DEGRADABLE LAYER FOR TEMPORARILY PROTECTING A SEAL
A packer arrangement for forming a seal between an inner member and an outer tubular string in a borehole includes an outer tubular string member having a chamber portion; and a packer device disposed at least partially within the chamber portion and including a sealing element for forming a seal against an inner member, the packer device including a degradable layer, the degradable layer temporarily and at least partially protecting the sealing element and method of establishing a seal.
Latest Baker Hughes Incorporated Patents:
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 member and an outer tubular string in a borehole includes an outer tubular string member having a chamber portion; and a packer device disposed at least partially within the chamber portion and including a sealing element for forming a seal against an inner member, the packer device including a degradable layer, the degradable layer temporarily and at least partially protecting the sealing element.
A borehole production system includes an outer tubular string defining a central bore and a packer device associated with the outer tubular string, the packer device including a sealing element actuatable between set and unset positions, the packer device including a degradable layer for temporarily and at least partially protecting the sealing element, wherein the sealing element of the packer device is moved radially inwardly to engage an inner tubular string for forming a seal against the inner tubular string.
A method of establishing a seal within a borehole between an outer tubular string member and an inner tubular string member, including the steps of disposing an outer tubular string within a borehole, the outer tubular string containing an outer tubular string member having an enlarged diameter chamber portion with a packer device residing at least partially within the chamber portion, the packer device being actuatable between an unset position and a set position and including a degradable layer for temporarily and at least partially protecting the packer device; disposing an inner tubular string within the outer tubular string; and actuating the packer device from the unset position to the set position to create a seal between the outer and inner tubular strings.
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 member and an outer tubular string in a borehole, the packer arrangement comprising:
- an outer tubular string member having a chamber portion; and
- a packer device disposed at least partially within the chamber portion and including a sealing element for forming a seal against an inner member, the packer device including a degradable layer, the degradable layer temporarily and at least partially protecting the sealing element.
2. The packer arrangement of claim 1 further comprising a setting member for selectively actuating the sealing element between set and unset positions.
3. The packer arrangement of claim 1 wherein the sealing element comprises an elastomeric seal.
4. The packer arrangement of claim 1 wherein the sealing element comprises a metallic seal.
5. The packer arrangement of claim 2 further comprising a locking mechanism for securing the setting member such that the sealing element is maintained in the set position.
6. The packer arrangement of claim 5 wherein the locking mechanism comprises a body lock ring.
7. The packer arrangement of claim 5 wherein the setting member comprises:
- a compression member that is axially moveable within the chamber portion; and
- an engagement profile for selectively securing the compression member to a setting tool component.
8. The packer arrangement of claim 7 wherein the setting member comprises a camming member that is axially moveable within the chamber portion between a first position wherein the sealing element is unset and a second position wherein the camming member urges the sealing element radially inwardly by camming toward the set position.
9. The packer arrangement of claim 7 wherein the setting member comprises:
- a generally cylindrical compression member having a helical interface with the outer tubular string member such that rotation of the compression member results in movement of the compression member axially within the outer tubular string member.
10. The packer arrangement of claim 1 wherein the degradable layer is disposed in the chamber portion.
11. The packer arrangement of claim 2 wherein the degradable layer is removed before the sealing element is actuated.
12. The packer arrangement of claim 1, wherein the degradable layer is disposed radially inwardly of the sealing element.
13. The packer arrangement of claim 1, further comprising a seal engagement member having a plurality of radially extending pips for engaging into the seal element.
14. The packer arrangement of claim 2 wherein the setting member comprises a hydraulically-actuated setting piston.
15. The packer arrangement of claim 1 wherein:
- the packer device comprises a sealing element within the chamber portion; and
- the inner tubular string includes a ductile tube that is expandable radially outwardly to form a sealing engagement with the sealing element within the chamber portion.
16. The packer arrangement of claim 15 wherein the sealing element comprises an elastomeric sealing element.
17. The packer arrangement of claim 15 wherein the sealing element comprises a metallic sealing element and the sealing engagement of the ductile tube and the sealing element forms a biting retention to withstand high axial tubing loads.
18. The packer arrangement of claim 15 wherein the ductile tube is expanded radially outwardly by hydraulic inflation.
19. The packer arrangement of claim 15 wherein the ductile tube is expanded radially outwardly by mechanical swaging.
20. A borehole production system comprising:
- an outer tubular string defining a central bore;
- a packer device associated with the outer tubular string, the packer device including a sealing element actuatable between set and unset positions, the packer device including a degradable layer for temporarily and at least partially protecting the sealing element, wherein the sealing element of the packer device is moved radially inwardly to engage an inner tubular string for forming a seal against the inner tubular string.
21. The borehole production system of claim 20 further comprising a setting member for selectively actuating the sealing element from the unset position to the set position.
22. The borehole production system of claim 21 wherein the setting member comprises:
- a compression member that is axially moveable within the chamber portion; and
- an engagement profile for selectively securing the compression member to a setting tool component.
23. The borehole production system of claim 22 wherein the setting member comprises a generally cylindrical compression member having a helical interface with the outer tubular string member such that rotation of the compression member results in movement of the compression member axially within the outer tubular string member.
24. The borehole production system of claim 23 further comprising an inner tubular string for production of hydrocarbons against which the packer device is set.
25. The borehole production system of claim 23 wherein the sealing element comprises an elastomeric seal.
26. The borehole production system of claim 23 wherein the sealing element comprises a non-elastomeric seal.
27. The borehole production system of claim 23 wherein the sealing element comprises a metallic seal member.
28. The borehole production system of claim 23 further comprising a locking mechanism for securing the setting member such that the sealing element is maintained in the set position.
29. The borehole production system of claim 28 wherein the locking mechanism comprises a body lock ring assembly.
30. A method of establishing a seal within a borehole between an outer tubular string member and an inner tubular string member, comprising the steps of:
- disposing an outer tubular string within a borehole, the outer tubular string containing an outer tubular string member having an enlarged diameter chamber portion with a packer device residing at least partially within the chamber portion, the packer device being actuatable between an unset position and a set position and including a degradable layer for temporarily and at least partially protecting the packer device;
- disposing an inner tubular string within the outer tubular string;
- actuating the packer device from the unset position to the set position to create a seal between the outer and inner tubular strings.
31. The method of claim 30 wherein the step of actuating the packer device comprises axially compressing a packer element to cause the packer element to be expanded radially inwardly against the inner tubular string.
32. The method of claim 30 wherein the step of actuating the packer device comprises urging a compression member axially against a sealing member to cause the sealing member to expand axially inwardly against the inner tubular string.
33. The method of claim 32 wherein the step of urging the compression member axially against the sealing member comprises:
- engaging an engagement profile on the compression member with a portion of the inner tubular string, and
- moving the inner tubular string axially with respect to the outer tubular string to cause the compression member to be urged against the sealing member.
34. The method of claim 33 further comprising securing the packer device in a set position with a locking mechanism.
35. The method of claim 30 wherein the degradable layer is disposed in the chamber portion.
36. The method of claim 30 further comprising removing the degradable layer before the step of actuating packer device.
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: 13/190,865
International Classification: E21B 33/12 (20060101);