ACTUATED PACKER ARRANGEMENT HAVING A DEGRADABLE LAYER FOR A SEAL
A packer arrangement for forming a seal between an inner tubular string and an outer tubular string in a borehole includes: an outer tubular string member defining an axial flowbore and having an associated packer setting mechanism; a packer device disposed at least partially within the outer tubular string member to form a seal against an inner tubular string, the packer device including a degradable layer for temporarily and at least partially protecting the packer device; an inner tubular string member to be disposed within the flowbore of the outer tubular string member; and an actuator carried on the inner tubular string member, the actuator being operable to actuate the packer setting mechanism to set the packer device against the inner tubular string.
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Packers are used for securing production tubing inside of casing or a liner within a borehole, for example. Packers are also used to create separate zones within a borehole. Unfortunately, conventional packers and techniques for setting packers results in a reduction of usable diameter within the well. This is because the packer is carried by a conveyance tubular (such as a production tubing string) that is of smaller diameter than the tubing or casing against which it is set. The packer is then set within the annular space between the conveyance tubular and the outer tubing or casing. Once set, the useable diameter of the well (i.e., the diameter through which production fluid can flow or tools can be passed) becomes the inner diameter of the conveyance tubular. However, the components of the packer device (including slips, elastomeric seals, setting sleeves and so forth) inherently occupy space between the inner and outer tubulars. For example, a borehole having standard 21.40 lb. casing with an outer diameter of 5 inches, would have an inner diameter of 4.126 inches. It would be desirable to run into the casing a string of tubing having an outer diameter of approximately 4 inches, which would allow for a tubing string with a large cross-section area for fluid flow and tool passage. However, the presence of packer components on the outside of the tubing string will dictate that a smaller size tubing string (such as 2⅞″) be run. Over an inch of diameter in usable area is lost due to the presence of both the inner production tubing string and the packer device that is set within the space between the production tubing string and the casing.
SUMMARYA packer arrangement for forming a seal between an inner tubular string and an outer tubular string in a borehole includes: an outer tubular string member defining an axial flowbore and having an associated packer setting mechanism; a packer device disposed at least partially within the outer tubular string member to form a seal against an inner tubular string, the packer device including a degradable layer for temporarily and at least partially protecting the packer device; an inner tubular string member to be disposed within the flowbore of the outer tubular string member; and an actuator carried on the inner tubular string member, the actuator being operable to actuate the packer setting mechanism to set the packer device against the inner tubular string.
The casing coupler 18 includes an axial bore 26 for passage of tools and fluid through the casing coupler 18. The bore 26 has an enlarged diameter chamber portion 28. A packer device 30 is disposed within the enlarged diameter chamber portion 28. The packer device 30 includes a cylindrical elastomeric packer sealing element 32 and a cylindrical setting sleeve 34. The setting sleeve 34 is a compression member that is axially moveable within the enlarged diameter portion 28 of the bore 26. The setting sleeve 34 features an axial bore 36 with an engagement profile 38 within. A ratchet-style body lock ring assembly 37, of a type known in the art, is associated with the outer radial diameter surface of the setting sleeve 34. The body lock ring assembly 37 provides for limited one-way movement of the setting sleeve 34 with respect to the surrounding casing coupler 18.
To activate the packer device 30, the production tubing string 40 and setting tool 42 are inserted into the casing string 17. The tapered camming surface 52 of each collet 46 will contact the upper ends of the sealing element 32 and the setting sleeve 34 and deflect the collet 46 radially inwardly. When the radially enlarged portion 48 of each collet 46 becomes aligned with the engagement profile 38 of the setting sleeve 34, each collet 46 will snap radially outwardly so that the radially enlarged portion 48 becomes disposed within the engagement profile 38, as shown in
Because the components of the packer device 30 are retained within an enlarged diameter portion 28 of the casing coupler 18, the gap between the exterior of the tubing string 40 and the interior of the casing string 17 can be quite small. For example, in a casing string made up of 35.3 lb. Casing sections with an external diameter of 5 inches, an interior diameter of 4.126 inches would be available. With the large bore, external packer arrangement described above, it would be possible to insert a tubing string 17 having a diameter approximating 4 inches, rather than a smaller diameter tubing string (i.e., 2⅞″). In fact, the use of a larger diameter tubing string is desirable for two reasons. First, the resulting available cross-sectional flow and work bore area of the tubing string 17 will be larger. Second, the sealing element 32 of the packer device 30 can more easily and securely seal against the larger diameter tubing string 17.
In
Also included in the packer device 30″ is a setting sleeve member 82 having a generally cylindrical sleeve body 84 that defines a central axial bore 86 with an interior engagement profile 88. A body lock ring assembly 37 is associated with the outer radial surface of the sleeve body 84 and provides for limited one-way movement of the setting sleeve member 82 with respect to the surrounding casing coupler 18. A tapered bore portion 90 is located proximate the upper end 92 of the body 84 thereby providing a ramped surface that is in abutting contact with the outer radial surface 77 of the sealing element 72.
Variations on the packer device 30″ are possible wherein the sealing element 72 is formed entirely of metal and without the elastomeric sealing portions 76. When the packer device 30″ is set, a metal-to-metal seal is formed. Such a variation may be advantageous in many instances wherein, for example, there is a minimum amount of movement of the components needed to form an effective seal. Where a fully metallic sealing element is employed, the sealing element may be a bellow-type seal or a hydroformed seal or ring element. Additionally, a metal-to-metal seal may incorporate toothed slips, of a type known in the art, or other mechanisms for creating a biting engagement between the tubing string 40 and the surrounding casing string 17.
Currently, each of the packer devices 30, 30′ and 30″ are permanently set packer devices. They may be removed from the borehole, if desired, by use of a suitable milling tool, as is known in the art.
The chamber 106 may be an atmospheric chamber or a more highly pressurized chamber, which will create a pressure differential across the seal member 118 which will urge the end portion 112 of the outer collar 102 toward the sealing element 32 and a set position. In variations on this embodiment, the chamber 106 could be replaced with a mechanical spring to serve as an energy source to bias the outer collar 102 toward the sealing element 32. Additionally, the transmitter 124 and actuator 122 could be replaced by a mechanical trigger arrangement wherein the spring is mechanically released from a compressed state by engaging a release latch for the spring with an engagement member within the tubing string 40.
In operation, the packer device 100 is in the initially unset position shown in
Referring now to
A fluid chamber 140 is defined between the setting piston 132 and the casing string 17 within the enlarged chamber 28. Fluid flow ports 142 are disposed through the setting piston 132 to permit fluid communication between the fluid chamber 140 and the interior flowbore 144 of the setting piston 132. Fluid seals 146 are provided between the setting piston 132 and the casing coupler 18 to ensure fluid tightness of the fluid chamber 140.
The lower end of the tubing string 40 is closed off by a plug 148. The plug 148 is preferably a temporary or removable plug that can be removed to allow flow through the tubing string 40 at a later point during production operations. Ports 150 are disposed through the side of the tubing string 40.
In operation, the packer device 130 is initially in the unset position depicted in
The sealing element 200 may be a metallic sealing element or a non-metallic sealing element. In one embodiment, the sealing element 200 is an elastomeric sealing element. In another embodiment, the sealing element 200 is a mechanical sealing element and contains toothed portions to form a biting engagement with the ductile tube 201. The design of the sealing element 200 will preferably provide fluid sealing and mechanical retention between the inflatable tubing 201 and the casing coupler 18. The sealing contact between the ductile tube 201 and the sealing element 200 forms a retention device between the tubing string 40 and the surrounding casing string that is capable of withstanding high axial tubing loads.
Those of skill in the art will appreciate that the present invention provides a novel borehole packer arrangement as well as a borehole production system that includes an outer tubular string having an enlarged diameter chamber portion; an inner tubular string; and a packer device disposed at least partially within the enlarged chamber to form a seal against the inner tubular string.
The present invention also provides methods of establishing a seal between inner and outer tubular string members within a borehole wherein a packer device is disposed within an enlarged diameter chamber portion of an outer tubular string. The outer tubular string, such as a string of casing or liner, is run into a borehole and cemented in place. At this point the packer device is in an unset position. Next, the inner tubular string is run into the outer tubular string to a predetermined depth or position within the outer string. The predetermined depth or position will typically correspond to the proper location of a tool, such as a production nipple, inside the outer tubular string. The packer device is then actuated from an unset to a set position to form a seal against a member of the inner tubular string.
In each of the embodiments hereof, a disintegratable, dissolvable, corrodible, decomposable, or otherwise easily defeatable protector layer may be employed, for example, a protective layer 205 is shown in
In one embodiment, for example, the layer 205 is removed by exposure to a downhole fluid, such as water, oil, acid, etc. After the layer 205 has been removed, the packer device 30 would operate as described above with respect to
Another embodiment is shown in
Materials appropriate for the purpose of degradable protective layers as described herein are lightweight, high-strength metallic materials. Examples of suitable materials and their methods of manufacture are given in United States Patent Publication No. 2011/0135953 (Xu et al.), which Patent Publication is hereby incorporated by reference in its entirety. These lightweight, high-strength and selectably and controllably degradable materials include fully-dense, sintered powder compacts formed from coated powder materials that include various lightweight particle cores and core materials having various single layer and multilayer nanoscale coatings. These powder compacts are made from coated metallic powders that include various electrochemically-active (e.g., having relatively higher standard oxidation potentials) lightweight, high-strength particle cores and core materials, such as electrochemically active metals, that are dispersed within a cellular nanomatrix formed from the various nanoscale metallic coating layers of metallic coating materials, and are particularly useful in borehole applications. Suitable core materials include electrochemically active metals having a standard oxidation potential greater than or equal to that of Zn, including as Mg, Al, Mn or Zn or alloys or combinations thereof. For example, tertiary Mg—Al—X alloys may include, by weight, up to about 85% Mg, up to about 15% Al and up to about 5% X, where X is another material. The core material may also include a rare earth element such as Sc, Y, La, Ce, Pr, Nd or Er, or a combination of rare earth elements. In other embodiments, the materials could include other metals having a standard oxidation potential less than that of Zn. Also, suitable non-metallic materials include ceramics, glasses (e.g., hollow glass microspheres), carbon, or a combination thereof. In one embodiment, the material has a substantially uniform average thickness between dispersed particles of about 50 nm to about 5000 nm. In one embodiment, the coating layers are formed from Al, Ni, W or Al2O3, or combinations thereof. In one embodiment, the coating is a multi-layer coating, for example, comprising a first Al layer, a Al2O3 layer, and a second Al layer. In some embodiments, the coating may have a thickness of about 25 nm to about 2500 nm.
These powder compacts provide a unique and advantageous combination of mechanical strength properties, such as compression and shear strength, low density and selectable and controllable corrosion properties, particularly rapid and controlled dissolution in various borehole fluids. The fluids may include any number of ionic fluids or highly polar fluids, such as those that contain various chlorides. Examples include fluids comprising potassium chloride (KCl), hydrochloric acid (HCl), calcium chloride (CaCl2), calcium bromide (CaBr2) or zinc bromide (ZnBr2). For example, the particle core and coating layers of these powders may be selected to provide sintered powder compacts suitable for use as high strength engineered materials having a compressive strength and shear strength comparable to various other engineered materials, including carbon, stainless and alloy steels, but which also have a low density comparable to various polymers, elastomers, low-density porous ceramics and composite materials.
While one or more embodiments have been shown and described, modifications and substitutions may be made thereto without departing from the spirit and scope of the invention. Accordingly, it is to be understood that the present invention has been described by way of illustrations and not limitation.
Claims
1. A packer arrangement for forming a seal between an inner tubular string and an outer tubular string in a borehole, the packer arrangement comprising:
- an outer tubular string member defining an axial flowbore and having an associated packer setting mechanism;
- a packer device disposed at least partially within the outer tubular string member to form a seal against an inner tubular string, the packer device including a degradable layer for temporarily and at least partially protecting the packer device;
- an inner tubular string member to be disposed within the flowbore of the outer tubular string member; and
- an actuator carried on the inner tubular string member, the actuator being operable to actuate the packer setting mechanism to set the packer device against the inner tubular string.
2. The packer arrangement of claim 1 wherein:
- the packer setting mechanism comprises:
- a setting member having a generally cylindrical body defining an axial bore, the axial bore of the setting member having a ramped surface to contact the packer device and an engagement profile; and
- the actuator comprises a collet to engage the engagement profile of the setting member to actuate the packer setting mechanism by urging the ramped surface of the setting member axially against the packer device.
3. The packer arrangement of claim 2 wherein the setting member is further axially moveable within the outer tubular string member between a first position, wherein the packer device is not set, and a second position, wherein the packer device is set.
4. The packer arrangement of claim 3 further comprising a body lock ring assembly to provide for one-way movement of the setting member with respect to the outer tubular string member.
5. The packer arrangement of claim 1 wherein:
- the packer setting mechanism comprises:
- an energy source operable to set the packer device against the inner tubular string member;
- a transceiver to receive a triggering signal and, in response to said signal, activating the energy source to set the packer device; and
- the actuator comprises a signal transmitter to provide a triggering signal to the transceiver.
6. The packer arrangement of claim 5 wherein the signal transmitter further comprises a radio frequency identification device.
7. The packer arrangement of claim 5 wherein the packer setting mechanism further comprises:
- a setting member moveably disposed with respect to the outer tubular member and having an end portion to contact the packer device; and
- wherein the collar is moved axially with respect to the outer tubular member by the energy source.
8. The packer arrangement of claim 7 wherein the packer setting mechanism further comprises a split ring that resides within a recess and which is radially removed from the recess upon receipt of the triggering signal by the transceiver.
9. The packer device of claim 5 wherein the energy source comprises a fluid chamber.
10. The packer device of claim 5 wherein the energy source comprises a mechanical spring.
11. The packer device of claim 1 wherein the degradable layer is disposed within the outer string member.
12. The packer device of claim 1 wherein the degradable layer is removed before the packer device is set against the inner tubular string.
13. The packer arrangement of claim 7 wherein the setting member is initially retained against movement by a releasable lock.
14. The packer arrangement of claim 13 further comprising a trigger arrangement for selectively releasing the lock to permit the spring to move the setting member to actuate the sealing element to the set position.
15. The packer arrangement of claim 14 wherein the trigger arrangement comprises a transceiver that releases the lock upon receipt of a trigger signal.
16. The packer arrangement of claim 15 wherein the trigger arrangement further comprises a signal transmitter associated with the inner tubular string, the signal transmitter transmitting a trigger signal to the transceiver.
17. The packer arrangement of claim 16 wherein the signal transmitter comprises an RFID chip and the transceiver comprises an RFID reader.
Type: Application
Filed: Jul 26, 2011
Publication Date: Jan 31, 2013
Applicant: BAKER HUGHES INCORPORATED (Houston, TX)
Inventors: Bennett Richard (Kingwood, TX), James Doane (Friendswood, TX)
Application Number: 13/190,843
International Classification: E21B 33/12 (20060101);