US20130025887A1 - Degradable layer for temporarily protecting a seal - Google Patents
Degradable layer for temporarily protecting a seal Download PDFInfo
- Publication number
- US20130025887A1 US20130025887A1 US13/190,865 US201113190865A US2013025887A1 US 20130025887 A1 US20130025887 A1 US 20130025887A1 US 201113190865 A US201113190865 A US 201113190865A US 2013025887 A1 US2013025887 A1 US 2013025887A1
- Authority
- US
- United States
- Prior art keywords
- packer
- sealing element
- tubular string
- seal
- packer device
- 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
Links
Images
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
- E21B33/128—Packers; Plugs with a member expanded radially by axial pressure
- E21B33/1285—Packers; Plugs with a member expanded radially by axial pressure by fluid pressure
Definitions
- 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.
- 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.
- the components of the packer device inherently occupy space between the inner and outer tubulars.
- a borehole having standard 21.40 lb. casing with an outer diameter of 5 inches would have an inner diameter of 4.126 inches.
- the presence of packer components on the outside of the tubing string will dictate that a smaller size tubing string (such as 27 ⁇ 8′′) 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.
- 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.
- 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.
- FIG. 1 is a side, cross sectional view of an exemplary packer device constructed in accordance with the present invention
- FIG. 2 is a side, cross sectional view of the packer device shown in FIG. 1 , now having been set;
- FIG. 3 is a side, cross-sectional view of an alternative packer device constructed in accordance with the present invention.
- FIG. 4 is a side, cross-sectional view of the packer device shown in FIG. 3 , now with having been set;
- FIG. 5 is a side, cross-sectional view of a further alternative packer device constructed in accordance with the present invention.
- FIG. 6 is a side, cross-sectional view of the packer device shown in FIG. 5 , now having been set;
- FIG. 7 is a side, cross-sectional view of an alternative packer device constructed in accordance with the present invention and utilizing a hydraulic setting arrangement for setting the packer device;
- FIG. 8 is a side, cross-sectional view of the packer device shown in FIG. 7 , now having been actuated to a set position;
- FIG. 9 is a side, cross-sectional view of an alternative packer device also utilizing a hydraulic setting arrangement
- FIG. 10 is a side, cross-sectional view of the packer device shown in FIG. 9 , now having been actuated to a set position;
- FIG. 11 is a side, cross-sectional view of a further exemplary packer device, which incorporates a ductile, radially expandable tube;
- FIG. 12A is a side, cross-sectional view of a packer device generally in accordance with FIG. 1 , but with a protective layer provided for a seal element;
- FIG. 12B is a quarter-sectional view of another packer device embodiment disclosed herein.
- FIGS. 1 and 2 illustrate an exemplary borehole 10 that has been drilled through the earth 12 .
- the borehole 10 is lined with a string of casing, of which two casing sections 14 , 16 are depicted.
- a casing coupler 18 interconnects the casing sections 14 , 16 to form a casing string 17 that defines a central bore 19 along its length.
- Cement 20 surrounds the casing sections 14 , 16 and casing coupler 18 .
- the casing coupler 18 has a greater diameter than the casing sections 14 , 16 and is secured to each of the casing sections 14 , 16 via threaded connections 22 , 24 , respectively.
- 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 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 .
- FIGS. 1 and 2 depict actuation of the packer device 30 to create a seal between the casing string 17 and a string of production tubing 40 , the lower end of which is visible in FIG. 2 .
- the lower end of the production tubing string 40 includes a setting tool 42 for actuation of the packer device 30 .
- the packer device 30 is in an initial, unset position.
- the setting tool 42 includes a cylindrical tool body 44 having a plurality of collets 46 extending axially therefrom. Each of the collets 46 carries a radially enlarged portion 48 that presents a stop shoulder 50 and a tapered camming surface 52 .
- the enlarged portion 48 is shaped and sized to fit within the engagement profile 38 of the setting sleeve 34 .
- 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.
- each collet 46 will snap radially outwardly so that the radially enlarged portion 48 becomes disposed within the engagement profile 38 , as shown in FIG. 2 .
- the tubing string 40 is then pulled upwardly to cause the setting sleeve 34 to be moved axially upwardly within the enlarged diameter portion 28 of the bore 26 .
- the collets 46 are not disengaged from the engagement profile 38 due to abutting contact between the stop shoulder 50 and the upper end 54 of the profile 38 .
- the sealing element 32 is thereby axially compressed by the setting sleeve 34 and, when axially compressed, will be extruded radially inwardly against the tool body 44 of the production tubing string 40 .
- the body lock ring assembly 37 will prevent the setting sleeve 34 from moving back downwardly with respect to the surrounding casing coupler 18 , thereby preventing the packer device 30 from becoming unset.
- the gap between the exterior of the tubing string 40 and the interior of the casing string 17 can be quite small.
- a tubing string 17 having a diameter approximating 4 inches rather than a smaller diameter tubing string (i.e., 27 ⁇ 8′′).
- 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 .
- FIGS. 3 and 4 illustrate an alternative embodiment of the invention wherein a packer device 30 ′ has a sealing element 32 and a setting sleeve assembly 60 .
- the setting sleeve assembly 60 includes an inner setting sleeve member 62 having an external helical thread 64 and an internal helical thread 66 that is formed on the interior of the enlarged diameter portion 28 . It is noted that the external and internal threads 64 , 66 are interengaged with one another in a well-known manner such that rotation of the sleeve member 62 within the casing coupler 18 will move the sleeve member 62 axially within the coupler 18 .
- One or more key slots 68 are located on the radial interior of the sleeve member 62 .
- the packer device 30 ′ is in an unset, initial position.
- a production tubing string 40 has been inserted into the casing string 17 .
- a setting component 70 is secured to the lower end of the production tubing string 40 and presents radially extending keys 72 that are shaped and sized to fit within the key slots 68 .
- the keys 72 are preferably spring-biased radially outwardly from the body of the setting component 70 so that they may be compressed radially inwardly as needed for disposal down through the casing string 17 and to pop radially outwardly upon encountering the key slots 68 .
- the inner sleeve member 62 is secured rotationally with respect to the setting component 70 such that rotating the tubing string 40 and setting component 70 will rotate the sleeve member 62 .
- the tubing string 40 is rotated at the surface to cause the sleeve member 62 to move axially upwardly with respect to the casing coupler 18 , thereby radially compressing the sealing element 32 and causing it to seal against the tubing string 40 .
- no body lock ring is required to maintain the packer device 30 ′ in the set position.
- the inward compressive force exerted by the sealing element 32 upon the outer radial surface of the tubing string 40 should be sufficient to prevent counter-rotation of the tubing string 40 within the casing string 17 that might cause the packer device 30 ′ to become unset.
- FIGS. 5 and 6 depict a further alternative embodiment for a packer device 30 ′′ constructed in accordance with the present invention.
- the packer device 30 ′′ includes a sealing element 72 having a ductile metallic body 74 and elastomeric sealing portions 76 .
- a suitable sealing element of this type is the “ZX” packing element that is available commercially from Baker Oil Tools of Houston, Tex. It is noted that the exterior radial surface 77 of the sealing element 72 is substantially conical in shape such that the lower axial end 78 of the sealing element 72 presents a smaller diameter than the upper axial end 80 .
- 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 .
- FIG. 5 depicts that packer device 30 ′′ in an unset condition.
- a production tubing string 40 has been disposed into the casing string 17 .
- a setting tool component 94 is secured to the lower end of the tubing string 40 and presents axially extending collets 96 with radially outwardly projecting portions 98 that are shaped and sized to reside within the engagement profile 88 of the setting sleeve member 82 .
- the collets 96 are deflected radially inwardly until the outwardly projecting portions 98 encounter the engagement profile 88 and snap radially outwardly to reside within the engagement profile 88 to secure the tubing string 40 to the setting sleeve member 82 .
- the tubing string 40 is raised to cause the setting sleeve member 82 and urge the ramped surface of tapered bore portion 90 axially against the outer radial surface 77 of the sealing element 72 .
- This axial movement causes the body 74 of the sealing element 72 to be cammed radially inwardly and deformed radially inwardly against the production tubing string 40 . Operation of the body lock ring assembly 37 will maintain the packer assembly 30 ′′ in the set position.
- the sealing element 72 is formed entirely of metal and without the elastomeric sealing portions 76 .
- a metal-to-metal seal is formed.
- the sealing element may be a bellow-type seal or a hydroformed seal or ring element.
- 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 .
- 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.
- FIGS. 7 and 8 illustrate a further exemplary packer device 100 that employs an energy source that is contained within the casing string 17 prior to disposing the tubing string 40 into the casing string 17 .
- the enlarged diameter chamber 28 of the casing coupler 18 contains an outer collar 102 and an inner collar 104 .
- the inner collar 104 is disposed radially within the outer collar 102 , and a chamber 106 is defined radially between the two collars 102 , 104 .
- Flanged end portions 108 and seals 110 are provided for each of the collars 102 , 104 .
- the outer collar 102 presents an upper axial end portion 112 that lies in contact with the sealing element 32 .
- a recess 114 is inscribed within the interior radial surface 116 of the outer collar 102 .
- An annular seal member 118 is fixedly secured to the inner collar 104 and is, in turn, secured to a split ring, or C-ring member 120 .
- the split ring 120 In the unset position, depicted in FIG. 7 , the split ring 120 resides within the recess 114 of the outer collar 102 .
- the chamber 106 is defined radially between the inner and outer collars 102 , 104 , at its upper end by seal 110 , and at its lower end by seal member 118 .
- a split ring actuator 122 (visible in FIG. 7 ) is operably interconnected with the split ring 120 .
- the split ring actuator 122 preferably comprises a programmable electronic transceiver that is designed to receive a triggering signal from a transmitter.
- Signal transmitter 124 is incorporated within the tubing string 40 .
- the signal transmitter 124 may comprise an RFID (radio frequency identification) tag or chip that is designed to emit a triggering signal upon passing within a certain proximate distance of the actuator 122 .
- the actuator 122 is operably associated with the split ring 120 to retract the split ring 120 radially inwardly and out of the recess 114 upon receipt of the signal from the transmitter 124 . Radial refraction of the split ring 120 may be done by the actuator mechanically, magnetically, or using other suitable known techniques.
- 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.
- 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 .
- 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 .
- the packer device 100 is in the initially unset position shown in FIG. 7 .
- the tubing string 40 is lowered into the casing string 17 until the transmitter 124 is located proximate the actuator 122 .
- the triggering signal is received by the actuator 122 , which then releases the split ring 120 from the recess 114 .
- a delay could be incorporated into the programming of the actuator 122 such that a predetermined period of time elapses between the time the triggering signal is received by the actuator 122 and the split ring 120 is released from the recess 114 .
- FIGS. 9 and 10 a further exemplary packer device 130 is depicted which utilizes hydraulic setting via the tubing string 40 .
- the sealing element 32 is retained within the chamber 28 along with a setting piston 132 .
- the setting piston 132 features an enlarged compression head portion 134 that abuts the sealing element 32 and a reduced diameter stem portion 136 that extends downwardly from the head portion 134 .
- a ratchet mechanism 138 is located at its lower end of the stem portion 136 and operates in the manner of a body lock ring to ensure one-way sequential movement of the setting piston 132 with respect to the surrounding casing coupler 18 .
- 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 .
- the packer device 130 is initially in the unset position depicted in FIG. 9 .
- the tubing string 40 is then disposed into the casing string 17 until the ports 150 of the tubing string 40 are generally aligned with the fluid flow ports 142 in the setting piston 132 .
- the interior flowbore 152 of the tubing string 40 is then pressurized so that fluid is flowed through the aligned ports 150 and 142 and into the fluid chamber 140 .
- the setting piston 132 is urged upwardly by the fluid pressure so that the enlarged head portion 134 compresses the sealing element 32 .
- Axial compression of the sealing element 32 causes the sealing element 32 to deform radially inwardly and seal against the tubing string 40 , as depicted in FIG. 10 .
- the ratchet mechanism 138 ensures that the packer device 130 remains in the set position.
- FIG. 11 depicts a further exemplary embodiment of the invention wherein a sealing element 200 is contained within the chamber 28 of the casing coupler 18 and an inflatable, or radially expandable, ductile tube 201 is made up into the production tubing string 40 .
- the ductile tube 201 is formed of a material that permits the tube 201 , or portions thereof, to be deformed radially outwardly.
- One such material is a nickel alloy.
- the ductile tube 201 is inflated or expanded radially outwardly until its radially outer surface is brought into sealing contact with the sealing element 200 .
- the ductile tube 201 can be inflated or expanded radially outwardly using a number of techniques for radially expanding ductile tubular members.
- One technique for inflating the ductile tube 201 is to seat a dart, ball, or other pug member 202 upon a seat 204 to seal off the flowbore 152 of the tubing string 40 below the ductile tube 201 . Fluid pressure is then increased within the flowbore 152 above the plug member 202 to cause the ductile tube 201 to expand radially outwardly, as illustrated in FIG. 11 .
- the plug member 202 may be a temporary or removable plug member.
- a mechanical means such as a suitable swaging instrument, can be used to radially expand the ductile tube 201 radially outwardly.
- the sealing element 200 may be a metallic sealing element or a non-metallic sealing element.
- the sealing element 200 is an elastomeric sealing element.
- 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.
- 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.
- 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.
- a disintegratable, dissolvable, corrodible, decomposable, or otherwise easily defeatable protector layer may be employed, for example, a protective layer 205 is shown in FIG. 12A .
- FIG. 12A exactly resembles FIG. 1 , and the description given above is therefore applicable also to FIG. 12A .
- the chamber portion 28 is provided with a radial depth greater than a radial thickness of the seal element 32 in order to enable the application of the protective layer 205 for the seal element 32 .
- the layer 205 is radially inwardly disposed of the element seal 32 . In one embodiment, the layer is within the recess 28 .
- the protective layer 205 is a degradable layer whose purpose is to temporarily protect the seal element 32 .
- “Degradable” is intended to mean that the layer is disintegratable, dissolvable, corrodible, or otherwise easily removable. It is to be understood that any use herein of the term “degrade”, or any of its forms, incorporates the stated meaning.
- the layer 205 is removed by exposure to a downhole fluid, such as water, oil, acid, etc.
- a downhole fluid such as water, oil, acid, etc.
- the packer device 30 would operate as described above with respect to FIGS. 1 and 2 , for forming a seal as shown in FIG. 2 .
- any of the other embodiments described herein could be similarly modified in order to include a degradable layer for temporarily protecting the corresponding seal element in each embodiment.
- a packer arrangement 500 includes a casing pup 502 and a packer mandrel 504 for setting a seal element 506 located in a cavity or chamber 508 of the casing pup 502 .
- the seal element 506 is initially protected by a degradable layer 510 , which substantially resembles the layer 205 described above. After degrading the layer 510 , an arm 512 carrying a seal engagement member 514 is actuated into engagement with the seal element 506 .
- the packer mandrel 504 include a wedge-like, conical, frustoconical, or otherwise tapered surface and be actuated toward the arm 512 , or vice-versa, for urging the seal engagement member 514 radially toward the seal element 506 .
- a piston could actuate the seal engagement member 514 into the packer mandrel 504 .
- the seal engagement member 514 includes a plurality of radially extending pips 516 for “biting” into the seal element 506 , thereby setting the seal element and reducing extrusion thereof.
- the arm 512 could include a body lock 518 for allowing movement of the member 514 in one direction with respect to the tapered surface of the mandrel 504 , but not the other direction, thereby locking the member 514 in place once actuated.
- 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.
- 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.
- the materials could include other metals having a standard oxidation potential less than that of Zn.
- suitable non-metallic materials include ceramics, glasses (e.g., hollow glass microspheres), carbon, or a combination thereof.
- the material has a substantially uniform average thickness between dispersed particles of about 50 nm to about 5000 nm.
- the coating layers are formed from Al, Ni, W or Al 2 O 3 , or combinations thereof.
- the coating is a multi-layer coating, for example, comprising a first Al layer, a Al 2 O 3 layer, and a second Al layer.
- the coating may have a thickness of about 25 nm to about 2500 nm.
- 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 (CaCl 2 ), calcium bromide (CaBr 2 ) or zinc bromide (ZnBr 2 ).
- KCl potassium chloride
- HCl hydrochloric acid
- CaCl 2 calcium chloride
- CaBr 2 calcium bromide
- ZnBr 2 zinc bromide
- 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.
Abstract
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.
Description
- 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.
- 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.
- 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.
-
FIG. 1 is a side, cross sectional view of an exemplary packer device constructed in accordance with the present invention; -
FIG. 2 is a side, cross sectional view of the packer device shown inFIG. 1 , now having been set; -
FIG. 3 is a side, cross-sectional view of an alternative packer device constructed in accordance with the present invention; -
FIG. 4 is a side, cross-sectional view of the packer device shown inFIG. 3 , now with having been set; -
FIG. 5 is a side, cross-sectional view of a further alternative packer device constructed in accordance with the present invention; -
FIG. 6 is a side, cross-sectional view of the packer device shown inFIG. 5 , now having been set; -
FIG. 7 is a side, cross-sectional view of an alternative packer device constructed in accordance with the present invention and utilizing a hydraulic setting arrangement for setting the packer device; -
FIG. 8 is a side, cross-sectional view of the packer device shown inFIG. 7 , now having been actuated to a set position; -
FIG. 9 is a side, cross-sectional view of an alternative packer device also utilizing a hydraulic setting arrangement; -
FIG. 10 is a side, cross-sectional view of the packer device shown inFIG. 9 , now having been actuated to a set position; -
FIG. 11 is a side, cross-sectional view of a further exemplary packer device, which incorporates a ductile, radially expandable tube; -
FIG. 12A is a side, cross-sectional view of a packer device generally in accordance withFIG. 1 , but with a protective layer provided for a seal element; -
FIG. 12B is a quarter-sectional view of another packer device embodiment disclosed herein. -
FIGS. 1 and 2 illustrate anexemplary borehole 10 that has been drilled through theearth 12. Theborehole 10 is lined with a string of casing, of which twocasing sections casing coupler 18 interconnects thecasing sections casing string 17 that defines acentral bore 19 along its length.Cement 20 surrounds thecasing sections casing coupler 18. It is noted that thecasing coupler 18 has a greater diameter than thecasing sections casing sections connections - The
casing coupler 18 includes anaxial bore 26 for passage of tools and fluid through thecasing coupler 18. Thebore 26 has an enlargeddiameter chamber portion 28. Apacker device 30 is disposed within the enlargeddiameter chamber portion 28. Thepacker device 30 includes a cylindrical elastomericpacker sealing element 32 and acylindrical setting sleeve 34. Thesetting sleeve 34 is a compression member that is axially moveable within the enlargeddiameter portion 28 of thebore 26. Thesetting sleeve 34 features anaxial bore 36 with anengagement profile 38 within. A ratchet-style bodylock ring assembly 37, of a type known in the art, is associated with the outer radial diameter surface of thesetting sleeve 34. The bodylock ring assembly 37 provides for limited one-way movement of thesetting sleeve 34 with respect to the surroundingcasing coupler 18. -
FIGS. 1 and 2 depict actuation of thepacker device 30 to create a seal between thecasing string 17 and a string ofproduction tubing 40, the lower end of which is visible inFIG. 2 . The lower end of theproduction tubing string 40 includes asetting tool 42 for actuation of thepacker device 30. InFIG. 1 , thepacker device 30 is in an initial, unset position. In one embodiment, thesetting tool 42 includes acylindrical tool body 44 having a plurality ofcollets 46 extending axially therefrom. Each of thecollets 46 carries a radially enlargedportion 48 that presents astop shoulder 50 and atapered camming surface 52. The enlargedportion 48 is shaped and sized to fit within theengagement profile 38 of thesetting sleeve 34. - To activate the
packer device 30, theproduction tubing string 40 and settingtool 42 are inserted into thecasing string 17. Thetapered camming surface 52 of eachcollet 46 will contact the upper ends of thesealing element 32 and thesetting sleeve 34 and deflect thecollet 46 radially inwardly. When the radially enlargedportion 48 of eachcollet 46 becomes aligned with theengagement profile 38 of thesetting sleeve 34, eachcollet 46 will snap radially outwardly so that the radially enlargedportion 48 becomes disposed within theengagement profile 38, as shown inFIG. 2 . Once thesetting tool 42 is attached to thesetting sleeve 34 in this manner, thetubing string 40 is then pulled upwardly to cause thesetting sleeve 34 to be moved axially upwardly within the enlargeddiameter portion 28 of thebore 26. Thecollets 46 are not disengaged from theengagement profile 38 due to abutting contact between thestop shoulder 50 and theupper end 54 of theprofile 38. The sealingelement 32 is thereby axially compressed by thesetting sleeve 34 and, when axially compressed, will be extruded radially inwardly against thetool body 44 of theproduction tubing string 40. The bodylock ring assembly 37 will prevent thesetting sleeve 34 from moving back downwardly with respect to the surroundingcasing coupler 18, thereby preventing thepacker device 30 from becoming unset. - Because the components of the
packer device 30 are retained within an enlargeddiameter portion 28 of thecasing coupler 18, the gap between the exterior of thetubing string 40 and the interior of thecasing 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 atubing 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 thetubing string 17 will be larger. Second, the sealingelement 32 of thepacker device 30 can more easily and securely seal against the largerdiameter tubing string 17. -
FIGS. 3 and 4 illustrate an alternative embodiment of the invention wherein apacker device 30′ has a sealingelement 32 and a settingsleeve assembly 60. The settingsleeve assembly 60 includes an innersetting sleeve member 62 having an externalhelical thread 64 and an internalhelical thread 66 that is formed on the interior of theenlarged diameter portion 28. It is noted that the external andinternal threads sleeve member 62 within thecasing coupler 18 will move thesleeve member 62 axially within thecoupler 18. One or morekey slots 68 are located on the radial interior of thesleeve member 62. - In
FIG. 3 , thepacker device 30′ is in an unset, initial position. InFIG. 4 , aproduction tubing string 40 has been inserted into thecasing string 17. Asetting component 70 is secured to the lower end of theproduction tubing string 40 and presents radially extendingkeys 72 that are shaped and sized to fit within thekey slots 68. It is noted that thekeys 72 are preferably spring-biased radially outwardly from the body of thesetting component 70 so that they may be compressed radially inwardly as needed for disposal down through thecasing string 17 and to pop radially outwardly upon encountering thekey slots 68. When thekeys 72 are located within thekey slots 68, theinner sleeve member 62 is secured rotationally with respect to thesetting component 70 such that rotating thetubing string 40 and settingcomponent 70 will rotate thesleeve member 62. In order to set thepacker device 30′, thetubing string 40 is rotated at the surface to cause thesleeve member 62 to move axially upwardly with respect to thecasing coupler 18, thereby radially compressing the sealingelement 32 and causing it to seal against thetubing string 40. In this embodiment, no body lock ring is required to maintain thepacker device 30′ in the set position. The inward compressive force exerted by the sealingelement 32 upon the outer radial surface of thetubing string 40 should be sufficient to prevent counter-rotation of thetubing string 40 within thecasing string 17 that might cause thepacker device 30′ to become unset. -
FIGS. 5 and 6 depict a further alternative embodiment for apacker device 30″ constructed in accordance with the present invention. Thepacker device 30″ includes a sealingelement 72 having a ductilemetallic body 74 andelastomeric sealing portions 76. A suitable sealing element of this type is the “ZX” packing element that is available commercially from Baker Oil Tools of Houston, Tex. It is noted that the exteriorradial surface 77 of the sealingelement 72 is substantially conical in shape such that the loweraxial end 78 of the sealingelement 72 presents a smaller diameter than the upperaxial end 80. - Also included in the
packer device 30″ is a settingsleeve member 82 having a generallycylindrical sleeve body 84 that defines a central axial bore 86 with aninterior engagement profile 88. A bodylock ring assembly 37 is associated with the outer radial surface of thesleeve body 84 and provides for limited one-way movement of the settingsleeve member 82 with respect to the surroundingcasing coupler 18. Atapered bore portion 90 is located proximate theupper end 92 of thebody 84 thereby providing a ramped surface that is in abutting contact with the outerradial surface 77 of the sealingelement 72. -
FIG. 5 depicts thatpacker device 30″ in an unset condition. InFIG. 6 , aproduction tubing string 40 has been disposed into thecasing string 17. Asetting tool component 94 is secured to the lower end of thetubing string 40 and presents axially extendingcollets 96 with radially outwardly projectingportions 98 that are shaped and sized to reside within theengagement profile 88 of the settingsleeve member 82. As thetubing string 40 is lowered through thecasing string 17, thecollets 96 are deflected radially inwardly until the outwardly projectingportions 98 encounter theengagement profile 88 and snap radially outwardly to reside within theengagement profile 88 to secure thetubing string 40 to the settingsleeve member 82. Then, thetubing string 40 is raised to cause the settingsleeve member 82 and urge the ramped surface oftapered bore portion 90 axially against the outerradial surface 77 of the sealingelement 72. This axial movement causes thebody 74 of the sealingelement 72 to be cammed radially inwardly and deformed radially inwardly against theproduction tubing string 40. Operation of the bodylock ring assembly 37 will maintain thepacker assembly 30″ in the set position. - Variations on the
packer device 30″ are possible wherein the sealingelement 72 is formed entirely of metal and without theelastomeric sealing portions 76. When thepacker 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 thetubing string 40 and the surroundingcasing string 17. - Currently, each of the
packer devices -
FIGS. 7 and 8 illustrate a further exemplary packer device 100 that employs an energy source that is contained within thecasing string 17 prior to disposing thetubing string 40 into thecasing string 17. Theenlarged diameter chamber 28 of thecasing coupler 18 contains anouter collar 102 and aninner collar 104. Theinner collar 104 is disposed radially within theouter collar 102, and achamber 106 is defined radially between the twocollars Flanged end portions 108 and seals 110 are provided for each of thecollars outer collar 102 presents an upperaxial end portion 112 that lies in contact with the sealingelement 32. Arecess 114 is inscribed within the interiorradial surface 116 of theouter collar 102. Anannular seal member 118 is fixedly secured to theinner collar 104 and is, in turn, secured to a split ring, or C-ring member 120. In the unset position, depicted inFIG. 7 , thesplit ring 120 resides within therecess 114 of theouter collar 102. As noted, thechamber 106 is defined radially between the inner andouter collars seal 110, and at its lower end byseal member 118. A split ring actuator 122 (visible inFIG. 7 ) is operably interconnected with thesplit ring 120. Thesplit ring actuator 122 preferably comprises a programmable electronic transceiver that is designed to receive a triggering signal from a transmitter.Signal transmitter 124 is incorporated within thetubing string 40. In one currently preferred embodiment, thesignal transmitter 124 may comprise an RFID (radio frequency identification) tag or chip that is designed to emit a triggering signal upon passing within a certain proximate distance of theactuator 122. Theactuator 122 is operably associated with thesplit ring 120 to retract thesplit ring 120 radially inwardly and out of therecess 114 upon receipt of the signal from thetransmitter 124. Radial refraction of thesplit ring 120 may be done by the actuator mechanically, magnetically, or using other suitable known techniques. - The
chamber 106 may be an atmospheric chamber or a more highly pressurized chamber, which will create a pressure differential across theseal member 118 which will urge theend portion 112 of theouter collar 102 toward the sealingelement 32 and a set position. In variations on this embodiment, thechamber 106 could be replaced with a mechanical spring to serve as an energy source to bias theouter collar 102 toward the sealingelement 32. Additionally, thetransmitter 124 andactuator 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 thetubing string 40. - In operation, the packer device 100 is in the initially unset position shown in
FIG. 7 . Thetubing string 40 is lowered into thecasing string 17 until thetransmitter 124 is located proximate theactuator 122. The triggering signal is received by theactuator 122, which then releases thesplit ring 120 from therecess 114. If desired, a delay could be incorporated into the programming of theactuator 122 such that a predetermined period of time elapses between the time the triggering signal is received by theactuator 122 and thesplit ring 120 is released from therecess 114. When thesplit ring 120 is released from therecess 114, fluid pressure within thechamber 106 will urge theouter collar 102 axially upwardly so that theupper end 112 will compress the sealingelement 32. The sealingelement 32 will be deformed radially inwardly to seal against thetubing string 40, as depicted inFIG. 8 to create a seal. - Referring now to
FIGS. 9 and 10 , a furtherexemplary packer device 130 is depicted which utilizes hydraulic setting via thetubing string 40. The sealingelement 32 is retained within thechamber 28 along with asetting piston 132. Thesetting piston 132 features an enlargedcompression head portion 134 that abuts the sealingelement 32 and a reduceddiameter stem portion 136 that extends downwardly from thehead portion 134. Aratchet mechanism 138 is located at its lower end of thestem portion 136 and operates in the manner of a body lock ring to ensure one-way sequential movement of thesetting piston 132 with respect to the surroundingcasing coupler 18. - A
fluid chamber 140 is defined between thesetting piston 132 and thecasing string 17 within theenlarged chamber 28.Fluid flow ports 142 are disposed through thesetting piston 132 to permit fluid communication between thefluid chamber 140 and theinterior flowbore 144 of thesetting piston 132. Fluid seals 146 are provided between thesetting piston 132 and thecasing coupler 18 to ensure fluid tightness of thefluid chamber 140. - The lower end of the
tubing string 40 is closed off by aplug 148. Theplug 148 is preferably a temporary or removable plug that can be removed to allow flow through thetubing string 40 at a later point during production operations.Ports 150 are disposed through the side of thetubing string 40. - In operation, the
packer device 130 is initially in the unset position depicted inFIG. 9 . Thetubing string 40 is then disposed into thecasing string 17 until theports 150 of thetubing string 40 are generally aligned with thefluid flow ports 142 in thesetting piston 132. Theinterior flowbore 152 of thetubing string 40 is then pressurized so that fluid is flowed through the alignedports fluid chamber 140. Thesetting piston 132 is urged upwardly by the fluid pressure so that theenlarged head portion 134 compresses the sealingelement 32. Axial compression of the sealingelement 32 causes the sealingelement 32 to deform radially inwardly and seal against thetubing string 40, as depicted inFIG. 10 . Theratchet mechanism 138 ensures that thepacker device 130 remains in the set position. -
FIG. 11 depicts a further exemplary embodiment of the invention wherein a sealingelement 200 is contained within thechamber 28 of thecasing coupler 18 and an inflatable, or radially expandable,ductile tube 201 is made up into theproduction tubing string 40. Theductile tube 201 is formed of a material that permits thetube 201, or portions thereof, to be deformed radially outwardly. One such material is a nickel alloy. To create a seal, theductile tube 201 is inflated or expanded radially outwardly until its radially outer surface is brought into sealing contact with the sealingelement 200. Theductile tube 201 can be inflated or expanded radially outwardly using a number of techniques for radially expanding ductile tubular members. One technique for inflating theductile tube 201 is to seat a dart, ball, orother pug member 202 upon aseat 204 to seal off theflowbore 152 of thetubing string 40 below theductile tube 201. Fluid pressure is then increased within theflowbore 152 above theplug member 202 to cause theductile tube 201 to expand radially outwardly, as illustrated inFIG. 11 . In this embodiment, as well, theplug member 202 may be a temporary or removable plug member. Alternatively, a mechanical means, such as a suitable swaging instrument, can be used to radially expand theductile tube 201 radially outwardly. - The sealing
element 200 may be a metallic sealing element or a non-metallic sealing element. In one embodiment, the sealingelement 200 is an elastomeric sealing element. In another embodiment, the sealingelement 200 is a mechanical sealing element and contains toothed portions to form a biting engagement with theductile tube 201. The design of the sealingelement 200 will preferably provide fluid sealing and mechanical retention between theinflatable tubing 201 and thecasing coupler 18. The sealing contact between theductile tube 201 and the sealingelement 200 forms a retention device between thetubing 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 inFIG. 12A . With the exception ofprotective layer 205,FIG. 12A exactly resemblesFIG. 1 , and the description given above is therefore applicable also toFIG. 12A . In this embodiment, thechamber portion 28 is provided with a radial depth greater than a radial thickness of theseal element 32 in order to enable the application of theprotective layer 205 for theseal element 32. As illustrated, thelayer 205 is radially inwardly disposed of theelement seal 32. In one embodiment, the layer is within therecess 28. Theprotective layer 205 is a degradable layer whose purpose is to temporarily protect theseal element 32. “Degradable” is intended to mean that the layer is disintegratable, dissolvable, corrodible, or otherwise easily removable. It is to be understood that any use herein of the term “degrade”, or any of its forms, incorporates the stated meaning. - In one embodiment, for example, the
layer 205 is removed by exposure to a downhole fluid, such as water, oil, acid, etc. After thelayer 205 has been removed, thepacker device 30 would operate as described above with respect toFIGS. 1 and 2 , for forming a seal as shown inFIG. 2 . It is to be appreciated that any of the other embodiments described herein could be similarly modified in order to include a degradable layer for temporarily protecting the corresponding seal element in each embodiment. - Another embodiment is shown in
FIG. 12B . Specifically, apacker arrangement 500 includes acasing pup 502 and apacker mandrel 504 for setting aseal element 506 located in a cavity orchamber 508 of thecasing pup 502. Theseal element 506 is initially protected by adegradable layer 510, which substantially resembles thelayer 205 described above. After degrading thelayer 510, anarm 512 carrying aseal engagement member 514 is actuated into engagement with theseal element 506. For example, thepacker mandrel 504 include a wedge-like, conical, frustoconical, or otherwise tapered surface and be actuated toward thearm 512, or vice-versa, for urging theseal engagement member 514 radially toward theseal element 506. For example, in another embodiment a piston could actuate theseal engagement member 514 into thepacker mandrel 504. Theseal engagement member 514 includes a plurality of radially extendingpips 516 for “biting” into theseal element 506, thereby setting the seal element and reducing extrusion thereof. Thearm 512 could include abody lock 518 for allowing movement of themember 514 in one direction with respect to the tapered surface of themandrel 504, but not the other direction, thereby locking themember 514 in place once actuated. - 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 (36)
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.
Priority Applications (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US13/190,865 US20130025887A1 (en) | 2011-07-26 | 2011-07-26 | Degradable layer for temporarily protecting a seal |
PCT/US2011/045467 WO2012015873A1 (en) | 2010-07-27 | 2011-07-27 | Method for improving the deposit formation resistance performance of turbine oils containing amine antioxidants |
EP11813081.4A EP2598489B1 (en) | 2010-07-27 | 2011-07-27 | Use of bis-diphenylphosphates for improving the deposit formation resistance performance of turbine oils containing amine antioxidants |
SG2013005582A SG187186A1 (en) | 2010-07-27 | 2011-07-27 | Method for improving the deposit formation resistance performance of turbine oils containing amine antioxidants |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US13/190,865 US20130025887A1 (en) | 2011-07-26 | 2011-07-26 | Degradable layer for temporarily protecting a seal |
Publications (1)
Publication Number | Publication Date |
---|---|
US20130025887A1 true US20130025887A1 (en) | 2013-01-31 |
Family
ID=47596295
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US13/190,865 Abandoned US20130025887A1 (en) | 2010-07-27 | 2011-07-26 | Degradable layer for temporarily protecting a seal |
Country Status (1)
Country | Link |
---|---|
US (1) | US20130025887A1 (en) |
Cited By (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20160130909A1 (en) * | 2014-11-10 | 2016-05-12 | Chevron U.S.A. Inc. | Inflatable Casing Valve |
US20170111898A1 (en) * | 2012-08-03 | 2017-04-20 | Intel Corporation | Periodic channel state information (csi) reporting using a physical uplink control channel (pucch) |
US20190093453A1 (en) * | 2017-09-28 | 2019-03-28 | Baker Hughes, A Ge Company, Llc | Insert safety valve system |
-
2011
- 2011-07-26 US US13/190,865 patent/US20130025887A1/en not_active Abandoned
Cited By (5)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20170111898A1 (en) * | 2012-08-03 | 2017-04-20 | Intel Corporation | Periodic channel state information (csi) reporting using a physical uplink control channel (pucch) |
US20160130909A1 (en) * | 2014-11-10 | 2016-05-12 | Chevron U.S.A. Inc. | Inflatable Casing Valve |
US9816349B2 (en) * | 2014-11-10 | 2017-11-14 | Chevron U.S.A. Inc. | Inflatable casing valve |
US20190093453A1 (en) * | 2017-09-28 | 2019-03-28 | Baker Hughes, A Ge Company, Llc | Insert safety valve system |
US10508512B2 (en) * | 2017-09-28 | 2019-12-17 | Baker Hughes, A Ge Company, Llc | Insert safety valve system |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US7694746B2 (en) | Large bore packer and methods of setting same | |
US9033055B2 (en) | Selectively degradable passage restriction and method | |
US10408012B2 (en) | Downhole tool with an expandable sleeve | |
US20130025849A1 (en) | Actuated packer arrangement having a degradable layer for a seal | |
US9611711B2 (en) | Method of opening an orifice in a downhole article, method for making the same and article made thereby | |
US11655686B2 (en) | Degradable plug device for a pipe | |
US10087714B2 (en) | Tubular assembly including a sliding sleeve having a degradable locking element | |
CA2704701A1 (en) | Composite downhole tool with reduced slip volume | |
WO2016161300A1 (en) | Disintegrating compression set plug with short mandrel | |
US10337287B2 (en) | Tubular assembly including a sliding sleeve having a degradable locking element | |
Walton et al. | Dissolvable metal vs. dissolvable plastic in downhole hydraulic fracturing applications | |
US20130025887A1 (en) | Degradable layer for temporarily protecting a seal | |
US10648263B2 (en) | Downhole plug assembly | |
US20160138370A1 (en) | Mechanical diverter | |
AU2013239039B2 (en) | Large bore packer and methods of setting same | |
US11608704B2 (en) | Method and apparatus for a joint-locking plug |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
AS | Assignment |
Owner name: BAKER HUGHES INCORPORATED, TEXAS Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:RICHARD, BENNETT;DOANE, JAMES;SIGNING DATES FROM 20110728 TO 20110801;REEL/FRAME:026931/0629 |
|
STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |