US20140238689A1 - Wellbore Packer And Method - Google Patents
Wellbore Packer And Method Download PDFInfo
- Publication number
- US20140238689A1 US20140238689A1 US13/896,589 US201313896589A US2014238689A1 US 20140238689 A1 US20140238689 A1 US 20140238689A1 US 201313896589 A US201313896589 A US 201313896589A US 2014238689 A1 US2014238689 A1 US 2014238689A1
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- US
- United States
- Prior art keywords
- packer
- mandrel
- wellbore
- slip
- compression ring
- 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.)
- Abandoned
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Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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 invention relates to a wellbore packer and method.
- Wellbore packers are employed for fluid control and isolation.
- packers are employed to control fluid flows and to isolate and direct injected fluids.
- a wellbore packer for setting against a wellbore wall in a wellbore, the wellbore packer comprising: a mandrel including a upper end and an lower end; and an outer housing encircling the mandrel and including a first compression ring, a second compression ring, an annular packing element encircling the mandrel and positioned between the first compression ring and the second compression ring, the sealing element being expandable to form an annular seal about the packer by compression between the first compression ring and the second compression ring; and an anchoring mechanism including a slip that is expandable outwardly into a set position and a slip actuation assembly to drive expansion of the slip.
- Also provided is a method for setting a packer against a wellbore wall in a wellbore comprising: running into the wellbore with a wellbore packer connected to a tubing string, the wellbore packer including: a mandrel including a upper end and an lower end; and an outer housing encircling the mandrel and including a first compression ring, a second compression ring, an annular packing element encircling the mandrel and positioned between the first compression ring and the second compression ring, the sealing element being expandable to form an annular seal about the packer by compression between the first compression ring and the second compression ring; and an anchoring mechanism including a slip that is expandable outwardly into a set position and a slip actuation assembly to drive expansion of the slip; applying force to the packer to push the outer housing down over the mandrel, while the second compression ring is held stationary to compress the packing element and to cause the packing element to expand outwardly against the wellbore wall; and
- FIG. 1 is a sectional view along the long axis of a packer in an inactive, run in condition.
- FIG. 2 is a sectional view along a long axis of the packer of FIG. 1 operating in a wellbore.
- the packer is in a set position.
- FIG. 3 is a sectional view along a long axis of the packer of FIG. 1 in a wellbore string and in a later stage of operation. Here the packer is shown after shear release.
- FIGS. 1 to 3 one embodiment of a wellbore packer 10 is shown. These figures show the packer 10 sometimes positioned in a wellbore, shown by wall 12 .
- FIG. 1 shows the packer in an inactive condition. This is the packer's condition during run in to a wellbore.
- FIGS. 2 and 3 show the packer operating in the wellbore.
- the wellbore may be cased or open hole, such that wall 12 may be a casing inner surface or exposed formation.
- Packer 10 is formed operate in the wellbore and for example has an outer diameter to fit within wall 12 .
- Wall 12 forms a constraining surface about the packer and the packer can be deployed and set to create an annular seal between the wall and the packer.
- packer 10 may be carried, via its upper end, on a manipulation string 14 , through which the packer 10 can be axially moved and manipulated from surface.
- String 14 may have a flexible or axially rigid, solid or tubular form.
- String 14 for example, may include line, rods, coil tubing, interconnected tubulars, etc.
- Packer 10 may be recognized by those in the field as an injection-type packer and includes an outer housing 16 and an inner mandrel 18 .
- Mandrel 18 provides a body about which outer housing 16 is mounted.
- the mandrel can be closed, if the packer is to act as a plug in the wellbore, or may have a bore 18 a therethrough from its upper end 18 b to its lower end 18 c , as shown, through which fluids can be injected below the packer.
- Mandrel 18 at its upper end is formed to be supportable on string 14 .
- upper end 18 b includes a thread form 20 into which a string may be secured by threaded engagement. It may be useful to employ a latch seal assembly 23 that can become engaged into thread form 20 by stabbing straight in but can only be removed by unthreading from thread 20 . In one embodiment shown in FIG.
- a string 14 a carries a latch seal assembly 23 that includes a mandrel latch including radially outwardly biased collet fingers 25 with an externally threaded surface 27 .
- the threaded surface 27 spans the collet fingers and forms a continuous threaded pin end.
- the collet fingers can collapse inwardly to allow connection with the packer by a straight insertion into end 18 b , but the collet fingers being biased outwardly drive threaded surface 27 into engagement with the thread 20 such that the latch seal assembly can only be removed from end 18 b by reverse threading the collet fingers 25 from thread 20 .
- Mandrel 18 further includes a bore portion 21 into which an injection string can be inserted and sealed.
- Bore portion 21 may include a surface to facilitate sealing therein of an injection string, such as a latch seal assembly 23 .
- the surface may be smoother than other mandrel surfaces.
- bore portion 21 may be polished.
- Bore portion 21 may extend fully through the mandrel or may have an axial length less than the length of the mandrel.
- bore portion 21 extends down to a shoulder 24 . The shoulder is upwardly facing with the inner diameter being greater above than below and, thus, presents a surface against which the injection string may be set to limit its insertion.
- Mandrel 18 may further include mounting site for a bore plug.
- the mounting site is a profile 26 for accepting the bore plug, if one is desired.
- a bore plug controls fluid communication through the bore from end 18 b to end 18 c and may be a valve or a solid wall and may be permanent or removable (i.e. burstable, expellable, openable, etc.).
- the illustrated profile is an annular indentation, for example, for an Otis X or XN blanking plug, but of course other forms are possible.
- Mandrel 18 carries structures on its outer surface 18 d for operation with outer housing 16 .
- the mandrel may include sites, such as glands or indentations 28 , 29 , for accepting connection with the outer housing, a shoulder 30 for acting against outer housing 16 and a ratchet structure 33 for locking the position of the outer housing relative to the mandrel.
- Mandel 18 may be made of interconnected parts, as is usual for wellbore tools, or the mandrel may be one piece, as shown.
- the absence of threaded connections in the bore along the length of the mandrel avoids potential leak paths and the need for seals to be installed, and allows the length of the tool to be reduced over mandrel constructions employing a plurality of parts threaded together.
- Outer housing 16 has an overall cylindrical form that encircles the mandrel. Outer housing 16 has an inner diameter through which the mandrel extends such that the outer housing and the mandrel are assembled substantially coaxially about long axis x.
- Outer housing 16 includes the packer's one or more packing elements 36 .
- Packing elements 36 when set, create an annular seal in the wellbore about the packer extending between the mandrel outer surface 18 d and the wellbore wall.
- Outer housing 16 further includes a lower packing element compression ring 37 , also called a gauge ring, on a lower housing segment 38 and an upper packing element compression ring 40 on the upper, opposite side of the packing elements from ring 36 .
- Rings 37 , 40 transfer compression force to the packing elements therebetween and direct the packing elements to be extruded radially outwardly.
- Outer housing 16 further includes an anchoring mechanism, for example, including slips 22 and a slip actuation assembly.
- Slips 22 are spaced apart about a circumference of the mandrel and formed to be settable to expand out and engage the wellbore wall.
- the slips may have teeth formed on their outer facing surfaces 22 a to bite into the wellbore wall, when set into contact with the wall.
- the slip actuation assembly includes parts formed to drive the slips out into a set position.
- the slip actuating assembly may also include components to retain the slips in a retracted position until they are driven out to set.
- the slips each include a backside 22 b that is frusto-conically formed at each end.
- the slips are ramped on their backside surface where the slip thickness tapers from a mid region toward the ends.
- the slip actuation assembly includes an upper cone 42 and a lower cone 44 that are each axially moveable and drivable behind the slips to act against the backside frusto-conical surfaces and drive the slips radially out to the expanded position.
- the slip actuation assembly also includes an axially rigid slip cage 46 releasably secured at one end, as by shear pins 48 , to upper cone 42 and releasably secured at the opposite end, as by shear pins 50 , to lower cone 44 .
- Slips 22 are aligned with openings 46 a in the slip cage and can pass therethrough, as they expand and retract.
- a locking body 52 is also provided as a part of the outer housing.
- Locking body 52 includes an inwardly facing ratchet surface 54 formed to act with ratchet surface 33 on mandrel 18 .
- the ratchet teeth on the ratchet mechanism, including ratchet surfaces 33 , 54 allow movement of locking body 52 in a downward direction but not in the reverse. In other words, locking body 52 can move toward lower end 18 c , but not in the reverse direction (i.e. toward upper end 18 b ).
- Locking body 52 also includes an upper end 52 a that forms a shoulder protruding out from mandrel outer surface 18 d.
- Housing 16 also includes an inwardly facing shoulder 58 to act with shoulder 30 on mandrel 18 .
- Locking body 52 and upper cone 42 are connected for movement together at connection 60 .
- packing elements 36 are positioned closer to the lower end 18 c of mandrel than the other components.
- the anchoring assembly and ratchet mechanism are positioned between packing elements 36 and the upper end of the packer, which is upper end 18 b of the mandrel. Since fluids are generally injected below packer, this positioning isolates the injected fluids from the operational mechanisms, thereby reducing potential corrosion problems.
- lower cone 44 is connected to upper ring 40 through a connection 62 .
- This connection, connection 60 and pins 48 , 50 connect the components of the outer housing above elements 36 , such that they all move in unison until pins 48 , 50 shear.
- Outer housing 16 is normally retained in place on mandrel by a releasable lock, such as shear pins 56 engaged between locking body 52 and recess 28 and shear pins 64 engaged between lower housing segment 38 and recess 29 .
- the releasable lock on the upper end has a lower holding force than the releasable lock on the lower end, such that the upper connection through shear pins 56 can be overcome before that holding the lower end.
- This allows a relative movement of upper end, for example locking body 52 , relative to the lower end, for example, lower housing segment 38 and locking body can be made moveable over mandrel 18 while the lower housing segment remains attached to the mandrel.
- the strongest releasable locks, in this embodiment, pins 64 cannot be overcome by setting the packer. Thus, pins 64 hold the mandrel in place in the outer housing while the packer is in use.
- packer 10 is attached to string 14 and run into the well.
- the packer is set by expanding the packing elements 36 and slips 22 such that the elements 36 form an annular seal between mandrel 18 and wall 12 and slips bite into the wellbore wall and hold the packer firmly in place against tool manipulations and pressure differentials.
- the packer is set by holding the mandrel while pushing down on locking body 52 .
- the packer may be set in various ways, such as by electrical drive, hydraulics, mechanical, etc.
- string 14 may include a line such as wireline for example, electric wireline.
- the packer may be attached to a setting tool with a wireline adapter kit. The packer can then be run into the well on wireline and at a position of interest, the packer may be set by a force generated by the wireline setting tool. At a predetermined force, the wireline adapter kit may disengage from the packer. Thereafter, the setting tool, adapter kit and wireline are retrieved from the hole, leaving the packer set in the wellbore.
- string 14 may include tubulars that can apply a push force on the tool.
- tubulars that can apply a push force on the tool.
- packer placement may require a push force to be applied to the packer during deployment.
- the packer can be deployed on a string formed of tubing and may be pushed into the well.
- a hydraulic setting tool may be attached to the tubing string and an adapter kit may be employed to attach the packer to the hydraulic setting tool. Pressure applied down the tubing is converted to a force to push the locking body down relative to the mandrel to set the packer.
- the tubing pressure may also be employed to disengage the adapter kit from the packer, after it is set.
- the force applying body of the adapter kit can be set against upper end 52 a shoulder of the locking body. While the mandrel is held steady, the force to set the packer is applied to locking body 52 . Once pins 56 shear, the force continues through locking body 52 to upper cone 42 , slip cage 46 , lower cone 44 and then into packing elements. Since lower end segment 38 is held in place by pins 64 , the movement of the upper components squeezes ring 40 against elements 36 and elements 36 against ring 37 and causes the packing elements to expand radially outwardly.
- the packer is fully set ( FIG. 2 ).
- the ratchet surfaces 33 , 54 of the ratchet mechanism trap the setting force against mandrel 18 .
- the teeth of the ratchet mechanism are selected to allow movement of the locking body toward lower end 18 c , but not in the reverse.
- This lower component to upper component setting sequence (i.e. (i) packing elements expand, (ii) lower cone (between packing elements and slips) wedges under the slips, and (iii) upper cone wedges under the slips), ensures that the packer anchors inside the wellbore properly and forms a high pressure seal between mandrel 18 and wall 12 . If the upper cone wedged prior to any of the lower components, the force could not be transferred through and the packer setting would be incomplete.
- the setting sequence may be achieved by selection of the shear pin failure rating.
- the shear pins 50 and 48 have a holding force greater than the force required to expand the packing elements and shear pins 48 have a holding force greater than that of the shear pins 50 for the lower cone.
- the packer After the packer is set, it can operate to hold pressure in the wellbore. If the mandrel is closed, the packer may operate immediately acting as a plug, such as a bridge plug in the well. If the packer is intended to assist with injection operations, an injection string can be run in to connect to the mandrel and inject through the packer.
- a latch seal assembly is attached to a tubing string 14 a and run into the well. If the packer mandrel is closed, for example, it has a plug in its mandrel for example, at profile 26 , the packer may act as a bridge plug in the well and snubbing of the string may not be necessary.
- latch seal assembly 23 is stabbed into the packer. Collet fingers 25 drive threaded surface 27 into engagement with the thread 20 and seals 23 a on the latch seal assembly engage bore portion 21 on the packer. An annular pressure test may ensure that seals 23 a are sealing are there are no leaks in the tubing connections.
- the annular pressure test ensures the packer is set properly after the integrity of tubing string 14 a , latch seal assembly 23 and packer 10 have been determined.
- the mandrel may then be opened, as by overcoming (i.e. pumping out, bursting, opening, etc.) any plug in the bore of the mandrel.
- the plug can be overcome by using applied pressure down string 14 a. Once the bore of the mandrel has been opened, communication is established with the wellbore below the packer. Fluid injection can then be commenced.
- tubing string 14 a if tubing string 14 a needs to be removed, a plug can be set inside the mandrel, for example in profile 26 .
- Tubing string 14 a and latch seal assembly 23 can then be separated safely from the packer and retrieved to surface. This may be accomplished by rotation of the latch seal assembly, for example right hand rotation to unthread the parts, and then pulling up.
- mandrel 18 If/when the operator decides to remove the packer, it can be released by pulling up on mandrel 18 , as shown in FIG. 3 .
- the mandrel can be pulled up by pulling the string 14 a into tension while latch seal assembly 23 is engaged in thread form 20 .
- Some other packers require the use of an injection string and a separate releasing string, but the same string may be used for both operations in this packer.
- the latch seal with its collet fingers 25 and external threaded surfaces 27 cannot be pulled straight out of engagement with thread form 20 , but instead must be unthreaded by employing more than a quarter turn rotation.
- the engagement of mandrel 18 by latch seal assembly 23 is, therefore, quite reliable and can only be overcome by significant rotation of the latch seal assembly relative to the packer. This requirement for reverse (i.e. right hand) threading makes an inadvertent release unlikely.
- shearing pins 64 which removes the compressive force setting slips 22 and elements 36 .
- the housing 16 can stretch and elements 36 and slips can relax and retract.
- Other packer mechanisms may be employed to facilitate release of the compressive force.
- mandrel 18 is pulled up to shear pins 64 .
- Shoulder 30 on mandrel 18 also moves up and pulls against locking body 52 , which pulls upwardly on upper cone 42 . This causes upper cone 42 to shift from beneath slips 22 and, as well, to pull up slip cage.
- a shoulder 43 on upper cone 42 may catch on a shoulder 45 on slip cage, so that both cone 42 and slip cage move up.
- the lower end of opening 46 a on the slip cage butts against the lower ends of slips and pulls slips 22 off lower cone 44 .
- the slips then can retract.
- the release of compressive force through shearing of pins 64 also allows elements 36 to relax and retract.
- the upward movement of the housing components above elements 36 facilitates and speeds the retraction of the packing elements.
Abstract
Description
- This application claims priority to U.S. Provisional Application No. 61/768,742 filed on Feb. 25, 2013, which is hereby incorporated by reference in its entirety.
- The invention relates to a wellbore packer and method.
- Wellbore packers are employed for fluid control and isolation. For example, packers are employed to control fluid flows and to isolate and direct injected fluids.
- In accordance with a broad aspect of the present invention, there is provided a wellbore packer for setting against a wellbore wall in a wellbore, the wellbore packer comprising: a mandrel including a upper end and an lower end; and an outer housing encircling the mandrel and including a first compression ring, a second compression ring, an annular packing element encircling the mandrel and positioned between the first compression ring and the second compression ring, the sealing element being expandable to form an annular seal about the packer by compression between the first compression ring and the second compression ring; and an anchoring mechanism including a slip that is expandable outwardly into a set position and a slip actuation assembly to drive expansion of the slip.
- Also provided is a method for setting a packer against a wellbore wall in a wellbore, the method comprising: running into the wellbore with a wellbore packer connected to a tubing string, the wellbore packer including: a mandrel including a upper end and an lower end; and an outer housing encircling the mandrel and including a first compression ring, a second compression ring, an annular packing element encircling the mandrel and positioned between the first compression ring and the second compression ring, the sealing element being expandable to form an annular seal about the packer by compression between the first compression ring and the second compression ring; and an anchoring mechanism including a slip that is expandable outwardly into a set position and a slip actuation assembly to drive expansion of the slip; applying force to the packer to push the outer housing down over the mandrel, while the second compression ring is held stationary to compress the packing element and to cause the packing element to expand outwardly against the wellbore wall; and continuing to apply force to compress the anchoring mechanism to drive the slip to expand outwardly into engagement with the wellbore wall.
- It is to be understood that other aspects of the present invention will become readily apparent to those skilled in the art from the following detailed description, wherein various embodiments of the invention are shown and described by way of illustration. As will be realized, the invention is capable for other and different embodiments and its several details are capable of modification in various other respects, all without departing from the spirit and scope of the present invention. Accordingly the drawings and detailed description are to be regarded as illustrative in nature and not as restrictive.
- A further, detailed, description of the invention, briefly described above, will follow by reference to the following drawings of specific embodiments of the invention. These drawings depict only typical embodiments of the invention and are therefore not to be considered limiting of its scope. In the drawings:
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FIG. 1 is a sectional view along the long axis of a packer in an inactive, run in condition. -
FIG. 2 is a sectional view along a long axis of the packer ofFIG. 1 operating in a wellbore. The packer is in a set position. -
FIG. 3 is a sectional view along a long axis of the packer ofFIG. 1 in a wellbore string and in a later stage of operation. Here the packer is shown after shear release. - The description that follows and the embodiments described therein are provided by way of illustration of an example, or examples, of particular embodiments of the principles of various aspects of the present invention. These examples are provided for the purposes of explanation, and not of limitation, of those principles and of the invention in its various aspects. The drawings are not necessarily to scale and in some instances proportions may have been exaggerated in order more clearly to depict certain features. Throughout the drawings, from time to time, the same number is used to reference similar, but not necessarily identical, parts.
- A wellbore packer and method have been invented.
- With reference to
FIGS. 1 to 3 , one embodiment of awellbore packer 10 is shown. These figures show thepacker 10 sometimes positioned in a wellbore, shown bywall 12.FIG. 1 shows the packer in an inactive condition. This is the packer's condition during run in to a wellbore.FIGS. 2 and 3 show the packer operating in the wellbore. - Although this type of packer is often employed in a cased wellbore, it is to be noted that the wellbore may be cased or open hole, such that
wall 12 may be a casing inner surface or exposed formation. -
Packer 10 is formed operate in the wellbore and for example has an outer diameter to fit withinwall 12.Wall 12 forms a constraining surface about the packer and the packer can be deployed and set to create an annular seal between the wall and the packer. - Although not shown in detail,
packer 10 may be carried, via its upper end, on amanipulation string 14, through which thepacker 10 can be axially moved and manipulated from surface.String 14 may have a flexible or axially rigid, solid or tubular form.String 14, for example, may include line, rods, coil tubing, interconnected tubulars, etc. -
Packer 10 may be recognized by those in the field as an injection-type packer and includes anouter housing 16 and aninner mandrel 18. - Mandrel 18 provides a body about which
outer housing 16 is mounted. The mandrel can be closed, if the packer is to act as a plug in the wellbore, or may have abore 18 a therethrough from itsupper end 18 b to itslower end 18 c, as shown, through which fluids can be injected below the packer. Mandrel 18 at its upper end is formed to be supportable onstring 14. In this embodiment,upper end 18 b includes athread form 20 into which a string may be secured by threaded engagement. It may be useful to employ alatch seal assembly 23 that can become engaged intothread form 20 by stabbing straight in but can only be removed by unthreading fromthread 20. In one embodiment shown inFIG. 3 , astring 14 a carries alatch seal assembly 23 that includes a mandrel latch including radially outwardlybiased collet fingers 25 with an externally threadedsurface 27. The threadedsurface 27 spans the collet fingers and forms a continuous threaded pin end. The collet fingers can collapse inwardly to allow connection with the packer by a straight insertion intoend 18 b, but the collet fingers being biased outwardly drive threadedsurface 27 into engagement with thethread 20 such that the latch seal assembly can only be removed fromend 18 b by reverse threading thecollet fingers 25 fromthread 20. -
Mandrel 18 further includes abore portion 21 into which an injection string can be inserted and sealed.Bore portion 21, sometimes referred to as a seal bore or polished bore, may include a surface to facilitate sealing therein of an injection string, such as alatch seal assembly 23. To facilitate sealing with theseals 23 a of an injection string, the surface may be smoother than other mandrel surfaces. For example, boreportion 21 may be polished.Bore portion 21 may extend fully through the mandrel or may have an axial length less than the length of the mandrel. For example, in the illustrated embodiment,bore portion 21 extends down to ashoulder 24. The shoulder is upwardly facing with the inner diameter being greater above than below and, thus, presents a surface against which the injection string may be set to limit its insertion. - Mandrel 18 may further include mounting site for a bore plug. In this illustrated embodiment, the mounting site is a
profile 26 for accepting the bore plug, if one is desired. A bore plug controls fluid communication through the bore fromend 18 b toend 18 c and may be a valve or a solid wall and may be permanent or removable (i.e. burstable, expellable, openable, etc.). The illustrated profile is an annular indentation, for example, for an Otis X or XN blanking plug, but of course other forms are possible. - Mandrel 18 carries structures on its
outer surface 18 d for operation withouter housing 16. For example, the mandrel may include sites, such as glands orindentations shoulder 30 for acting againstouter housing 16 and aratchet structure 33 for locking the position of the outer housing relative to the mandrel. -
Mandel 18 may be made of interconnected parts, as is usual for wellbore tools, or the mandrel may be one piece, as shown. A one piece part, as shown, which is devoid of connections such as threaded connections, ports, seals, etc. may be useful. The absence of threaded connections in the bore along the length of the mandrel avoids potential leak paths and the need for seals to be installed, and allows the length of the tool to be reduced over mandrel constructions employing a plurality of parts threaded together. - The function of the mandrel and the parts thereof will be better understood in the description hereinbelow regarding the packer operation.
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Outer housing 16 has an overall cylindrical form that encircles the mandrel.Outer housing 16 has an inner diameter through which the mandrel extends such that the outer housing and the mandrel are assembled substantially coaxially about long axis x. -
Outer housing 16 includes the packer's one ormore packing elements 36.Packing elements 36, when set, create an annular seal in the wellbore about the packer extending between the mandrelouter surface 18 d and the wellbore wall. -
Outer housing 16 further includes a lower packingelement compression ring 37, also called a gauge ring, on alower housing segment 38 and an upper packingelement compression ring 40 on the upper, opposite side of the packing elements fromring 36.Rings -
Outer housing 16 further includes an anchoring mechanism, for example, including slips 22 and a slip actuation assembly.Slips 22 are spaced apart about a circumference of the mandrel and formed to be settable to expand out and engage the wellbore wall. The slips may have teeth formed on their outer facing surfaces 22 a to bite into the wellbore wall, when set into contact with the wall. The slip actuation assembly includes parts formed to drive the slips out into a set position. The slip actuating assembly may also include components to retain the slips in a retracted position until they are driven out to set. In this illustrated embodiment, the slips each include abackside 22 b that is frusto-conically formed at each end. Thus, the slips are ramped on their backside surface where the slip thickness tapers from a mid region toward the ends. In this embodiment, the slip actuation assembly includes anupper cone 42 and alower cone 44 that are each axially moveable and drivable behind the slips to act against the backside frusto-conical surfaces and drive the slips radially out to the expanded position. The slip actuation assembly also includes an axiallyrigid slip cage 46 releasably secured at one end, as byshear pins 48, toupper cone 42 and releasably secured at the opposite end, as byshear pins 50, tolower cone 44.Slips 22 are aligned withopenings 46 a in the slip cage and can pass therethrough, as they expand and retract. - A locking
body 52 is also provided as a part of the outer housing. Lockingbody 52 includes an inwardly facingratchet surface 54 formed to act withratchet surface 33 onmandrel 18. The ratchet teeth on the ratchet mechanism, including ratchet surfaces 33, 54 allow movement of lockingbody 52 in a downward direction but not in the reverse. In other words, lockingbody 52 can move towardlower end 18 c, but not in the reverse direction (i.e. towardupper end 18 b). - Locking
body 52 also includes anupper end 52 a that forms a shoulder protruding out from mandrelouter surface 18 d. -
Housing 16 also includes an inwardly facingshoulder 58 to act withshoulder 30 onmandrel 18. - Locking
body 52 andupper cone 42 are connected for movement together atconnection 60. - In the illustrated embodiment, packing
elements 36 are positioned closer to thelower end 18 c of mandrel than the other components. In particular, as illustrated, the anchoring assembly and ratchet mechanism are positioned between packingelements 36 and the upper end of the packer, which isupper end 18 b of the mandrel. Since fluids are generally injected below packer, this positioning isolates the injected fluids from the operational mechanisms, thereby reducing potential corrosion problems. - Thus, as illustrated,
lower cone 44 is connected toupper ring 40 through aconnection 62. This connection,connection 60 and pins 48, 50 connect the components of the outer housing aboveelements 36, such that they all move in unison untilpins -
Outer housing 16 is normally retained in place on mandrel by a releasable lock, such as shear pins 56 engaged between lockingbody 52 andrecess 28 and shear pins 64 engaged betweenlower housing segment 38 andrecess 29. The releasable lock on the upper end has a lower holding force than the releasable lock on the lower end, such that the upper connection through shear pins 56 can be overcome before that holding the lower end. This allows a relative movement of upper end, forexample locking body 52, relative to the lower end, for example,lower housing segment 38 and locking body can be made moveable overmandrel 18 while the lower housing segment remains attached to the mandrel. The strongest releasable locks, in this embodiment, pins 64, cannot be overcome by setting the packer. Thus, pins 64 hold the mandrel in place in the outer housing while the packer is in use. - In use,
packer 10 is attached tostring 14 and run into the well. The packer is set by expanding thepacking elements 36 and slips 22 such that theelements 36 form an annular seal betweenmandrel 18 andwall 12 and slips bite into the wellbore wall and hold the packer firmly in place against tool manipulations and pressure differentials. - The packer is set by holding the mandrel while pushing down on locking
body 52. The packer may be set in various ways, such as by electrical drive, hydraulics, mechanical, etc. - In one embodiment, for example,
string 14 may include a line such as wireline for example, electric wireline. In such an embodiment, the packer may be attached to a setting tool with a wireline adapter kit. The packer can then be run into the well on wireline and at a position of interest, the packer may be set by a force generated by the wireline setting tool. At a predetermined force, the wireline adapter kit may disengage from the packer. Thereafter, the setting tool, adapter kit and wireline are retrieved from the hole, leaving the packer set in the wellbore. - In another embodiment,
string 14 may include tubulars that can apply a push force on the tool. For example, if the operation requires deployment in a deviated or horizontal well, then packer placement may require a push force to be applied to the packer during deployment. In such an embodiment, the packer can be deployed on a string formed of tubing and may be pushed into the well. A hydraulic setting tool may be attached to the tubing string and an adapter kit may be employed to attach the packer to the hydraulic setting tool. Pressure applied down the tubing is converted to a force to push the locking body down relative to the mandrel to set the packer. The tubing pressure may also be employed to disengage the adapter kit from the packer, after it is set. - The force applying body of the adapter kit can be set against
upper end 52 a shoulder of the locking body. While the mandrel is held steady, the force to set the packer is applied to lockingbody 52. Once pins 56 shear, the force continues through lockingbody 52 toupper cone 42,slip cage 46,lower cone 44 and then into packing elements. Sincelower end segment 38 is held in place bypins 64, the movement of the upper components squeezesring 40 againstelements 36 andelements 36 againstring 37 and causes the packing elements to expand radially outwardly. - After packing
elements 36 have fully expanded, the force is no longer taken up by the packing elements. Thereafter, shear screws 50 located betweenlower cone 44 and the slip cage shear allowing the slips to shift onto the lower cone. Once slips 22 contactlower cone 44, they are pushed radially outwardly from the mandrel towardwellbore wall 12. After contactingwall 12, shear pins 48 between the upper cone and the slip cage break, allowing theupper cone 42 to also be pushed under thebacksides 22 b of the slips. - Once the
cones slips 22, with the slips biting intowall 12, the packer is fully set (FIG. 2 ). The ratchet surfaces 33, 54 of the ratchet mechanism trap the setting force againstmandrel 18. As noted above, the teeth of the ratchet mechanism are selected to allow movement of the locking body towardlower end 18 c, but not in the reverse. - This lower component to upper component setting sequence (i.e. (i) packing elements expand, (ii) lower cone (between packing elements and slips) wedges under the slips, and (iii) upper cone wedges under the slips), ensures that the packer anchors inside the wellbore properly and forms a high pressure seal between
mandrel 18 andwall 12. If the upper cone wedged prior to any of the lower components, the force could not be transferred through and the packer setting would be incomplete. The setting sequence may be achieved by selection of the shear pin failure rating. The shear pins 50 and 48 have a holding force greater than the force required to expand the packing elements and shear pins 48 have a holding force greater than that of the shear pins 50 for the lower cone. - After the packer is set, it can operate to hold pressure in the wellbore. If the mandrel is closed, the packer may operate immediately acting as a plug, such as a bridge plug in the well. If the packer is intended to assist with injection operations, an injection string can be run in to connect to the mandrel and inject through the packer.
- In an injection operation, for example, at surface a latch seal assembly is attached to a
tubing string 14 a and run into the well. If the packer mandrel is closed, for example, it has a plug in its mandrel for example, atprofile 26, the packer may act as a bridge plug in the well and snubbing of the string may not be necessary. At depth,latch seal assembly 23 is stabbed into the packer.Collet fingers 25 drive threadedsurface 27 into engagement with thethread 20 and seals 23 a on the latch seal assembly engagebore portion 21 on the packer. An annular pressure test may ensure thatseals 23 a are sealing are there are no leaks in the tubing connections. The annular pressure test ensures the packer is set properly after the integrity oftubing string 14 a,latch seal assembly 23 andpacker 10 have been determined. The mandrel may then be opened, as by overcoming (i.e. pumping out, bursting, opening, etc.) any plug in the bore of the mandrel. The plug can be overcome by using applied pressure downstring 14 a. Once the bore of the mandrel has been opened, communication is established with the wellbore below the packer. Fluid injection can then be commenced. - During the fluid injection process, if
tubing string 14 a needs to be removed, a plug can be set inside the mandrel, for example inprofile 26.Tubing string 14 a andlatch seal assembly 23 can then be separated safely from the packer and retrieved to surface. This may be accomplished by rotation of the latch seal assembly, for example right hand rotation to unthread the parts, and then pulling up. - If/when the operator decides to remove the packer, it can be released by pulling up on
mandrel 18, as shown inFIG. 3 . The mandrel can be pulled up by pulling thestring 14 a into tension whilelatch seal assembly 23 is engaged inthread form 20. Some other packers require the use of an injection string and a separate releasing string, but the same string may be used for both operations in this packer. In particular, the latch seal with itscollet fingers 25 and external threadedsurfaces 27 cannot be pulled straight out of engagement withthread form 20, but instead must be unthreaded by employing more than a quarter turn rotation. The engagement ofmandrel 18 bylatch seal assembly 23 is, therefore, quite reliable and can only be overcome by significant rotation of the latch seal assembly relative to the packer. This requirement for reverse (i.e. right hand) threading makes an inadvertent release unlikely. - Since
slips 22 and packingelements 36 are set, pulling up on the mandrel moves the mandrel up through outer housing: shearing pins 64, which removes the compressive force setting slips 22 andelements 36. Thehousing 16 can stretch andelements 36 and slips can relax and retract. Other packer mechanisms may be employed to facilitate release of the compressive force. In particular, when the packer is to be released,mandrel 18 is pulled up to shear pins 64.Shoulder 30 onmandrel 18 also moves up and pulls against lockingbody 52, which pulls upwardly onupper cone 42. This causesupper cone 42 to shift from beneath slips 22 and, as well, to pull up slip cage. For example, ashoulder 43 onupper cone 42 may catch on ashoulder 45 on slip cage, so that bothcone 42 and slip cage move up. When pulled up, the lower end of opening 46 a on the slip cage butts against the lower ends of slips and pullsslips 22 offlower cone 44. The slips then can retract. The release of compressive force through shearing ofpins 64 also allowselements 36 to relax and retract. The upward movement of the housing components aboveelements 36 facilitates and speeds the retraction of the packing elements. - The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments without departing from the spirit or scope of the invention. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article “a” or “an” is not intended to mean “one and only one” unless specifically so stated, but rather “one or more”. All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are known or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims. No claim element is to be construed under the provisions of 35 USC 112, sixth paragraph, unless the element is expressly recited using the phrase “means for” or “step for”.
Claims (18)
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US13/896,589 US20140238689A1 (en) | 2013-02-25 | 2013-05-17 | Wellbore Packer And Method |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US201361768742P | 2013-02-25 | 2013-02-25 | |
US13/896,589 US20140238689A1 (en) | 2013-02-25 | 2013-05-17 | Wellbore Packer And Method |
Publications (1)
Publication Number | Publication Date |
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US20140238689A1 true US20140238689A1 (en) | 2014-08-28 |
Family
ID=51386975
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
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US13/896,589 Abandoned US20140238689A1 (en) | 2013-02-25 | 2013-05-17 | Wellbore Packer And Method |
Country Status (2)
Country | Link |
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US (1) | US20140238689A1 (en) |
CA (1) | CA2815848A1 (en) |
Cited By (13)
Publication number | Priority date | Publication date | Assignee | Title |
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WO2016065291A1 (en) * | 2014-10-23 | 2016-04-28 | Hydrawell Inc. | Expandable plug seat |
US20160312569A1 (en) * | 2015-04-22 | 2016-10-27 | Weatherford Technology Holdings, Llc | Tension-Set Tieback Packer |
CN108266153A (en) * | 2018-02-07 | 2018-07-10 | 中国石油集团西部钻探工程有限公司 | Suspension packing integral type list fluid cylinder can self-locking hanger |
US20180305994A1 (en) * | 2015-10-16 | 2018-10-25 | Inflatable Packers International Pty Ltd | Hydraulic anchoring assembly for insertable progressing cavity pump |
US10233709B2 (en) * | 2016-09-08 | 2019-03-19 | Baker Hughes, A Ge Company, Llc | Top set liner hanger and packer with hanger slips above the packer seal |
CN111749642A (en) * | 2020-08-11 | 2020-10-09 | 中国石油集团渤海钻探工程有限公司 | Novel pressure control integrated upper sealing well completion tool |
US10801304B2 (en) | 2018-09-24 | 2020-10-13 | The Wellboss Company, Inc. | Systems and methods for multi-stage well stimulation |
CN112177560A (en) * | 2019-07-03 | 2021-01-05 | 中国石油化工股份有限公司 | Adjustable double-well-barrel double-sealing device |
CN113236176A (en) * | 2021-06-22 | 2021-08-10 | 新疆华隆油田科技股份有限公司 | Electric push rod type packer |
US11111758B2 (en) | 2019-01-24 | 2021-09-07 | The Wellboss Company, Inc. | Downhole sleeve tool |
CN113803015A (en) * | 2020-06-12 | 2021-12-17 | 中国石油化工股份有限公司 | Suspension sealing device |
US11692420B2 (en) | 2020-10-09 | 2023-07-04 | The Wellboss Company, Inc. | Systems and methods for multi-stage fracturing |
CN117489293A (en) * | 2023-12-29 | 2024-02-02 | 中油博淏科技(天津)有限公司 | Packer with double sealing structures |
-
2013
- 2013-05-13 CA CA2815848A patent/CA2815848A1/en not_active Abandoned
- 2013-05-17 US US13/896,589 patent/US20140238689A1/en not_active Abandoned
Cited By (19)
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WO2016065291A1 (en) * | 2014-10-23 | 2016-04-28 | Hydrawell Inc. | Expandable plug seat |
US20160186511A1 (en) * | 2014-10-23 | 2016-06-30 | Hydrawell Inc. | Expandable Plug Seat |
US20160312569A1 (en) * | 2015-04-22 | 2016-10-27 | Weatherford Technology Holdings, Llc | Tension-Set Tieback Packer |
US9874070B2 (en) * | 2015-04-22 | 2018-01-23 | Weatherford Technology Holdings, Llc | Tension-set tieback packer |
US10883326B2 (en) * | 2015-10-16 | 2021-01-05 | Inflatable Packers International Pty Ltd | Hydraulic anchoring assembly for insertable progressing cavity pump |
US20180305994A1 (en) * | 2015-10-16 | 2018-10-25 | Inflatable Packers International Pty Ltd | Hydraulic anchoring assembly for insertable progressing cavity pump |
US10233709B2 (en) * | 2016-09-08 | 2019-03-19 | Baker Hughes, A Ge Company, Llc | Top set liner hanger and packer with hanger slips above the packer seal |
US10570686B2 (en) | 2016-09-08 | 2020-02-25 | Baker Hughes, A Ge Company, Llc | Top set liner hanger and packer with hanger slips above the packer seal |
CN108266153A (en) * | 2018-02-07 | 2018-07-10 | 中国石油集团西部钻探工程有限公司 | Suspension packing integral type list fluid cylinder can self-locking hanger |
US10801304B2 (en) | 2018-09-24 | 2020-10-13 | The Wellboss Company, Inc. | Systems and methods for multi-stage well stimulation |
US11396793B2 (en) | 2018-09-24 | 2022-07-26 | The Wellboss Company, Inc. | Systems and methods for multi-stage well stimulation |
US11396792B2 (en) * | 2019-01-24 | 2022-07-26 | The Wellboss Company, Inc. | Downhole sleeve tool |
US11111758B2 (en) | 2019-01-24 | 2021-09-07 | The Wellboss Company, Inc. | Downhole sleeve tool |
CN112177560A (en) * | 2019-07-03 | 2021-01-05 | 中国石油化工股份有限公司 | Adjustable double-well-barrel double-sealing device |
CN113803015A (en) * | 2020-06-12 | 2021-12-17 | 中国石油化工股份有限公司 | Suspension sealing device |
CN111749642A (en) * | 2020-08-11 | 2020-10-09 | 中国石油集团渤海钻探工程有限公司 | Novel pressure control integrated upper sealing well completion tool |
US11692420B2 (en) | 2020-10-09 | 2023-07-04 | The Wellboss Company, Inc. | Systems and methods for multi-stage fracturing |
CN113236176A (en) * | 2021-06-22 | 2021-08-10 | 新疆华隆油田科技股份有限公司 | Electric push rod type packer |
CN117489293A (en) * | 2023-12-29 | 2024-02-02 | 中油博淏科技(天津)有限公司 | Packer with double sealing structures |
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Legal Events
Date | Code | Title | Description |
---|---|---|---|
AS | Assignment |
Owner name: RESOURCE WELL COMPLETION TECHNOLOGIES INC., CANADA Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:HUGHES, JOHN;RASMUSSEN, RYAN DWAINE;REEL/FRAME:030436/0328 Effective date: 20130401 |
|
AS | Assignment |
Owner name: RESOURCE COMPLETION SYSTEMS INC., CANADA Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:RESOURCE WELL COMPLETION TECHNOLOGIES INC.;REEL/FRAME:032979/0272 Effective date: 20140131 |
|
STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |
|
AS | Assignment |
Owner name: THE WELLBOSS COMPANY, LLC, TEXAS Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:THE WELLBOSS COMPANY, INC.;REEL/FRAME:051046/0459 Effective date: 20191118 |
|
AS | Assignment |
Owner name: THE WELLBOSS COMPANY, INC., CANADA Free format text: MUTUAL RESCISSION OF ASSIGNMENT;ASSIGNOR:THE WELLBOSS COMPANY, LLC;REEL/FRAME:051368/0244 Effective date: 20191217 |