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Publication numberUS20070012461 A1
Publication typeApplication
Application numberUS 11/183,434
Publication dateJan 18, 2007
Filing dateJul 18, 2005
Priority dateJul 18, 2005
Publication number11183434, 183434, US 2007/0012461 A1, US 2007/012461 A1, US 20070012461 A1, US 20070012461A1, US 2007012461 A1, US 2007012461A1, US-A1-20070012461, US-A1-2007012461, US2007/0012461A1, US2007/012461A1, US20070012461 A1, US20070012461A1, US2007012461 A1, US2007012461A1
InventorsAllen Morgan
Original AssigneeMorgan Allen B
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Packer tool arrangement with rotating lug
US 20070012461 A1
Abstract
A packer assembly requires only forces applied axially along an actuating means such as production tubing (either pushing down or pulling up) to actuate it between its operational states, such as a set state, a bypassed state, and a released state. The packer includes a tubular member that has a lug guide formed substantially within its inner surface. The packer further includes a mandrel that can be coupled to an actuating means and disposed within the tubular member, the mandrel further comprising a lug ring having at least one lug disposed in the lug guide. The tubular member is held in a substantially fixed position relative to the mandrel once the packer is initially set within a well-bore. The lug ring is free to rotate in response to forces applied to the tubing once the packer tool assembly is initially set.
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Claims(20)
1. A packer apparatus comprising:
a tubular member comprising a lug guide formed substantially within its inner surface;
a mandrel operative to be coupled to an actuating means and disposed within the tubular member, the mandrel further comprising a lug ring having at least one lug disposed in the lug guide;
means for maintaining the tubular member in a substantially fixed position relative to the mandrel once said packer is initially set within a well-bore; and
wherein the lug ring is operative to rotate in response to forces applied to the actuating means once the packer tool assembly is initially set.
2. The packer apparatus of claim 1 wherein the lug guide comprises a plurality of state and intermediate positions sequentially connected through a plurality of guide segments, each of the state positions corresponding to an operational state of said packer, said packer operative in the one of the operational states corresponding to the state position currently occupied by the at least one lug.
3. The packer apparatus of claim 3 wherein the at least one lug is operative to be actuated from one state position to a next state position of the lug guide by first applying a downward axial force on the mandrel through the actuating means to urge the at least one lug into a next intermediate position of the lug guide, and then applying an upward axial force on the mandrel through the actuating means to urge the at least one lug into a next state position of the lug guide.
4. The packer apparatus of claim 3 wherein one or more of the state positions of the lug guide are each interconnected with an intermediate position through a declining guide segment, and one or more of the intermediate positions are each coupled to a state position through an inclining guide segment.
5. The packer apparatus of claim 4 wherein:
a first of the state positions of the lug guide corresponds to a set state wherein said packer is sealably anchored within the well-bore; and
a second of the state positions of the lug guide corresponds to a released state wherein said packer can be repositioned within the well-bore.
6. The packer apparatus of claim 5 wherein a third of the state positions of the lug guide corresponds to a bypassed state wherein said packer operates in a bypassed mode.
7. The packer apparatus of claim 6 wherein said packer remains sealably anchored within the well-bore while operating in the bypassed state.
8. The packer apparatus of claim 7 wherein the lug guide is circular and the plurality of state positions begins with the set state, then the bypassed state, then the released state, with intermediate states there between, and the released state connected with the set state.
9. The packer apparatus of claim 6 wherein said packer is initially disposed in the well-bore in an armed state, wherein the at least one lug is releasably restrained within a guide segment connecting the set state position to a previous intermediate position by frangible means to prevent the at least one lug from being urged into the set state until a triggering force applied to set said packer exceeds a predetermined threshold.
10. The packer apparatus of claim 8 wherein the triggering force is applied hydraulically.
11. The packer apparatus of claim 7 wherein the triggering force is applied by wireline.
12. The packer apparatus of claim 3 wherein the released state comprises a first released state position in the lug guide wherein said packer can be repositioned in an up-hole direction from its previous position in the well-bore; and a second released state position wherein said packer can be repositioned in a down-hole direction from its previous position in the well-bore.
13. The packer apparatus of claim 1 wherein the actuating means is a length of production tubing.
14. A method of actuating a packer, said packer comprising a mandrel, the mandrel comprising a rotatable lug ring, the lug ring comprising at least one lug, the mandrel being disposed within a tubular member, the at least one lug being disposed within a lug guide formed substantially within the inner surface of the tubular member and having a plurality of state positions and a plurality of intermediate positions there between, each of the state and intermediate positions sequentially interconnected through a guide segment, said method comprising:
setting the packer within a well bore, said setting further comprising maintaining the tubular member in a fixed position relative to the mandrel;
applying a downward axial force on the mandrel to urge the at least one lug through a declining one of the guide segments into a next intermediate position of the lug; and
applying an upward axial force on the mandrel to urge the at least one lug through an inclining one of the guide segments into a next state position of the lug guide.
15. The method of claim 14 wherein:
a first of the state positions of the lug guide corresponds to a set state wherein the packer is sealably anchored within the well-bore; and
a second of the state positions of the lug guide corresponds to a released state wherein the packer can be repositioned within the well-bore.
16. The method of claim 15 wherein a third of the state positions of the lug guide corresponds to a bypassed state wherein the packer operates in a bypassed mode while remaining sealably anchored within the well-bore.
17. The method of claim 16 wherein said identifying further comprises arming the packer for deployment within the well-bore, said arming further comprising releasably securing the at least one lug within a declining one of the lug guides connecting a previous intermediate position with the set state position, preventing the at least one lug from being urged into the set state position in response to a triggering force that has not exceeded a predetermined threshold.
18. The method of claim 17 further comprising:
deploying the armed packer within a well-bore; and
wherein said setting further comprises providing a triggering force to the packer that exceeds the predetermined threshold.
19. The method of claim 14 wherein the applied upward and downward forces applied to the mandrel are applied through a length of production tubing coupled to the mandrel.
20. The method of claim 18 wherein said providing further comprises pumping fluid into the packer through a length of production tubing coupled to the mandrel.
Description
BACKGROUND

When oil and gas wells are first drilled, sections of pipe are threadably secured together and the segmented pipe is lowered into the well-bore created by the drilling process. Cement is then typically introduced between the well-bore and the outside surface of the pipe to rigidly secure the pipe in place within the well-bore. This length of cemented pipe is called a casing and provides a rigid support that prevents the well-bore from collapsing in on itself Because the casing is expensive, it is desirable for the casing to be relatively permanent. Thus, it is important to protect the casing from the corrosive properties of the fluids that are typically produced from the well (e.g. oil, gas and other fluids from formations tapped by the well), as well as fluids that may be pumped down into the well for purposes of acidizing, formation fracturing, squeeze cementing, or other similar operations known to those of skill in the art.

One common technique for protecting the casing as previously described is through the use of a tool generally referred to as a packer. Packers are typically deployed within the annulus or bore of the casing and include sealing elements that, when forced against the annular surface of the casing, prevent the flow of fluids into the casing that are being produced just below it. The packer ensures that corrosive fluids are only produced through the packer and a second pipe to which the packer is attached rather than through the casing itself

A packer is deployed by first lowering the packer into the casing attached to, for example, a length of production tubing or a wireline as is known to those of skill in the art. While being lowered into the well, the packer is initially configured in a mode whereby it is able to move freely within the bore of the casing until it reaches the zone of a formation from which the well is to produce. The packer is designed such that upon reaching the appropriate depth in an “armed” mode, it can be triggered or actuated through the application of forces from above to anchor itself against the annular surface of the casing while also disposing its sealing elements against the annular surface of the casing. This process is known as “setting” the packer.

In the case of packers run into the hole already attached to tubing through which the well is to be produced, the setting of the packer is typically triggered by introducing fluid into the packer through the tubing. The bore of the packer is initially plugged on its down-hole end and as a result hydraulic forces develop inside of the packer and are used to trigger the setting process. Packers run into the hole by wireline are set by actuating a wireline device that uses gravity to trigger the setting process. Once set, the wireline and wireline device are removed and production tubing is then introduced and coupled to the packer. In either case, once the packer is set, a pump out plug is blown out of the down-hole end of the packer to enable production from a perforated portion of the casing just below it. Regardless of the manner in which the triggering or actuating force is generated and applied, most commercially available packers operate in a similar fashion internally to achieve the desired “set” configuration.

Once production from a well (or at least from a particular zone within the well) has been completed, a packer is typically removed from that location in the well-bore. Some packer designs permit the packer to be released from the set position through the application of forces to the production pipe or tubing to which the packer is attached. These forces are typically axial (i.e. along the axis of the pipe or tubing), or some may require rotational forces applied to the pipe or tubing that are translated into a torque at the packer. Other designs are permanently set and the only way they can be removed is by their destruction, such as drilling them out of the casing. Some retrievable packers can be released through application of axial force, raised or lowered to another zone, and then reset at the new depth without having to be pulled from the hole and re-armed. In the case of a reset, force applied up-hole is used to reset the packer rather than hydraulic forces or a wireline. Resetting these packers typically requires the ability to administer a rotational force to the packer from above the ground in addition to applying pulling and pushing (i.e. axial) forces.

The ever-increasing demand for oil and gas and the increasing price in response thereto, has motivated the drilling of wells to access formations that are not easily reached with a primarily vertical well-bore. Rather, access to many formations requires directional and even horizontal drilling that may involve abrupt changes in direction (referred to as “doglegs”). As a result, the pipe used for the casing and especially for producing such wells has necessitated the use of more flexible materials such as tubing that can be more easily run through horizontal and doglegged bores. The use of flexible tubing has made it virtually impossible to use packer designs that require rotational forces to manipulate the packer. This is because it is very difficult to achieve sufficient rotational force on a packer that is coupled at the end of what may be several thousand feet of flexible tubing. While a packer deployed under such conditions may initially be set using hydraulic forces, current packer designs still require the application of rotational forces if the packer is to be easily released and reset at another depth to avoid being removed from the well.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 is an illustration of a well-bore that becomes significantly horizontal to effectively access and produce from a formation.

FIGS. 2A-B form two parts of continuous drawing that illustrates a cross-sectional view of the top and bottom sections, respectively, of an embodiment of a hydraulically actuated packer incorporating aspects of the invention.

FIG. 2C illustrates a cross-sectional view of the top section of an embodiment of a wireline actuated packer incorporating various features of the invention.

FIGS. 3A-3B form two parts of a continuous drawing illustrating a cross-sectional view of the top and bottom sections of the hydraulically actuated packer of FIGS. 2A-B after being initially set.

FIG. 4 illustrates a cross-sectional view of the top section of the hydraulically actuated embodiment of FIGS. 3A-B wherein a bypass has been enabled around packing elements of the packer and into the annulus of the casing in accordance with various aspects of the invention.

FIGS. 5A-5B show magnified quarter-sectional views of the top and bottom portions of the hydraulically actuated embodiment of FIGS. 2A, 2B, 3A and 3B incorporating various features of the invention.

FIG. 5C illustrates an embodiment of the rotating lug assembly in accordance with the invention.

FIG. 6 is a two-dimensional illustration of an embodiment of a groove or lug guide in accordance with the invention in which the rotating lug travels to achieve actuation of the packer into various operational states, including “set,” “bypassed” and “released” states.

FIG. 7 is a two-dimensional illustration of an embodiment of a groove pattern in accordance with the invention in which the rotating lug travels to achieve actuation of the packer into various operational states, including “set,” “released” and “bypass” modes, as well as an up-hole and down-hole position of the lug for purposes of relocating the packer within the well-bore prior to resetting the packer.

NOTATION AND NOMENCLATURE

Certain terms are used throughout the following description and in the claims to refer to particular features, apparatus, procedures, processes and actions resulting therefrom. Those skilled in the art may refer to an apparatus, procedure, process, result or a feature thereof by different names. This document does not intend to distinguish between components, procedures or results that differ in name but not function. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”

DETAILED DESCRIPTION

The following discussion is directed to various embodiments of the invention. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted as, or otherwise be used for limiting the scope of the disclosure, including the claims, unless otherwise expressly specified herein. For example, an embodiment may be hydraulically actuated (i.e. set) if run into the hole coupled to tubing, yet various aspects of the invention can also be incorporated into embodiments using other known setting techniques, such as using a wireline device. In addition, one skilled in the art will understand that the following description has broad application, and the discussion of any particular embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment. For example, while the various embodiments may employ one type of technique for initially setting the packer, packers employing other known techniques are considered within the scope of the present invention.

With reference to FIG. 1, a producing well is illustrated including a drilling rig 100, a directionally drilled well-bore 102 tapping formation 104. Disposed inside of well-bore 102 is a segmented casing 110. Because of the directional bend required in the well-bore 102 to access formation 104, a length of flexible tubing 112 is typically disposed within the casing 110 through which the well produces from formation 104. Perforations 108 are formed in the casing 102 through which fluids are drawn into the casing 110. Packer 106 is typically disposed and “set” just above the perforations to prevent the fluids from continuing up through the casing 110. The packer 106 instead forces the fluids drawn in through the perforations 108 to be directed into the bore of packer 106 and into the production tubing 112 to which the packer 106 is coupled at its up-hole end.

As previously described, packers have been designed that can be released, re-positioned within the well bore, and then re-set without having to be removed from the well-bore. One such packer design is disclosed in U.S. Pat. No. 5,197,547 (hereinafter the '547 patent), which is incorporated herein in its entirety by this reference. The packer design disclosed in the '547 patent requires a rotational force, along with axially applied forces, to be applied at the up-hole end of the production medium to release the packer from the “set” mode and reset the packer while disposed within the well-bore. The application of torque to actuate the packer in this manner becomes exceedingly difficult when disposed in a directionally drilled well-bore such as that illustrated in FIG. 1. When tubing is used as the production medium, the ability to translate torque applied at the up-hole end of the tubing to a sufficient rotational force at the packer is virtually impossible, especially as the depth of the packer's deployment (and thus the length of the tubing) increases.

Some packer designs employed under the drilling conditions described in FIG. 1 must be destructively drilled out of the well-bore to complete the well or at least a particular zone in a well (these are sometimes referred to as permanent packers). At best, packer designs implemented under the conditions generally described in FIG. 1 might have the capability of being released through the application of axial forces on the tubing. Once released, however, even they must be pulled from the well bore and “re-armed” if they are to be redeployed. Packer designs capable of being reset without being removed and rearmed have heretofore required rotational forces that are difficult to create with tubing as was previously discussed. One benefit of the packer assembly of the present invention provides the ability for a packer, especially one deployed under conditions such as that illustrated in FIG. 1, to be released, repositioned and reset (i.e. actuated) through application of only axially applied (i.e. pulling and pushing) forces on the tubing T.

Moreover, aspects of the present invention also permits an additional “bypassed” state, between the “set” and “released” modes, where fluids are permitted to bypass the seals into the casing for purposes of performing circulation while the packer remains in a “set” state. Thus, while in this bypass state, the packer remains anchored within the casing and the sealing elements remain deployed until circulation is complete. During circulation, fluid is forced down through the production tubing causing fluids resting at the bottom of the well to be lifted up from the bottom of the well. These fluids are then forced into interstitial areas of the packer outside of the packer bore, around the sealing elements and ultimately into the annulus of the casing. This serves to avoid contact between the fluids being produced during circulation and the sealing elements, which would otherwise degrade the sealing elements and quickly render them ineffectual. Moreover, it is an added benefit that the packer remains anchored within the casing during circulation.

FIGS. 2A and 2B illustrate the upper and lower portions respectively of an embodiment of a packer assembly, disposed in a well casing C that incorporates various features of the invention. The embodiment of FIGS. 2A and 2B can be run into a well-bore (not shown) on tubing T and is actuated (i.e. triggered) hydraulically to become “set.” The tubing T can be threadedly coupled to an upper mandrel (or mandrel sub) 31 by threads 20, thus rendering the bore 8 of tubing T in communication with the packer bore 26 a. The packer bore 26 a is formed by upper mandrel 31 and various other subcomponents that together form a packer mandrel as will be described in detail below.

The mandrel sub 31 is telescopically received through the upper end of a body B, which is releasably connected to mandrel sub 31 by suitable frangible means such as shear pins 32 as is well known to those of skill in the art. In an embodiment, shear pins 32 may extend through body B and into sub 31. An annular cap 33 is threadedly engaged in the upper end of body B at threads 134 and the cap 33 terminates in the shoulder 34 internally of body B as shown. Mandrel sub 31 has shoulder 35 extending outwardly between mandrel sub 31 and body B which engages shoulder 34 when the packer is being unset so that mandrel sub 31 may be moved up by the tubing T.

As shown in FIG. 2A, the body B forms a hollow spring cage housing 55 a containing a resilient element 55. In an embodiment, the shear pins 32 are shown extending through cap 33 and into mandrel sub 31, but those of skill in the art will recognize that the location and type of such frangible means may be other than that in the example embodiment without exceeding the scope of the present invention. In an embodiment, the longitudinal body B is hollow and resilient element 55 (which may be a coil spring or some other equivalent resilient element) is positioned therein between the annular shoulder 56 at the lower end of body B and the shoulder 35 a formed by the end of the mandrel sub 31 as shown.

The spring element 55 is typically collapsed when the tool is assembled as the body B is moved up on the packer mandrel to be secured to the mandrel sub 31 by the frangible means 32. It remains collapsed or partially collapsed as the body B is moved down along the packer mandrel by hydraulic forces created during the setting process as will be described in more detail below. Those of skill in the art will recognize that other known embodiments of packers may not make use of a resilient element 55. For example, an alternate embodiment of a packer that does not make use of a resilient element 55 is disclosed in the above-referenced '547 patent.

The packer mandrel may be formed of any suitable number of tubular portions, in addition to mandrel sub 31, as is known to those of skill in the art. In an embodiment, this may include an upper tubular portion or sub 14 (which is threadedly connected to mandrel sub 31 at 16) and a lower tubular portion or sub 15, which are threadedly connected together through a rotatable lug assembly 500. A more detailed description of an embodiment of the rotatable lug assembly will be presented later in the description.

In an embodiment, a member referred to generally at 26 (and is sometimes referred to as a packer support or a rubber mandrel), provides a support for the rubber sealing elements P that are used to seal the casing C when the packer is set. The packer support 26 includes a support sleeve 27 and upper 102 and lower 104 slip and cone assemblies. It serves to extend or move the packer or seal elements referred to generally at P, along with the upper and lower slip and cone anchor assemblies 102, 104, into sealing and securing relation with the inner surface or annular wall of the casing C.

In an embodiment, the upper assembly 102 includes upper slips 57 supported at the lower end of the body B in a manner well known to those skilled in the art and are adjacent to (and while in the “armed” state, preferably not in contact with) an annular, tapered surface 58 a forming a conical surface or cone supported on the upper end of the packer support 26. The lower assembly 104 includes a movable end portion 60 on the lower end of packer support 26, which has an annular tapered surface 61 forming a conical surface or cones for engagement with adjacent lower slips 62 on member 25 when the packer is set. Those of skill in the art will recognize that the structure and relationship of the cones 58 a, 61 and slips 57, 62 may be accomplished in any manner suitable for setting the packer.

In an embodiment, the upper end of packer support 26 is secured by suitable means such as threads 56 c to support sleeve 27 as shown in FIG. 2A. The packers or seal elements P are supported thereon for movement as is well-known in the art. The lower end portion 29 of packer support 26 is movable relative to support sleeve 27 and packer support 26 to expand or extend the packers P into sealing engagement with the annular surface of the casing C. An annular shoulder 67 on support sleeve 27 engages inwardly extending shoulder 68 on the movable end portion 60 and supports the movable end portion on packer support 26 while accommodating movement of such end portion 60 when the packer is set. Triggering the packer to set causes forces to compress the packers P and extends them and the slip and cone arrangements 102, 104 into sealing and securing relation within the annular opening.

In an embodiment, the support sleeve 27 extends longitudinally of the packer mandrel as shown in the drawings and terminates in end cap 69, which may be threadedly engaged thereon and assists in supporting the partially surrounding member 25 on the sleeve 27. The member 25 may be formed of any desired number of tubular subs or portions, and may include an upper tubular sub 72 and a lower tubular sub 25 a, which may be threadedly coupled as shown at 25 b or coupled in any appropriate manner as the packer is assembled. The member 25 includes a groove 606 formed within its internal surface into which rotating lugs 514 a and 514 b (FIG. 5C) are disposed in a preset or armed position as will be described in greater detail below.

In an embodiment, drag blocks referred to generally at 70 and springs 71 are supported in the tubular sub 72. Member 25 may be formed by the upper tubular sub or member 72 and the lower tubular sub or member 25 a, which are connected together to form the member 25 as previously discussed. When the drag blocks 70 are engaged during the initial setting of the packer, they are urged outwardly by spring means 71 for engagement with the casing C to enable the packer mandrel to be vertically manipulated relative to the member 25. Vertically manipulating the mandrel causes lugs 514 a, 514 b to be advanced within groove 606 to achieve various operational states of the packer, including the “bypassed” and “released” states, and then back to the “set” state if desired. A more detailed description of the rotatable lug assembly 500, FIG. 5C and the operational states will be presented below.

In an embodiment, the springs 71 will be initially collapsed and secured to the support sleeve 27 and member 25 prior to deployment and while in the “armed” state prior to triggering the setting of the packer. Shear pins 72 a may be employed to maintain the drag blocks in this inoperative or non-engaged state. Shear pins 72 a may also be used to secure the member 25 so that slips 62 are supported in a non-engaging position adjacent the tapered surface (i.e. cone) 61 while the packer is deployed within the well bore casing C. Those of skill in the art will recognize that other equivalent means may be employed to provide the necessary anchoring of the tubular member 25 to render it stationary with respect to the packer mandrel without consequence to the patentability of the invention as disclosed.

In an embodiment, rotatable lug assembly 500, FIG. 5C couples upper 14 and lower 15 mandrel subs together with a rotatable lug ring 510 there between. The packer mandrel, along with the rotatable lug assembly 500, is disposed within tubular member sub 25 a. A groove or lug guide 606, FIGS. 6 and 7 is formed within the inside surface of the tubular member sub 25 a. The groove provides a guide channel in which lugs 514 a, b travel between mandrel resting points (e.g. 602, 604, 608, 612), each representing a particular functional state of the packer while the mandrel is in that position. Because the rotatable lug ring 510 is free to rotate, placing downward force on the mandrel will cause the lug to travel through the groove to the extent that the components within the packer can compress (illustrated by dotted lines at 603, 605, and 607). Once in one of the bottom positions, pulling up on the mandrel causes the lugs 512 to rotate into one of the functional positions and remain there until another downward force is applied.

In an embodiment, the groove or guide patterns 606 of FIG. 6 or 7 can be repeated over 180 degrees of the tubular sub 25 a and thus, each lug 514 a, b makes one trip through the same pattern over 180 degrees of rotation. Those of skill in the art will recognize that variations of the embodiment of rotatable lug assembly 500 may be made without exceeding the intended scope of the invention. For example, the pattern could also be formed over 360 degrees such that the rotatable lug ring 510 will rotate one complete turn through the entire guide before repeating. The ring 510 could also be implemented with only one lug rather than two.

In an embodiment of the guide 606, FIG. 6, the pattern can have a first location 602 wherein when the lugs 514 (and thus the mandrel) are at rest, and the packer operates in the “set” state. Actuating the mandrel with a down-hole axial force on the tubing T and then with a pulling or up-hole axial force will cause the lugs 514 to rotate into and come to rest in position 604, wherein the packer is in the “bypassed” state. Again, actuating the mandrel as described above causes the lugs 514 to rotate into the position 608, wherein the packer is in the “released” state. From their, the packer can be pulled up-hole, either out of the well completely or to another higher zone location. In the latter situation, the packer can be actuated as described before, advancing the lugs into the set state once again at 602. In an embodiment as shown in FIG. 7, an additional position at 612 is added permitting the packer to be lowered down-hole after release. Downward force and then a pull upward as previously described places the packer back into position 602 and into the “set” state once again.

In an embodiment, a pump out plug referred to generally at 36 is shown adjacent the lower end 29 of the mandrel sub 15. The pump out plug may include a tubular housing 37 threadedly connected to the mandrel sub 15, and a plug portion 38 releasably secured in the housing by any suitable means such as a frangible member, or shear pins 39. After the packer is set, sufficient hydraulic pressure can be applied to the bore of the mandrel to shear the pin(s) 39 and release the plug 38 to enable fluid flow through the mandrel bore 26 a and the packer as desired.

In assembling a packer for deployment that includes features of the present invention, virtually all of the components except for the rotating lug assembly 500 and lower tubular sub 25 a, may be assembled using any number of well-known designs in any well-known manner to place such a design in a “preset” or “armed” state. With reference to the example embodiment of FIGS. 2A and 2B, mandrel sub 31 and cap 33 are assembled in a well known manner on body B, with a resilient element 55 disposed therein. Body B is then releasably secured to the mandrel of the packer at mandrel sub 31 by any suitable frangible means well known in the art such as shear pins 32. As previously discussed, those of skill in the art will recognize that body B may be employed without the spring element 55. This does not affect the manner in which features of the present invention are incorporated into the embodiment.

In an embodiment, shear pins 72 a are introduced as shown in FIG. 2B to extend through member 25 a and into support sleeve 27 to secure support sleeve 27 in position as the packer is lowered into the well bore. The mandrel (i.e. subs 14, 15 coupled through its rotatable lug assembly 500) is initially inserted through the entry point 610 of groove 606. The lugs 514 are located at initial position 601, which will be indicated by the fact that the lugs 514 can be viewed and accessed through an opening that extends completely through the tubular sub 26 a. Shear pins can be inserted through this opening and the lugs 514 to hold the rotatable lug assembly 500 into this position. Once assembled and initially set, those of skill in the art will recognize that the mandrel will not be able to exit the guide 606, but will be stopped at the point at which the components of the packer have reached maximum compression, for example, at lug location 605.

In an embodiment, the packer is threadedly secured with the tubing T as shown and is lowered into a well-bore casing C. Once the packer has been lowered to the desired position within casing C, the packer is hydraulically triggered to become “set” in a manner well known in the art. Fluid is pumped down through the tubing T and into the bore 26 a of the packer. Internal pressure begins building within the packer, including inside the spring housing 55 a of body B as the fluid flows into the housing 55 a through channels 5, FIG. 2A. The pressure inside the spring housing 55 begins forcing body B downward toward the top slips 57 of the upper slips and cones arrangement 102 and forces are applied upward against sub 31. When the resulting shearing force on shear pins 32 exceeds some predetermined value, the shearing pins give way and body B is able to press downward on the slips 57, as well as the rubber mandrel 26 generally.

Body B continues to press downwardly and the top slips 57 are pressed downward and make initial contact with top cones (not shown) of the upper slip and cone arrangement 102. Continued movement of the packer support or rubber mandrel 26 (including support sleeve 27) shears pins 72 a to release the member 25 and the drag block springs 71 of drag block assembly 70. These forces are also translated to the rubber mandrel 26, causing the top cones (not shown) of lower slip and cone arrangements 104 to initially contact the bottom slips 62. This results because second end portion 60 of the packer support 26 contacts lower slips 62 to force the lower slips 62 and tapered surface 61 out into securing engagement with the surface defining the opening in which the present invention is positioned. This stops the downward movement of movable portion 60 of the packer support 26.

Continued downward hydraulic force on body B and packer support 26 forces packer support 26, packer P and support sleeve 27 downward. Packer P is thus forced against packer support second end portion 60 which forces or extends the packer or seal elements P out into sealing engagement with the annular surface of the casing C. The above action continues until the packer P and the upper slip 57 of upper slip and cone assembly 102 is firmly engaged with the annular surface of the casing C. Finally, the hydraulic forces cause the shear pins 512 in the rotatable lug assembly to sheer, which frees the packer mandrel (e.g. subs 31, 14 and 15) to move freely with respect to tubular member 25, including subs 25 a and 72. This causes the packer mandrel to move downwardly and causes rotatable lug 510, (FIG. 5C) to rotate such that lugs 514 a, b come to rest at the “set” position (602, FIGS. 6 and 7). The foregoing mechanical sequence that occurs during the setting process as triggered from the “armed” condition of the packer actually causes a relatively short longitudinal movement of the components supported on the rubber mandrel 26.

Once set, pump-out plug 38 can be blown out by shearing pins 39. With plug 38 removed, the well may begin producing through the lower end 29 of the packer. Those of skill in the art will recognize that the packer is designed to “avalanche” into the “set” state by sequencing the failure of the various shear pins in the manner described above. This can be accomplished by designing the shear pins to fail at increasing thresholds of force to effectuate the sequential nature of the setting process.

An illustration of the embodiment of FIGS. 2A and 2B with its various components in the “set” state is shown in FIGS. 3A and 3B. Those of skill in the art will recognize that variations in packer designs to accomplish this sequential process may be varied in numerous ways to achieve the same result. For example, the thickness or number of shear pins can affect the threshold force at which they shear. It is also possible to locate the shear pins or other components in different locations. Those of skill in the art will recognize that the manner in which the packer is designed to achieve the “set” state is not pertinent to the scope of the instant invention.

In addition, while the embodiment illustrated in FIGS. 2A, 2B, 3A, 3B, 5A and 5B is one triggered to set hydraulically, those of skill in the art will recognize that embodiments actuated using other techniques to create the actuating forces are well-known and may be used without impact upon the manner in which features of the present invention are employed therein. For example, the embodiment could be adapted to be set through wireline techniques known to those of skill in the art. FIG. 2C illustrates the use of a wireline device W by which to establish the downward force on body B to initiate or trigger the set process. One difference in the two embodiments is that the wireline embodiment does not require the channels 5, FIG. 2A that provide fluid communication between the packer bore 26 a and the spring housing 55 a. The components comprising and manner of operation of wireline actuating devices are well-known to those of skill in the art and thus will not be detailed here.

Once production from a current zone has been completed, or circulation is desired, an operator at the surface can apply a force axially along the tubing that causes the lugs 514 to move away from the “set” rest point 602 in guide 606 and to contact declined surface 609 of guide 606. The axially applied pushing force will cause the rotatable lug ring 510 to rotate, causing the lugs 514 to travel down the guide 606 and to reach vertical segment 630. There, the internal components of the packer can become substantially compressed and begin resisting any further travel of the packer mandrel in the down-hole direction such as at position 607. This is because the packer is still set and all of the anchoring and sealing components are maximally disposed against the inside surface of the casing C. A pulling force applied to the tubing T then causes the packer mandrel to pull up and causes the lugs 514 to travel to the top of vertical groove segment 630 until it contacts inclined surface 632. At this point, the lug ring 510 rotates and causes the lugs 514 to travel into position 604. This position places the packer into the “bypassed” state as will be described in more detail below. In the bypassed state, the mandrel has been pulled up, but not to the level at which the anchoring and sealing components will be released. The packer can therefore be bypassed during, for example, circulation can be advantageously conducted while the packer is still in a sealed and anchored state.

Once circulation is complete, the packer can be actuated again, as previously described, first with a force directed axially along the tubing T and down-hole in direction. This will bring the lugs 514 into the vertical segment 636 of guide 606. Pulling up-hole on the tubing T will cause the lugs 514 to move up and into the highest state position in the guide 606 at position 608. At this point, the body B will be completely extended toward the upper mandrel 31 and the spring element 55 will be substantially uncompressed. The force will be just sufficient to begin lifting the upper slips 57 from the top cones (not shown) and the internal upper and lower anchoring components, as well as the sealing elements will begin to release from their position against the inner wall of the casing C. The mechanisms by which the slips and sealing elements can be made to release are well-known to those of skill in the art. Once released, the packer can be lifted by the tubing T either completely from the hole, or to a new location that is higher than the previous location in the well-bore.

In the embodiment of guide 606 disclosed in FIG. 6, the packer can either be lifted as described above, or it can actually be re-set by pushing down on the tubing T, causing the lug to travel down the vertical guide segment 638 to the point where the upper mandrel begins to compress the spring mechanism 55, causing the process by which the upper slips 57 begin to re-engage with the upper cone of cones 58. This movement continues, aided by the drag blocks 70 which are still engaged and provide just enough resistance to get the setting sequence started again as was previously described above for the initial setting of the packer. The only difference is that the drag blocks 70 are already engaged. As the upper 58 and lower 62 slips are pressed back out, they engage the casing C while the sealing elements P are again forced out to engage the casing C again as well. Eventually, the lugs 514 no longer move substantially downward in vertical groove segment 638, reaching the point (e.g. at 605) wherein little if any more compression is possible. A force applied in the up-hole direction pulls the packer mandrel and thus the lugs 514 back up against inclined guide surface 640, causing the lugs 514 to achieve the resting position 602 at which the packer is returned to the “set” state.

In the embodiment of guide 606 as illustrated in FIG. 7, an additional rest position 612 is added after 608 in the sequence. This additional resting position provided after the packer is released at 608 is to provide the ability to lower the packer deeper into the well prior to resetting it as described above. Once again, a force directed up-hole will cause the lugs 514 to move into the intermediate position 650, from where the packer can be moved up-hole if desired. A force directed down-hole while in 650 will cause the lugs 514 to enter vertical segment 638 from where the packer can be reset as was described above.

When the packer is placed into the “bypassed” mode (i.e. the lugs 514 are actuated into position 604), the position of the rubber mandrel 26 is raised just enough to leave the packer in the set mode, but enough to cause bypass channels 410 to be raised and to come into communication with upper bypass channels 412. The proximate relationship of the bypass channels 410, 412 is illustrated in FIG. 4. During circulation, fluid produced through the circulation process is permitted to enter the bypass channels 410, which permit the fluid to flow past the still deployed sealing elements P. The fluid is then permitted to enter the overlapping upper bypass channels 412, and ultimately into the casing C through the upper slip and cone assemblies 102. One of the advantages of this “bypassed” state is that the packer remains securely anchored as in the “set” state, which ensures that the packer is not as likely to be blown out of the well during circulation. Moreover, the sealing elements P do not some in contact with the fluid produced and thus are as likely to corrode.

Various embodiments of the rotating lug assembly (500, FIG. 5C) and various embodiments of the groove or lug guide (606, FIGS. 6, 7) can be incorporated into existing packer designs known to those of skill in the art. The rotatable lug assembly is shear pinned to a start position that ensures that the packers are able to become “set” as they were previously designed, with the packer mandrel becoming free to be actuated after the packer has achieved its initial “set” state. The rotatable lug assembly and lug guide permit the lugs to move through the guide by applying only forces along the axis of the tubing because the lug is able to freely rotate as the lugs are forced to move through the guide by the actuating forces as previously described. As a result, packers can be triggered into their “set” state in accordance with their well-known design, and then may be sequenced into other desirable states. This is accomplished through simple application of sufficient down-hole force axially along the tubing to take the packer out of the resting position in its current state, and then applying sufficient up-hole force axially along the tubing to cause the lugs to move through their guide as they rotate on their rotatable lug ring.

Thus, a packer may be bypassed while still being set, may be released from its set position for repositioning movement or complete removal from the well-bore, and may be reset at a different position within the well-bore without the need to remove the packer and to rearm the packer for redeployment. Further, movement between these states of operation does not require any rotational forces to be applied and translated down the tubing, which is extremely difficult to accomplish reliably.

The foregoing is by way of example only, and changes can be made without departing from the scope of the invention which is more properly encompassed by the following claims.

Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US7673693 *Jun 13, 2007Mar 9, 2010Halliburton Energy Services, Inc.Hydraulic coiled tubing retrievable bridge plug
Classifications
U.S. Classification166/387, 166/134
International ClassificationE21B33/13, E21B23/04
Cooperative ClassificationE21B23/06, E21B33/12, E21B23/006
European ClassificationE21B23/06, E21B33/12, E21B23/00M2