcium carbonate, ground nut shells, ground cellulose, shredded cedar fibre.
  • Other LCMs can optionally be used.
  • Loss Circulation Materials are typically pumped through a PBL tool or similar bypass to try to stem the loss of drilling fluid, and pumping of LCM through the drillstring and into the borehole normally constitutes the first attempt at resolution of borehole problems exhibiting unusually high losses of drilling fluid.
  • a PBL tool is mounted on the drillstring below the plug described above and above the Bottom Hole Assembly (BHA).
  • BHA Bottom Hole Assembly
  • pumping LCM is successful and in that situation normal drilling can resume.
  • the string is typically pulled back until the plug sub is above the casing shoe, and located within the casing string C.
  • shear pins 43 which have their radially inner ends captive in the slot formed on the outer surface of the piston sleeve 41.
  • Shear pins 43 can be provided as a single pin, or as pairs of pins, typically spaced at 180° of circumferential spacing around the piston sleeve 41 as shown in Figure 9 , but multiple pairs of shear pins can optionally be provided as shown in Figure 11 .
  • the shear pins 43 can have a higher rating than pins 42, so can retain the sleeve 41 against further axial movement at a pressure threshold that shears the weaker upper pins 42. Therefore, dropping the ball typically moves the sleeve 41 axially downwards within the bore of the anchor sub 50, until the pins 43 have reached the tops of the slots on the outer surface of the piston sleeve 41, and the ports in between the shear pins 42 have been exposed, allowing the upward movement of the lower slip 52 as a result of the differential piston area between the different diameters of seal.
  • the weight is set down in the string above the plug 10 to activate the annular sealing device to seal off the annulus between the drillstring and the casing.
  • the fluid pressure can optionally be increased within the throughbore in order to shear the shear pins 43, and drive the piston sleeve 41 into the catcher device 45, in order to regain pumping ability across the plug sub 10, by virtue of the slots 46 in the catcher device 45 allowing fluid passage in the throughbore past the catcher 45.
  • This permits continued pumping if required, and retains some ability to operate parts of the string below the activated annular sealing device and mechanical anchor. If remedial operations are unsuccessful, a decision may be taken at this time to seal the well and side track above it.
  • the dart 26 is typically dropped from surface and lands on the seat 25 on the sleeve 12, causing it to move axially down to seal off the bore by means of the chevron seals 19 interacting with the outer surface of the solid dart 26.
  • the disconnect above the plug 10 can be operated, typically by dropping a further ball onto a seat in the disconnect device as is known in the art, leaving the plug sub 10 and BHA anchored in place downhole.
  • the strings above the anchored plug sub 10 can then be pulled out of hole, and optionally cement can be pumped through the drill pipe to set a permanent plug above the packer assembly.

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  • 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)
  • Earth Drilling (AREA)
  • Piles And Underground Anchors (AREA)
EP13163387.7A 2012-04-11 2013-04-11 Bouchon de fond de trou Withdrawn EP2650468A3 (fr)

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
GBGB1206381.4A GB201206381D0 (en) 2012-04-11 2012-04-11 Apparatus and method

Publications (2)

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EP2650468A2 true EP2650468A2 (fr) 2013-10-16
EP2650468A3 EP2650468A3 (fr) 2014-09-03

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US (1) US20130292119A1 (fr)
EP (1) EP2650468A3 (fr)
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US20130292119A1 (en) 2013-11-07
GB201206381D0 (en) 2012-05-23
EP2650468A3 (fr) 2014-09-03

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