WO2019158922A1 - Perfectionnements apportés ou se rapportant à l'abandon de puits et à la récupération de fentes - Google Patents

Perfectionnements apportés ou se rapportant à l'abandon de puits et à la récupération de fentes Download PDF

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Publication number
WO2019158922A1
WO2019158922A1 PCT/GB2019/050391 GB2019050391W WO2019158922A1 WO 2019158922 A1 WO2019158922 A1 WO 2019158922A1 GB 2019050391 W GB2019050391 W GB 2019050391W WO 2019158922 A1 WO2019158922 A1 WO 2019158922A1
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WO
WIPO (PCT)
Prior art keywords
load
casing
downhole tool
piston
packer
Prior art date
Application number
PCT/GB2019/050391
Other languages
English (en)
Inventor
Michael Wardley
George Telfer
Original Assignee
Ardyne Holdings 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
Application filed by Ardyne Holdings Limited filed Critical Ardyne Holdings Limited
Publication of WO2019158922A1 publication Critical patent/WO2019158922A1/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
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • E21B23/06—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for setting packers
    • 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
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • 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

  • the present invention relates to methods and apparatus for well abandonment and slot recovery and in particular, though not exclusively, to an improved apparatus for casing recovery.
  • a difficulty in the design of such combined cutter and spear tools is that when cutting, circulation needs to be maintained with the return path in the annulus between the work string and the casing so that cuttings can return to surface, however for the circulation test this return path needs to be closed to force the return path to be through the cut and behind the casing to surface.
  • US 5,101,895 to Smith International, Inc. discloses a remedial bottom hole assembly for casing retrieval having a spear and an inflatable packer utilized in combination with a pipe cutter. With such an assembly, after the spear is set and the casing is cut, the packer can be inflated to determine if circulation can be established without the removal of the spear and pipe cutter.
  • a cut and pull spear configured to obtain multiple grips in a tubular to be cut under tension.
  • the slips are set mechanically with the aid of drag blocks to hold a portion of the assembly while a mandrel is manipulated.
  • An annular seal is set in conjunction with the slips to provide well control during the cut.
  • An internal bypass around the seal can be in the open position to allow circulation during the cut. The bypass can be closed to control a well kick with mechanical manipulation as the seal remains set. If the tubular will not release after an initial cut, the spear can be triggered to release and be reset at another location.
  • the mandrel is open to circulation while the slips and seal are set and the cut is being made. Cuttings are filtered before entering the bypass to keep the cuttings out of the blowout preventers.
  • the present Applicants have advantageously determined that a tension- set packer overcomes the disadvantages in the prior art as it is capable of sealing the annulus between the drill string and the casing both for testing and in case of a kick, while also keeping the annulus clear during cutting.
  • the present Applicants now have the TRIDENT ® system.
  • the TRIDENT ® system operates by providing an anchor to the casing, a casing cutter to cut the casing and a tension-set packer to provide a seal over the annulus between the string and casing to create a circulation path behind the casing and so aid casing recovery all in a single trip in the well bore.
  • the anchor is set to provide stability for the cutter to allow for a fixed point for an overpull to be applied to set the packer.
  • load set downhole tools i.e. weight set or tension set
  • they may have difficulties when used from floating rigs such as semi- submersibles.
  • sea swell will place tension and/or weight on the drill string and consequently there is a risk that the downhole tool is accidentally actuated by the increased load when a bass wave or lag is experienced at the floating rig.
  • heave compensators can be used, these still result in movement and the consequential variable load being applied.
  • a known method to prevent the accidental actuation of the downhole tool is to insert a shear pin rated at a higher shear force than the predicted load which may occur in operation. Actuation of the downhole tool must then be achieved with an increased load i.e. a high overpull or significant weight. While the shear pin prevents accidental actuation, it also prevents the downhole tool being re-set. Thus for the tension-set packer multiple circulation tests cannot be performed. This is a major disadvantage.
  • a resettable mechanism for preventing the accidental actuation of a load set downhole tool, the downhole tool being actuated by an operating load comprising:
  • a substantially tubular body having a central throughbore, with first and second ends; an inner actuating member, the inner actuating member being an annular body having a first end for connection to an operating member of the downhole tool;
  • a first piston arranged in a fluid filled chamber between the tubular body and the annular body, the piston being fixed to the annular body and moveable relative to the tubular body;
  • the first piston creating an upper chamber and a lower chamber on respective sides of the first piston
  • the first piston including a valve mechanism comprising a first valve, operable at a first fluid pressure applied from the upper chamber to the lower chamber, and a second valve, operable at a second fluid pressure applied in reverse, which is less than the first fluid pressure, each biased in opposing directions and providing an actuable through passage between the upper and lower chambers, so that:
  • the first and second valves are closed and the fluid in the upper chamber prevents movement of the inner actuating member until a first load is applied in a first direction; and in a second configuration the fluid in the upper chamber prevents movement of the inner actuating member until a second load is applied in a second direction; and wherein
  • the first load is greater than a combined load of the operating load and a piston load
  • the second load is applied in reverse to the first load.
  • the piston load can be set by the calculated area of the piston together with the pressure rating of the first valve.
  • the first piston is set to move only when a load greater than the highest accidental load which may be experienced by the downhole tool, in use, is applied .
  • the mechanism can be reset by reversing the load i.e. if a reduction in tension applied by setting down weight or if weight applied by pulling to apply tension.
  • the load required to reset i.e. the second load can also be much smaller than the first load.
  • the second load can be set by the pressure rating of the second valve.
  • the first valve is a high pressure relief valve.
  • the first valve is operable at a first fluid pressure of 5000 psi (3.4xl0 7 Nm 2 ) or greater.
  • the second valve is a check valve.
  • the second valve is operable at a second fluid pressure of 5 psi (3.4xl0 4 Nm 2 ) or greater.
  • the fluid in the chamber is oil.
  • debris laden mud is isolated from the valves.
  • a floating piston is disposed in the lower chamber providing an equalisation chamber which includes a port through the tubular body.
  • the floating piston ensures pressurisation of the closed oil filled chamber as the tool is run to depth.
  • a method of controlled actuation of a load set downhole tool comprising the steps:
  • the downhole tool is prevented from actuating until a load greater than its operating load plus the piston load is applied and then the mechanism can be reset so that the downhole tool may be actuated any number of times.
  • the first direction may be downstream so that the downhole tool is a tension set tool.
  • the first direction may be upstream so that the downhole tool is a weight set tool.
  • the method includes repeating steps (c) and (d) to repeatedly actuate the downhole tool.
  • a high overpull mechanical tension-set retrievable packer configured to seal to casing or a downhole tubular, comprising:
  • a substantially cylindrical body having a central throughbore, with first and second ends including connection means for mounting in a string; a mandrel which is configured to be axial moveable relative to a tubular body;
  • a resettable mechanism according to the first aspect wherein the mandrel is connected to the inner actuating member.
  • An upward force or tension applied to the string axially may move the mandrel relative to the tubular body.
  • the axial movement of the mandrel relative to the cylindrical body in the first direction may actuate and set the mechanical tension-set retrievable packer.
  • the axial movement of the mandrel relative to the cylindrical body in the second direction may de- actuate the mechanical tension-set retrievable packer.
  • the packer element may be made from any material capable of radially expanding when it is axially compressed such as rubber.
  • a pull of approx. 130,000lbs is required. With a piston area of say 20 sq. inches and a pressure relief valve set at 5,000psi, you need to pull 100,000lbs to allow oil through the valve plus at least 30,000 lbs to start the further compression of the disc springs. To unset the packer you simply slack off and the strong disc springs will ensure that the oil will return through the weak check valve.
  • the axial movement of the mandrel relative to the cylindrical body in the first direction radially expands the packer element. The radially expansion of the packer element may seal the wellbore. The axial movement of the mandrel relative to the cylindrical body in the second direction allows the packer to contract radially.
  • the mechanical tension-set retrievable packer comprises at least one port configured to be in fluid communication with the annulus of the casing and/or downhole tubular.
  • the at least one port may be configured to allow fluid communication between the throughbore and the annulus of the casing and/or downhole tubular below the mechanical tension-set retrievable packer.
  • the axial movement of the mandrel relative to the cylindrical body in the first direction may open the at least one port.
  • the axial movement of the mandrel relative to the cylindrical body in the second direction may close the at least one port.
  • the method includes cycling steps (c) and (d) to repeatedly set and unset the mechanical tension-set retrievable packer.
  • an anchor mechanism configured to grip a section of casing or a downhole tubular in a wellbore; the mechanical tension-set retrievable packer;
  • a casing cutter configured to cut the tubular
  • anchor mechanism is located between the mechanical tension-set retrievable packer and the casing cutter.
  • the casing cutting and removal assembly may further comprise a drill, the drill being located at a distal end of the casing cutting and removal assembly. Mounting a drill bit on the end of the casing cutting and removal assembly allows initial dressing of a cement plug prior to casing cutting being achieved on the same trip into the wellbore.
  • the casing cutting and removal assembly may further comprise a bridge plug, the bridge plug being located at a distal end of the casing cutting and removal assembly. Mounting a bridge plug on the end of the casing cutting and removal assembly allows setting of a bridge plug in the casing prior to casing cutting being achieved on the same trip into the wellbore.
  • the drill or bridge plug may be hydraulically or pneumatically actuated. In this way the drill or bridge plug can be operated from surface without actuation of the anchor mechanism, mechanical tension-set retrievable packer or the casing cutter.
  • the method may comprise the step of determining circulation behind the cut tubular at surface. This provides a positive circulation test and the cut tubular section, preferably a casing section, can be removed.
  • the method includes the further steps of unsetting anchor mechanism, actuating the anchor mechanism to grip the cut tubular section at an upper location on the tubular, and removing the cut tubular section from the wellbore.
  • the method then comprises the further steps of unsetting anchor mechanism, locating the casing cutter at a higher position on the tubular and repeating the steps (b) to (f). This can be repeated until a positive circulation test occurs and a section of cut tubular can be removed from the wellbore.
  • Figures 1A and IB are sectional views of a resettable mechanism in first and at second configurations, respectively, for use with a load set downhole tool operated by tension on a spring according to an embodiment of the present invention
  • Figures 2A and 2B are sectional views of a mechanical tension-set retrievable packer for use with the resettable mechanism of Figures 1A and IB, in unset and set states, respectively, according to an embodiment of the present invention.
  • FIGS 3A to 3F provide schematic illustrations of a casing cutting and removal assembly in a method according to an embodiment of the present invention.
  • Mechanism 10 comprises a tubular body 12 having, at a first end 14, a pin connector 16 for mounting the mechanism 10 in a string (not shown).
  • a second end 18 of the body 12 is integral with the tubular body 20 of a downhole tool (not shown).
  • a screw threaded connection may be alternatively arranged at the second end 18 for connection to the downhole tool or other part of a string which is in turn connected to the downhole tool.
  • the downhole tool will operate by relative movement of the body 20 and an operating member 22.
  • An inner sleeve 24 is provided in a central throughbore 26 of the mechanism 10.
  • Inner sleeve 24 and operating member 22 are shown connected in the mechanism 10, with the operating member 22 forming a portion of the inner sleeve 24.
  • the inner sleeve 24 is thus connected to the operating member 22 of the downhole tool. This is achieved via a direct connection in the present embodiment, but may be by an overshot arrangement.
  • a spring compression ring 28 attached to the operating member 22 which will compress a disc spring 46 which can be used to operate a tool (not shown). This spring compression ring 28 and spring 46 are not part of the mechanism 10 and shown only for illustrative purposes of operating a tension set tool.
  • Mechanism 10 comprises a chamber 48 formed by the tubular body 12 and inner sleeve 24.
  • the tubular body 12 provides an inner surface 41, upper surface 31 and a lower surface 34 to the chamber 48.
  • the outer surface 40 of the inner sleeve 24 provides the bounding wall of the closed chamber 48.
  • Within the chamber 48 there is arranged a piston 50.
  • Piston 50 is fixed to the inner sleeve 24 and so that it can move in the chamber 48 in response to movement of the inner sleeve 24.
  • the piston 50 is sealed 71 to an inner surface 41 of the tubular body 12.
  • the presence of the piston 50 creates an upper chamber 60 and a lower chamber 64.
  • the upper chamber 60 is bounded by the outer surface 40, inner surface 41, upper surface 31 and upper piston face 54.
  • the lower chamber 64 is bounded by the outer surface 40, inner surface 41, lower surface 34 and lower piston face 52.
  • Floating piston 62 is located in the lower chamber 64 being sealed against the outer surface 40 and inner surface 41.
  • the floating piston 62 creates a further chamber, being a pressure equalisation chamber 66 in the lower chamber 64.
  • Piston 50 includes two valves, pressure relief valve 58 and a check valve 56.
  • Valves 56, 58 lie in parallel with the longitudinal axis of the mechanism 10 and selectively provide fluid communication the upper chamber 60 and the lower chamber 64.
  • the relief valve 58 is operable at around 5000 psi (3.4xl0 7 Nm 2 ) to allow fluid flow from the upper chamber 60 to the lower chamber 64.
  • the check valve 56 is operable at a low pressure, say about 5 psi (3.4xl0 4 Nm 2 ) to allow fluid to flow from the lower chamber 64 to the upper chamber 60.
  • the inner surface 41 of upper chamber 60 is provided with an aperture 70 which is sealed with a top aperture sealing plug 72. Also, the inner surface of lower chamber 64 is provided with an aperture 74 which is sealed with a lower aperture sealing plug 78. The inner surface 41 of pressure equalisation chamber 66 is also provided with an aperture 78. Prior to deployment, the mechanism 10 is arranged such that it is unset. Oil is pumped through lower aperture 74 into chamber 64 at a pressure sufficient to actuate the low-pressure check valve 56, in this case around 5 psi.
  • the pressurised oil actuates the low-pressure check valve 56 causing it to open and allow the oil to travel through the low-pressure check valve 56, into chamber 60 and to be expelled through aperture 70 to ensure the amount of oil in the system is appropriate to enable the valve system to function.
  • a lower sealing plug 76 and top sealing plug 72 are used to seal apertures 74 and 70 respectively.
  • seals 71 prevent the unwanted movement of fluid between the chambers 60,64,66.
  • the piston face area 54 together with the rating of the pressure relief valve 58 determine a piston load at which the pressure relief valve 58 will open and the piston 50 will move in a first direction towards the upper surface 31. This is selected to be at greater than the operating load for actuation of the downhole tool being used with the mechanism 10. Preferably the piston load is three to five times greater than the operating load.
  • the piston load can be selected to represent a load greater than that which may be experience by the downhole tool when deployed in a well.
  • the mechanism 10 is arranged in a first configuration as shown in Figure 1A.
  • the pressure equalisation chamber 66 ensures that the volume of oil will remain pressurised.
  • the piston 50 will want to move upwards very slightly due to the increase in hydrostatic pressure and move downwards due to the increase in temperature and therefore the expansion of oil.
  • the work string will be anchored so that there is a fixed point against which a load may be applied.
  • the downhole tool and resettable mechanism can be run in a well and the downhole tool, which would normally operate at a relatively low operating load, say 15 tonnes (15000 kg) as an example, will not actuate until a load greater than the combination of the operating load and the piston load is applied.
  • a relatively low operating load say 15 tonnes (15000 kg) as an example
  • the piston face area 54 together with the rating of the pressure relief valve 58 provide a piston load of 45 tonnes (45,000 kg).
  • This load is thus required to allow oil through valve 58 plus a pull or load of at least 15 tonnes (15,000kg) to start movement of the piston 50 and the inner sleeve 24 such that a load of at least 60 tonnes (60,000kg) is required to actuate the downhole tool.
  • a load of around 75 tonnes (75,000 kg) would be recommended to ensure the tool operates.
  • the check valve 58 when the load applied by an overpull to the string is greater than the combination of the operating load and the piston load, the check valve 58 will open allowing oil to transfer from chamber 60 through to chamber 64.
  • chamber 64 will increase in size as chamber 64 receives oil through valve 58 and face 52 moves away from floating piston face 63.
  • chamber 60 will diminish in size as the face 54 moves towards face 31 and thus the associated relative movement of the inner sleeve 24 causes the operating member 22 of the downhole tool also to be relatively moved and consequently the downhole tool is actuated.
  • it has taken a load well in excess of the operating load of the downhole tool, in this case a multiple of the operating load being five times the operating load, to actuate the downhole tool.
  • FIG. IB The operating configuration is shown in Figure IB.
  • the disc springs 46 have been compressed so that the downhole tool is effectively actuated.
  • the high-pressure relief valve 58 has been opened allowing oil to pass into and expand chamber 64, thus minimising chamber 60, whilst the inner sleeve 24 has moved along towards the second end 18 such that spring compression ring 28 compresses the spring 46 to operate the downhole tool.
  • the spring 46 remains contracted. Any variation in the load will not cause the tool to be deactivated as long as a net load remains in the first direction. If weight is set down, a reverse load is applied.
  • FIGS. 2A and 2B are enlarged longitudinal sectional views of a mechanical tension-set retrievable packer, generally indicated by reference numeral 222, according to an embodiment of the present invention.
  • the mechanical tension-set retrievable packer 222 comprises a packer element 240.
  • the packer element 240 is typically made from a material capable of radially expanding when it is axially compressed such as rubber or other elastomeric material.
  • the packer 222 has a mandrel 215 movable in relation to the body 213.
  • a spring compression ring 248 is mounted on the second end 215b of the mandrel.
  • the spring compression ring 248 is configured to engage a first end 246a of spring 246.
  • the second end 46b of the spring 246 is connected and/or engages shoulder 244 on the tool body 213.
  • the mandrel 215 is movably mounted on the body 213 and is biased to a first position shown in Figure 2A by spring 246.
  • the packer 222 is connected to the resettable mechanism 10 of Figures 1A and IB. Those parts of Figures 1A to ID viewable on the drawings are marked.
  • the operating member 22 thus forms the mandrel 215 and body 12 is integral with body 213 which can be considered as body 20 on Figures 1A and IB.
  • the mandrel is configured to move from a first mandrel position shown in Figure 2A to a second mandrel position shown in Figure 2B when an upward tension or force is applied to the packer 222 via the drill string (not shown) connected thereto at a second end 218.
  • the spring force of spring 246 maintains the position of the mandrel 215 relative to the body 213.
  • the packer element 240 is not compressed.
  • the mandrel 215 moves relative to the body 213, the upward force acting on the mandrel 215 moves the spring compression ring 248 in a direction X which compresses the spring 246.
  • a lower gauge ring 252 mounted on the mandrel 215 engages a first edge 240a of the packer element 240.
  • An upper gauge ring 254 mounted on the tool body 213 engages a second edge 240b of the packer element.
  • the upward force acting on the packer 222 moves the lower gauge ring 252 toward the upper gauge ring 254 compressing the packer element 240. Compression of the packer element 240 causes it to radially expand to contact the casing and seal the annulus of the wellbore.
  • the upward force or tension applied to the packer 222 has a pre-set lower threshold such that the spring force of spring 246 is overcome when upward force or tension is applied above the lower threshold.
  • the lower threshold may be the minimum force or tension required to overcome the spring force of spring 246.
  • the lower threshold is set so that actuation will occur once an operating load is applied.
  • An example operating load may be 15 tonnes (15000 kg).
  • the resettable mechanism 10 when the resettable mechanism 10 is part of the packer 222 a greater load is required to actuate the packer 222. This increased load is determined by the piston load in the mechanism 10. If we were to attempt to design a tension-set packer operable on the increased load, the springs 246 would be excessively long and such a packer would be impractical.
  • the packer 222 can now be set using an increased load which can be adjusted so that it is greater than any unexpected loading which may occur on the drill string in use. Such variable loading is typically experienced when the string is run form a floating rig. Additionally, the resettable mechanism 10 allows the packer 222 to be unset and reset any number of times without requiring the packer to be pulled out of the well.
  • Casing cutting and removal assembly 310 includes, from a first end 316, a casing cutter 318, an anchor mechanism 320 and a mechanical tension-set retrievable packer 322 which includes a resettable mechanism 325 arranged on a drill string 323 or other tool string according to an embodiment of the present invention.
  • the casing cutter 318, anchor mechanism 320 and mechanical tension-set retrievable packer 322 with the resettable mechanism 325 may be formed integrally on a single tool body or may be constructed separately and joined together by box and pin sections as is known in the art. Two parts may also be integrally formed and joined to the third part.
  • Anchor mechanism 320 may be considered as a casing spear.
  • the anchor mechanism 320 may be of any configuration to grip the casing 314.
  • a typical anchor mechanism 320 may comprise slips which move over a cone to extend and grip the casing 314.
  • the slips will engage the inner surface 317 of the casing 314.
  • tension is applied by overpulling the drill string 323 and the tool 310, the slips are further forced outwards to grip the inner surface 317 of the casing 314.
  • Changing fluid pressure through the anchor mechanism will not deactivate the slips.
  • the slips and anchor mechanism will release when the tension is removed and weight is set down on the string 323.
  • the anchor mechanism 320 therefore provides a fixed point against which a load may be applied, either by pulling to tension or by setting down weight on the drill string 323.
  • a bearing on the tool body connects the anchor mechanism 320 with the tool body.
  • the anchor mechanism 320 is rotatably mounted on the body and is configured to secure the tool 310 against the wellbore casing 314.
  • An upward force applied to the tool body may also apply pressure to the bearing and may facilitate the rotation of the lower tool body which will be connected to the casing cutter 318 and thus allow rotation thereof.
  • Casing cutter 318 may be any type of casing cutter.
  • the casing cutter 318 comprises a plurality of blades 330 which extend by the application of fluid pressure through the drill string 323.
  • the blades 330 rotate to cut through the wall of the casing 314.
  • Such fluid flow also removes the casing cuttings.
  • the casing cutting and removal assembly 310 is assembled on a drill string 323, in the order of the mechanical tension-set retrievable packer 322 with resettable mechanism 325, the anchoring mechanism 320 and the casing cutter 318.
  • a bridge plug could replace the drill 319 and be set in the casing 314 in place of the cement plug 321.
  • the casing cutting and removal assembly 310 is run-in the wellbore 312 and casing 314 until it reaches the cement plug 321.
  • a wellbore integrity test can be performed using the anchor mechanism 320 and the mechanical tension- set retrievable packer 322, if desired.
  • fluid can be pumped at a fluid pressure below a pre-set threshold through the bore of the drill string 323 to hydraulically activate the drill 319. This does not actuate the casing cutter 318, anchor mechanism 320, the mechanical tension-set retrievable packer 322 or the resettable mechanism 325.
  • the drill 319 is used to dress the cement plug 321.
  • the casing cutting and removal assembly is then pulled up to locate the blades 330 of the casing cutter 318 at a desired location to cut the casing 314.
  • the anchor mechanism 320 is hydraulically actuated to grip the casing surface 317 to secure the axial position of the tool 310 in the wellbore.
  • the fluid circulation rate through bore 325 is increased and the anchor mechanism 320 grips the casing 314.
  • the tool 310 is then anchored to the casing by reversibly setting the anchor mechanism 320 by pulling the string 323.
  • the casing cutter 318 can be actuated. Note that the casing 314 is held in tension when the casing cutter 318 is operated.
  • the mechanical tension-set packer 322 and resettable device 325 are not affected by setting of the anchor mechanism 320 or the casing cutting as the tension applied is lower than the combined operating load and collet load.
  • the mechanical tension-set retrievable packer can be rapidly set to seal the wellbore by simply applying greater tension to the drill string 323 to set the packer. This is described hereinbefore with reference to Figures 2A and 2B.
  • the load applied being great enough to overcome the detent in the resettable mechanism 325 so that the packer 322 can set.
  • the mechanical tension-set retrievable packer 322 is first set to seal the casing 314.
  • an upward tension or pulling force is applied to the drill string as shown by arrow X in Figure 3D.
  • 60,000 lbs (266894 N) of upward tension or pulling force is applied to the drill string.
  • the load applied is great enough to overcome the check valve pressure in the resettable mechanism 325 so that the packer 322 can set.
  • the packer element is axially compressed it radially expands to engage the casing and seals the casing annulus 328. The upward force is maintained to seal of the wellbore. This is as illustrated in Figure 3D.
  • the annulus 328 is now sealed off and pressurised fluid pumped through the drill string 323 will enter the annulus 328 and travel through the cut 329 in the casing 314. While fluid can travel down between the casing 314 and the formation 331 it will be stopped at cement 341. In this way, the fluid will be forced upwards between the casing 314 and the formation 331 towards the surface.
  • the ability to circulate up through the annulus behind the casing at surface indicates a positive circulation test and that the annulus behind the casing is free of debris which may cause the casing 314 to stick when removed.
  • the casing 314 can now be removed.
  • the upward force or tension applied to the drill string is reduced to deactivate the mechanical tension-set retrievable packer 322 and the resettable mechanism moves to its first configuration and has reset.
  • the packer element returns to its original uncompressed state and moves away from the well casing 314.
  • This weight setting operation can merely be a continuation of the release of tension which unset the packer 322.
  • the tool 310 is now relocated to a new axial position in the casing 314 with the anchor mechanism 320 located at an upper end of the cut section of casing 343.
  • the anchor mechanism 320 is activated to grip the casing section 343 as described above and as illustrated in Figure 3E.
  • the cut section of casing 343 is removed from the wellbore 312.
  • the wellbore 312 now contains the casing stub 345 and cement plug 321 as shown in Figure 3F.
  • the retrievable mechanical tension-set packer 322 can also be used to assist in retrieval of the casing section 343 is desired .
  • the string 323 is now no longer anchored at a fixed point and thus tension can only be applied against the weight of the casing section 343.
  • the packer 322 can be set at its operating load. This is achieved by dropping a ball through the drill string 323. The ball seats in a disengagement assembly of the resettable mechanism 325 and desupports the collet ring, thereby removing the detent. Consequently the packer 322 can then be set by its much lower operating load.
  • the principal advantage of the present invention is that it provides a resettable mechanism to prevent accidental actuation of a load set downhole tool.
  • a further advantage of an embodiment of the present invention is that it provides a high overpull tension-set packer which is resettable.
  • a still further advantage of an embodiment of the present invention is that it provides a casing cutting and removal assembly on which multiple circulation tests can be performed on a single trip in the well.

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  • Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)

Abstract

L'invention concerne un mécanisme réenclenchable destiné à empêcher l'actionnement accidentel d'un outil de fond de trou à charge réglée, ainsi qu'un procédé d'utilisation. Le mécanisme réenclenchable utilise un piston dans une chambre remplie d'huile, le piston comprenant des vannes polarisées en sens inverse pour commander la communication fluidique entre les côtés du piston, le piston étant mobile sous une charge supérieure à la charge de fonctionnement de l'outil de fond de trou et à la charge de piston. L'inversion de charge réenclenche le mécanisme et l'outil de fond de trou. L'invention concerne, selon certains modes de réalisation, une garniture d'étanchéité maintenue par traction mécanique récupérable et un système de coupe et de retrait de tubage qui empêchent un actionnement prématuré de la garniture d'étanchéité lors d'une exécution depuis des structures flottantes.
PCT/GB2019/050391 2018-02-15 2019-02-14 Perfectionnements apportés ou se rapportant à l'abandon de puits et à la récupération de fentes WO2019158922A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GB1802449.7 2018-02-15
GB1802449.7A GB2571094B (en) 2018-02-15 2018-02-15 Resettable mechanism for preventing actuation of a load-set downhole tool

Publications (1)

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WO2019158922A1 true WO2019158922A1 (fr) 2019-08-22

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GB (1) GB2571094B (fr)
WO (1) WO2019158922A1 (fr)

Families Citing this family (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB2584281B (en) * 2019-05-24 2021-10-27 Ardyne Holdings Ltd Improvements in or relating to well abandonment and slot recovery
CN112610176B (zh) * 2021-01-14 2022-08-05 长江大学 一种用于弃井套管回收的施工工艺

Citations (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB2548727A (en) * 2017-05-19 2017-09-27 Ardyne Tech Ltd Improvements in or relating to well abandonment and slot recovery

Family Cites Families (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
AU2010282322B8 (en) * 2009-08-13 2015-11-12 Halliburton Energy Services, Inc. Repeatable, compression set downhole bypass valve

Patent Citations (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB2548727A (en) * 2017-05-19 2017-09-27 Ardyne Tech Ltd Improvements in or relating to well abandonment and slot recovery

Also Published As

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GB2571094A (en) 2019-08-21
GB201802449D0 (en) 2018-04-04
GB2571094B (en) 2020-07-15

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