US20090229832A1 - Pressure Compensator for Hydrostatically-Actuated Packers - Google Patents
Pressure Compensator for Hydrostatically-Actuated Packers Download PDFInfo
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- US20090229832A1 US20090229832A1 US12/046,168 US4616808A US2009229832A1 US 20090229832 A1 US20090229832 A1 US 20090229832A1 US 4616808 A US4616808 A US 4616808A US 2009229832 A1 US2009229832 A1 US 2009229832A1
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- Prior art keywords
- setting
- fluid
- tool
- chamber
- pressure
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- 239000012530 fluid Substances 0.000 claims abstract description 93
- 238000004891 communication Methods 0.000 claims abstract description 20
- 238000000034 method Methods 0.000 claims abstract description 12
- 230000002706 hydrostatic effect Effects 0.000 claims abstract description 10
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 claims description 14
- 229910052757 nitrogen Inorganic materials 0.000 claims description 7
- 238000004873 anchoring Methods 0.000 claims description 6
- 230000004044 response Effects 0.000 claims description 5
- 230000006835 compression Effects 0.000 description 11
- 238000007906 compression Methods 0.000 description 11
- 230000000712 assembly Effects 0.000 description 7
- 238000000429 assembly Methods 0.000 description 7
- 230000004913 activation Effects 0.000 description 4
- 238000007789 sealing Methods 0.000 description 4
- 238000004519 manufacturing process Methods 0.000 description 3
- 230000000717 retained effect Effects 0.000 description 3
- 238000010276 construction Methods 0.000 description 2
- 230000004888 barrier function Effects 0.000 description 1
- 230000008901 benefit Effects 0.000 description 1
- 238000002347 injection Methods 0.000 description 1
- 239000007924 injection Substances 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
- E21B33/129—Packers; Plugs with mechanical slips for hooking into the casing
- E21B33/1295—Packers; Plugs with mechanical slips for hooking into the casing actuated by fluid pressure
Definitions
- the invention relates generally to downhole tools, including packer devices.
- the invention relates to methods of actuating downhole tools.
- Some downhole tools use absolute well pressure activation to operate. They are also referred to as hydrostatically actuated tools.
- absolute well pressure activation the to absolute pressure in the wellbore is the sum of the hydrostatic pressure and any additional pressure generated from the surface of the well.
- the tool to be actuated is constructed to hold atmospheric air pressure in an atmospheric chamber. The tool is then run to depth. A rupture disc separates the atmospheric chamber from the wellbore fluid, which is under hydrostatic pressure. When the absolute pressure in is the well exceeds the differential pressure rating of the rupture disc, the disc ruptures to permit fluid to enter the atmospheric chamber.
- the pressurized well fluid entering the actuation chamber is applied to a setting piston to set the packer device or otherwise actuate the downhole tool.
- Tools which can be operated using absolute well pressure activation are described in, for example, U.S. Pat. No. 6,779,600.
- the invention provides a design and method for operating downhole tools in response to absolute pressure.
- a well packer device is provided with a packer element and slip elements which are set by axial compression.
- the packer device has an actuation chamber which is in communication with a pressure compensator reservoir.
- the actuation chamber has a fluid communication port which allows fluid communication between actuation chamber and the annulus surrounding the packer device.
- the pressure compensator reservoir and actuation chamber are charged with a pressurized fluid, such as nitrogen.
- the fluid pressure within the pressure compensator reservoir and actuation chamber is higher than atmospheric pressure.
- the tool is actuated when the external wellbore pressure exceeds the burst pressure rating of the rupture disc plus the fluid pressure contained within the pressure compensator chamber and actuation chamber.
- a setting piston is moved by the pressure of the fluid to set the packer device. Pressure charging of the pressure compensator reservoir allows for the tool to be operated at greater depths and to remain operable under higher external pressures than possible if the actuation chamber was at atmospheric pressure.
- FIGS. 1A , 1 B, 1 C, 1 D and 1 E are a side, partial cross-sectional view of an exemplary packer device constructed in accordance with the present invention.
- FIG. 2 is a side, cross-sectional view of portions of an alternative packer device constructed in accordance with the present invention and in a run-in, unactuated position.
- FIG. 3 is a side, cross-sectional view of the packer device shown in FIG. 2 , now in an actuated position.
- FIG. 4 is a side, cross-sectional view of a further alternative device constructed in accordance with the present invention.
- FIGS. 1A , 1 B, 1 C, 1 D and 1 E depict an exemplary packer device 10 constructed in accordance with the present invention.
- the packer device 10 includes a central mandrel 12 having a threaded connection 14 at its upper axial end 16 .
- the central mandrel 12 is formed of an upper central mandrel portion 18 , middle central mandrel portion 20 , and lower central mandrel portion 22 , and a lower sub 24 , which are interconnected with one another by threaded connections, in a manner known in the art.
- the lower sub 24 presents a lower threaded connection 26 at its lower axial end.
- the threaded connections 14 , 26 are used for interconnection of the packer device 10 into a wellbore production or injection string (not shown), as is known in the art.
- the central mandrel 12 defines a central flowbore 28 along its length.
- the packer device 10 generally features a debris barrier 30 , a set of upper anchoring slips 32 , an elastomeric packer assembly 34 , and a set of lower anchoring slips 36 .
- the slip assemblies 32 , 36 are set using axial compression of the assemblies with respect to the central mandrel 12 so as to cause the slip elements 38 of the slip assemblies 32 , 36 to be urged radially outward, as is known in the art. As the construction and operation of such devices is well known, they will not be further described herein.
- a setting collar 42 and body lock ring assembly 44 are located axially below the lower slip assembly 36 .
- the packer assembly 34 is set by axial compression as well so as to cause the elastomeric packer elements 40 to be extruded radially outward. Axial compression of the packer assembly 34 and slip assemblies 32 , 36 is caused by upward axial movement of the setting collar 42 with respect to the central mandrel 12 .
- the lower portion of the packer device 10 includes a hydraulic setting section, generally shown at 46 and a hydrostatic setting assembly, generally shown at 48 , which are used to generate the axial force to set the slip assemblies 32 , 36 and the packer assembly 34 .
- the hydraulic backup setting piston 50 is moveably retained within a setting piston chamber 52 which is defined radially between the central mandrel 12 and an outer sleeve 54 .
- the backup setting piston 50 includes a compression end 56 , which abuts the compression collar 42 .
- the piston 50 includes an enlarged sealing portion 58 with fluid seals 60 to provide fluid sealing against both the central mandrel 12 and the outer sleeve 54 .
- the enlarged portion 58 presents a fluid pressure receiving surface 62 .
- an upper setting piston chamber 52 is in fluid communication with the annulus 53 surrounding the tool 10 via a port 15 while a lower setting piston chamber 52 ′ is in fluid communication with the flowbore 28 via a radial port 64 disposed through the central mandrel 12 .
- Pressurized fluid may enter the lower setting piston chamber 52 ′ via the port 64 and be applied against the surface 62 .
- the backup setting piston may be used to set the packer assembly 34 and slip assemblies 32 , 36 . To do this, the flowbore 28 is pressurized at the surface of the well to exude pressure upon the surface 62 of the backup setting piston 50 .
- the backup setting piston 50 is axially moved to cause the compression end 56 of the piston 50 to urge the setting collar 42 against the lower slip assembly 36 .
- pressurized fluid enters the lower chamber 52 ′ through port 64 , and the piston 50 moved, fluid is expelled from the upper chamber 52 into the annulus 53 through port 15 .
- Setting force is retained in slips 32 , 36 and packer 34 by body lock ring assembly 44 .
- the primary setting assembly 48 includes a setting sleeve 66 which is attached by one or more set screws 68 to the compression collar 42 .
- the lower end of the setting sleeve 66 is secured to outer sleeve 54 .
- a pressure chamber 55 is formed radially between the lower sleeve 72 and the central mandrel 12 (see FIG. 1D ).
- the chamber 55 is pressurized to a level above wellbore hydrostatic pressure.
- the lower end of the outer sleeve 54 is secured by securing ring 70 to lower sleeve 72 .
- Annular fluid seals 57 ensure pressure integrity of the pressure chamber 55 .
- a body lock ring assembly 74 of a type known in the art for ensuring one-way relative axial movement between components, is incorporated between the outer sleeve 54 and the central mandrel 12 , as depicted in FIG. 1D .
- the lower end of the lower sleeve 72 is affixed by a threaded connection 74 to an interlock assembly housing 76 .
- the interlock assembly housing 76 overlies the lower sub 24 without being affixed to it. Seals 80 provide fluid sealing between the interlock assembly housing 76 and the lower sub 24 .
- a number of features of the interlock assembly 84 are described in U.S. Pat. No. 6,779,600 entitled “Labyrinth Lock Seal for Hydrostatically Set Packer” issued to King et al. That patent is owned by the assignee of the present application and is hereby incorporated by reference in its entirety.
- the interlock assembly 84 includes a lock sleeve 86 that is moveably disposed within the setting chamber 82 .
- the lock sleeve 86 is affixed by shear pin 88 to an interlock piston 90 .
- the interlock piston 90 is secured by a locking dog 92 to the lower central mandrel portion 22 .
- a fluid pressure compensator reservoir 94 is defined within the lower sub 24 .
- the fluid pressure compensator reservoir 94 contains pressurized nitrogen.
- a fluid communication passage 96 extends between the reservoir 94 and the setting chamber 82 .
- a fluid communication port 98 (see FIG. 1E ) is disposed through the interlock assembly housing 76 to permit fluid communication from the exterior annulus 100 into the setting chamber 82 .
- the port 98 is initially closed off by a frangible rupture disc 102 .
- the reservoir 94 Prior to running the packer device into a wellbore, the reservoir 94 is filled with pressurized nitrogen or another pressurized fluid.
- the reservoir 94 is pressurized to a pressure that is greater than atmospheric pressure.
- the level of pressure within the reservoir 94 is set based upon the external wellbore pressure that the tool 10 is expected to be exposed to. In a presently preferred embodiment, the reservoir 94 is pressurized to a level that approximates the expected exterior pressure. Therefore, the tool 10 may be actuated by increasing pressure within the annulus by an amount approximately equal to the burst rating of the rupture disc 102 .
- a fill port 104 is disposed through the exterior wall of the lower sub 24 to permit fluid to be communicated into the reservoir 94 . The fill port 104 is closed off with a removable plug.
- the pressure within the reservoir 94 will be communicated to the setting chamber 82 via the passage 96 .
- One advantage of pressurizing the setting chamber 82 is that, at great depths, outer housing components, including the interlock assembly housing 76 will not be deformed or deflected radially inwardly, or very minimally so, by the significant hydrostatic wellbore pressure, so that the operational movement of members within the setting chamber 82 is not impeded by this deformation.
- the fluid pressure compensator reservoir 94 is filled with pressurized fluid at the surface prior to running the tool 10 into a wellbore.
- the packer device 10 is incorporated into a production tubing string in a manner known in the art. The production tubing string and packer device 10 are then disposed into a wellbore and lowered to a desired depth.
- the annulus 100 When the desired depth of setting is reached in the wellbore, the annulus 100 is sufficiently pressurized at the surface of the wellbore so that the rupture disc 102 will burst and allow high pressure wellbore fluid to flow from the annulus 100 into the setting chamber 82 .
- the wellbore fluid As the wellbore fluid enters the setting chamber 82 , it urges the lock sleeve 86 axially upwardly within the chamber 82 . Movement of the lock sleeve 86 causes shear member 88 to rupture and releases the locking dog 92 from engagement with the central mandrel 12 . Once the locking dog 92 is released, the interlock assembly housing 76 and lower sleeve 72 are free to move axially with respect to the central mandrel 12 .
- Increased fluid pressure within the annulus 100 will also cause the packer device 10 to be set.
- the increased fluid pressure will bear upon the lower end 106 of the interlock assembly housing 76 and urge the interlock assembly housing 76 , the affixed lower sleeve 72 , outer sleeve 54 and setting sleeve 66 and compression collar 64 axially upwardly with respect to the central mandrel 12 .
- the interlock assembly housing 76 , lower sleeve 72 , outer sleeve 54 , and setting sleeve 66 serve as a primary setting piston for setting of the packer device 10 . Because the locking dog 92 has been released, the primary setting piston may now move freely with respect to the central mandrel 12 .
- the compression collar 64 is urged against the lower slip assembly 36 causing the slip assemblies 32 , 36 and the packer assembly 34 to be set.
- the chamber 55 collapses.
- Pressurization of the compensator reservoir 94 provides an increase in internal pressure for the setting chamber 82 . This allows the packer device 10 to be run to deeper depths and resulting higher hydrostatic pressures before actuation occurs.
- the amount of external fluid pressure required to destroy the rupture disc 102 is determined by adding the internal pressure of the compensator reservoir 94 to the burst rating of the rupture disc 102 . For example, if the rupture disc 102 is designed to rupture at approximately 10,000 psi, and the compensation reservoir 94 contains fluid that is pressurized to 2,000 psi, the absolute external pressure applied to the tool 10 must exceed 12,000 psi in order to rupture the disc 102 and actuate the tool 10 .
- the packer assembly 200 includes a central mandrel 202 and a bottom sub 204 .
- a setting cylinder 206 surrounds the central mandrel 202 above the bottom sub 204 .
- the setting cylinder 206 presents a radially-inwardly projecting piston 208 which contacts the outer radial surface 210 of the mandrel 202 .
- O-ring seals 212 provide fluid sealing across the piston 208 .
- the setting cylinder 206 is initially affixed to the bottom sub 204 by frangible shear pins 214 .
- a first setting chamber is defined below the piston 208 and radially between the central mandrel 202 and the bottom sub 204 .
- the lower end of the first setting chamber 216 is closed off by fluid seals 218 .
- a fluid port 220 is disposed through the lower sub 204 to provide fluid communication between the first setting chamber 216 and the surrounding annulus 222 .
- the port 22 is initially closed off by a frangible rupture disc 224 .
- a second setting chamber 226 is located above the piston 208 and defined radially between the setting cylinder 206 and the mandrel 202 .
- the upper end of the second setting chamber 226 is closed off by a radial projection 228 from the central mandrel 202 and fluid seals 230 .
- the second setting chamber 226 is in fluid communication with the first setting chamber 216 via a weep hole 232 or other restrictive fluid path, which is disposed through the piston 208 .
- a fluid pressure compensator reservoir 234 is defined within the bottom sub 204 .
- the reservoir 234 is similar in structure and function to the fluid pressure compensator reservoir 94 described earlier.
- the fluid pressure compensator reservoir 234 contains pressurized nitrogen.
- a fluid communication passage 236 extends between the reservoir 234 and the first setting chamber 216 .
- a chamber fill port 238 is preferably provided for readily filling the reservoir 234 .
- the reservoir 234 Prior to running the packer device 200 into a wellbore, the reservoir 234 is charged with fluid that is pressurized greater than atmospheric pressure, thereby enabling the packer assembly 200 to be run in deeper wells containing greater hydrostatic pressure. The greater-than-atmospheric pressure from the reservoir 234 is transmitted through the passage 236 to the first setting chamber 216 and through the weep hole 232 to the second setting chamber 226 .
- the annulus 222 is pressurized to rupture the rupture disc 224 . Fluid from the annulus 222 will pass through the port 220 and enter the first setting chamber 216 . The increased fluid pressure will bear against the lower side 238 of the piston 208 and cause the shear pins 214 to shear. When the pins 214 are sheared, the setting cylinder 206 is released and moves upwardly with respect to the central mandrel 202 . The second setting chamber 226 is collapsed, and the setting cylinder 206 will set the associated packer and slip elements (not shown) in the manner described previously with regard to packer device 10 .
- FIG. 4 illustrates an exemplary alternative packer device 300 incorporating an improved setting assembly in accordance with the present invention.
- the packer element 302 is located above the setting assembly 304 while a slip anchoring assembly 306 is located below the setting assembly 304 .
- the setting assembly 304 includes an upper setting cylinder 308 and a lower setting sleeve 310 .
- An upper setting chamber 312 is defined radially between the central mandrel 314 and the upper setting cylinder 308 .
- the upper setting chamber 312 is bounded on its lower end by shoulder 316 and at its upper end by setting piston 318 .
- a charging port 320 is disposed through the setting cylinder 308 to permit the upper setting chamber 312 to be charged with a fluid.
- the charging port 320 is closed off by a plug, as is known in the art.
- a lower setting chamber 322 is defined radially between the central mandrel 314 and the lower setting sleeve 310 .
- the lower setting chamber 322 is bounded at its upper end by a fluid seal 324 between the lower setting sleeve 310 and the central mandrel 314 .
- the lower setting chamber 322 is bounded by a lower setting piston 326 .
- a fluid port 328 is disposed through the lower setting piston 310 to permit the lower setting chamber 322 to be charged with a fluid.
- the fluid port 328 is closed off by a closure plug, as is known in the art.
- a shear screw 330 secures the lower setting sleeve 326 to the upper setting sleeve 308 .
- the upper and lower setting chambers 312 , 322 Prior to running the packer device 300 into a wellbore, the upper and lower setting chambers 312 , 322 are charged with a fluid at a pressure that exceeds atmospheric pressure. This permits the packer device 300 to be run to deeper depths with higher hydrostatics within a wellbore.
- the fluid pressure compensation reservoir is integrated into the setting chambers 312 , 322 .
- the packer device 300 might also be constructed so as to have one or more separate fluid compensation reservoirs which is/are maintained separately from the setting chambers 312 , 322 .
- the annulus surrounding the packer device 300 is pressurized from the surface to a predetermined level.
- the increased fluid pressure acts upon the outer radial surfaces of the upper setting cylinder 308 and the lower setting sleeve 310 and particularly at the point 332 where the cylinder 308 and sleeve 310 meet and causes the shear screw 330 to rupture, thereby releasing the cylinder 308 from the sleeve 310 .
- the increased annular fluid pressure then causes the upper and lower setting chambers 312 , 322 to collapse.
- the upper setting cylinder 308 is moved axially upwardly with respect to the central mandrel 314 , thereby setting the packer element 302 .
- the lower setting sleeve 310 is moved axially downwardly with respect to the central mandrel 314 , thereby setting the slip anchoring assembly 306 .
- Body lock ring 332 maintains the axial compression force in packer element 302 and slip anchoring assembly 306 .
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Abstract
Devices and methods for operating a tool within a wellbore. A downhole tool includes a tool operation portion having a moveable tool member and a setting portion having a setting piston and setting chamber. A fluid pressure compensation reservoir is in fluid communication with the setting chamber and containing a pressurized fluid which offsets external hydrostatic pressure.
Description
- 1. Field of the Invention
- The invention relates generally to downhole tools, including packer devices. In particular aspects, the invention relates to methods of actuating downhole tools.
- 2. Description of the Related Art
- Some downhole tools use absolute well pressure activation to operate. They are also referred to as hydrostatically actuated tools. In absolute well pressure activation, the to absolute pressure in the wellbore is the sum of the hydrostatic pressure and any additional pressure generated from the surface of the well. To use absolute pressure activation, the tool to be actuated is constructed to hold atmospheric air pressure in an atmospheric chamber. The tool is then run to depth. A rupture disc separates the atmospheric chamber from the wellbore fluid, which is under hydrostatic pressure. When the absolute pressure in is the well exceeds the differential pressure rating of the rupture disc, the disc ruptures to permit fluid to enter the atmospheric chamber. Typically, the pressurized well fluid entering the actuation chamber is applied to a setting piston to set the packer device or otherwise actuate the downhole tool. Tools which can be operated using absolute well pressure activation are described in, for example, U.S. Pat. No. 6,779,600.
- In preferred embodiments, the invention provides a design and method for operating downhole tools in response to absolute pressure. In a described embodiment, a well packer device is provided with a packer element and slip elements which are set by axial compression. The packer device has an actuation chamber which is in communication with a pressure compensator reservoir. The actuation chamber has a fluid communication port which allows fluid communication between actuation chamber and the annulus surrounding the packer device. The pressure compensator reservoir and actuation chamber are charged with a pressurized fluid, such as nitrogen. The fluid pressure within the pressure compensator reservoir and actuation chamber is higher than atmospheric pressure. The tool is actuated when the external wellbore pressure exceeds the burst pressure rating of the rupture disc plus the fluid pressure contained within the pressure compensator chamber and actuation chamber. When the actuation chamber is filled with wellbore fluid, a setting piston is moved by the pressure of the fluid to set the packer device. Pressure charging of the pressure compensator reservoir allows for the tool to be operated at greater depths and to remain operable under higher external pressures than possible if the actuation chamber was at atmospheric pressure.
- Alternative embodiments are described which incorporate different actuation or setting chamber designs.
- For a thorough understanding of the present invention, reference is made to the following detailed description of the preferred embodiments, taken in conjunction with the accompanying drawings, wherein like reference numerals designate like or similar elements throughout the several figures of the drawings and wherein:
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FIGS. 1A , 1B, 1C, 1D and 1E are a side, partial cross-sectional view of an exemplary packer device constructed in accordance with the present invention. -
FIG. 2 is a side, cross-sectional view of portions of an alternative packer device constructed in accordance with the present invention and in a run-in, unactuated position. -
FIG. 3 is a side, cross-sectional view of the packer device shown inFIG. 2 , now in an actuated position. -
FIG. 4 is a side, cross-sectional view of a further alternative device constructed in accordance with the present invention. -
FIGS. 1A , 1B, 1C, 1D and 1E depict anexemplary packer device 10 constructed in accordance with the present invention. Thepacker device 10 includes acentral mandrel 12 having a threadedconnection 14 at its upperaxial end 16. Thecentral mandrel 12 is formed of an uppercentral mandrel portion 18, middlecentral mandrel portion 20, and lowercentral mandrel portion 22, and alower sub 24, which are interconnected with one another by threaded connections, in a manner known in the art. Thelower sub 24 presents a lower threadedconnection 26 at its lower axial end. The threadedconnections packer device 10 into a wellbore production or injection string (not shown), as is known in the art. Thecentral mandrel 12 defines acentral flowbore 28 along its length. - Beginning at the
upper end 16 of thetool 10 and working downwardly, thepacker device 10 generally features adebris barrier 30, a set ofupper anchoring slips 32, anelastomeric packer assembly 34, and a set oflower anchoring slips 36. Theslip assemblies central mandrel 12 so as to cause theslip elements 38 of theslip assemblies setting collar 42 and bodylock ring assembly 44 are located axially below thelower slip assembly 36. Thepacker assembly 34 is set by axial compression as well so as to cause theelastomeric packer elements 40 to be extruded radially outward. Axial compression of thepacker assembly 34 andslip assemblies setting collar 42 with respect to thecentral mandrel 12. - The lower portion of the
packer device 10 includes a hydraulic setting section, generally shown at 46 and a hydrostatic setting assembly, generally shown at 48, which are used to generate the axial force to set theslip assemblies packer assembly 34. - The hydraulic
backup setting piston 50 is moveably retained within asetting piston chamber 52 which is defined radially between thecentral mandrel 12 and anouter sleeve 54. Thebackup setting piston 50 includes acompression end 56, which abuts thecompression collar 42. In addition, thepiston 50 includes an enlargedsealing portion 58 withfluid seals 60 to provide fluid sealing against both thecentral mandrel 12 and theouter sleeve 54. The enlargedportion 58 presents a fluid pressure receiving surface 62. It is noted that an uppersetting piston chamber 52 is in fluid communication with theannulus 53 surrounding thetool 10 via aport 15 while a lowersetting piston chamber 52′ is in fluid communication with theflowbore 28 via aradial port 64 disposed through thecentral mandrel 12. Pressurized fluid may enter the lowersetting piston chamber 52′ via theport 64 and be applied against the surface 62. In the event that the absolute pressure setting technique, which will be described shortly, fails, the backup setting piston may be used to set thepacker assembly 34 and slipassemblies flowbore 28 is pressurized at the surface of the well to exude pressure upon the surface 62 of thebackup setting piston 50. Thebackup setting piston 50 is axially moved to cause thecompression end 56 of thepiston 50 to urge thesetting collar 42 against thelower slip assembly 36. As pressurized fluid enters thelower chamber 52′ throughport 64, and thepiston 50 moved, fluid is expelled from theupper chamber 52 into theannulus 53 throughport 15. Setting force is retained inslips lock ring assembly 44. - The
primary setting assembly 48 includes asetting sleeve 66 which is attached by one or moreset screws 68 to thecompression collar 42. The lower end of thesetting sleeve 66 is secured toouter sleeve 54. Apressure chamber 55 is formed radially between thelower sleeve 72 and the central mandrel 12 (seeFIG. 1D ). Thechamber 55 is pressurized to a level above wellbore hydrostatic pressure. The lower end of theouter sleeve 54 is secured by securingring 70 tolower sleeve 72. Annular fluid seals 57 ensure pressure integrity of thepressure chamber 55. A bodylock ring assembly 74, of a type known in the art for ensuring one-way relative axial movement between components, is incorporated between theouter sleeve 54 and thecentral mandrel 12, as depicted inFIG. 1D . The lower end of thelower sleeve 72 is affixed by a threadedconnection 74 to aninterlock assembly housing 76. Theinterlock assembly housing 76 overlies thelower sub 24 without being affixed to it.Seals 80 provide fluid sealing between theinterlock assembly housing 76 and thelower sub 24. - A setting
chamber 82 and an interlock assembly, generally indicated at 84, are retained radially between theinterlock assembly housing 76 and thecentral mandrel 12. A number of features of theinterlock assembly 84 are described in U.S. Pat. No. 6,779,600 entitled “Labyrinth Lock Seal for Hydrostatically Set Packer” issued to King et al. That patent is owned by the assignee of the present application and is hereby incorporated by reference in its entirety. Theinterlock assembly 84 includes alock sleeve 86 that is moveably disposed within the settingchamber 82. Thelock sleeve 86 is affixed byshear pin 88 to aninterlock piston 90. Theinterlock piston 90 is secured by a lockingdog 92 to the lowercentral mandrel portion 22. - A fluid
pressure compensator reservoir 94 is defined within thelower sub 24. In a currently preferred embodiment, the fluidpressure compensator reservoir 94 contains pressurized nitrogen. Afluid communication passage 96 extends between thereservoir 94 and the settingchamber 82. A fluid communication port 98 (seeFIG. 1E ) is disposed through theinterlock assembly housing 76 to permit fluid communication from theexterior annulus 100 into the settingchamber 82. Theport 98 is initially closed off by afrangible rupture disc 102. - Prior to running the packer device into a wellbore, the
reservoir 94 is filled with pressurized nitrogen or another pressurized fluid. Thereservoir 94 is pressurized to a pressure that is greater than atmospheric pressure. The level of pressure within thereservoir 94 is set based upon the external wellbore pressure that thetool 10 is expected to be exposed to. In a presently preferred embodiment, thereservoir 94 is pressurized to a level that approximates the expected exterior pressure. Therefore, thetool 10 may be actuated by increasing pressure within the annulus by an amount approximately equal to the burst rating of therupture disc 102. Afill port 104 is disposed through the exterior wall of thelower sub 24 to permit fluid to be communicated into thereservoir 94. Thefill port 104 is closed off with a removable plug. The pressure within thereservoir 94 will be communicated to the settingchamber 82 via thepassage 96. One advantage of pressurizing the settingchamber 82 is that, at great depths, outer housing components, including theinterlock assembly housing 76 will not be deformed or deflected radially inwardly, or very minimally so, by the significant hydrostatic wellbore pressure, so that the operational movement of members within the settingchamber 82 is not impeded by this deformation. - In operation, the fluid
pressure compensator reservoir 94 is filled with pressurized fluid at the surface prior to running thetool 10 into a wellbore. Thepacker device 10 is incorporated into a production tubing string in a manner known in the art. The production tubing string andpacker device 10 are then disposed into a wellbore and lowered to a desired depth. - When the desired depth of setting is reached in the wellbore, the
annulus 100 is sufficiently pressurized at the surface of the wellbore so that therupture disc 102 will burst and allow high pressure wellbore fluid to flow from theannulus 100 into the settingchamber 82. As the wellbore fluid enters the settingchamber 82, it urges thelock sleeve 86 axially upwardly within thechamber 82. Movement of thelock sleeve 86 causesshear member 88 to rupture and releases the lockingdog 92 from engagement with thecentral mandrel 12. Once the lockingdog 92 is released, theinterlock assembly housing 76 andlower sleeve 72 are free to move axially with respect to thecentral mandrel 12. - Increased fluid pressure within the
annulus 100 will also cause thepacker device 10 to be set. The increased fluid pressure will bear upon thelower end 106 of theinterlock assembly housing 76 and urge theinterlock assembly housing 76, the affixedlower sleeve 72,outer sleeve 54 and settingsleeve 66 andcompression collar 64 axially upwardly with respect to thecentral mandrel 12. Theinterlock assembly housing 76,lower sleeve 72,outer sleeve 54, and settingsleeve 66 serve as a primary setting piston for setting of thepacker device 10. Because the lockingdog 92 has been released, the primary setting piston may now move freely with respect to thecentral mandrel 12. Thecompression collar 64 is urged against thelower slip assembly 36 causing theslip assemblies packer assembly 34 to be set. Thechamber 55 collapses. - Pressurization of the
compensator reservoir 94 provides an increase in internal pressure for the settingchamber 82. This allows thepacker device 10 to be run to deeper depths and resulting higher hydrostatic pressures before actuation occurs. The amount of external fluid pressure required to destroy therupture disc 102 is determined by adding the internal pressure of thecompensator reservoir 94 to the burst rating of therupture disc 102. For example, if therupture disc 102 is designed to rupture at approximately 10,000 psi, and thecompensation reservoir 94 contains fluid that is pressurized to 2,000 psi, the absolute external pressure applied to thetool 10 must exceed 12,000 psi in order to rupture thedisc 102 and actuate thetool 10. - Referring now to
FIGS. 2 and 3 , there is depicted analternative packer assembly 200 wherein there is a single piston with balanced or nearly balanced atmospheric chambers which urge the piston up and down more or less equivalently. The upper portions (not shown) of thepacker assembly 200 may have the identical construction as thepacker device 10 described previously. Thepacker assembly 200 includes acentral mandrel 202 and abottom sub 204. Asetting cylinder 206 surrounds thecentral mandrel 202 above thebottom sub 204. Thesetting cylinder 206 presents a radially-inwardly projectingpiston 208 which contacts the outerradial surface 210 of themandrel 202. O-ring seals 212 provide fluid sealing across thepiston 208. Thesetting cylinder 206 is initially affixed to thebottom sub 204 by frangible shear pins 214. - A first setting chamber, indicated generally at 216, is defined below the
piston 208 and radially between thecentral mandrel 202 and thebottom sub 204. The lower end of the first setting chamber 216 is closed off byfluid seals 218. Afluid port 220 is disposed through thelower sub 204 to provide fluid communication between the first setting chamber 216 and the surroundingannulus 222. Theport 22 is initially closed off by afrangible rupture disc 224. - A
second setting chamber 226 is located above thepiston 208 and defined radially between the settingcylinder 206 and themandrel 202. The upper end of thesecond setting chamber 226 is closed off by aradial projection 228 from thecentral mandrel 202 and fluid seals 230. Thesecond setting chamber 226 is in fluid communication with the first setting chamber 216 via a weephole 232 or other restrictive fluid path, which is disposed through thepiston 208. - A fluid
pressure compensator reservoir 234 is defined within thebottom sub 204. Thereservoir 234 is similar in structure and function to the fluidpressure compensator reservoir 94 described earlier. In a currently preferred embodiment, the fluidpressure compensator reservoir 234 contains pressurized nitrogen. Afluid communication passage 236 extends between thereservoir 234 and the first setting chamber 216. Achamber fill port 238 is preferably provided for readily filling thereservoir 234. Prior to running thepacker device 200 into a wellbore, thereservoir 234 is charged with fluid that is pressurized greater than atmospheric pressure, thereby enabling thepacker assembly 200 to be run in deeper wells containing greater hydrostatic pressure. The greater-than-atmospheric pressure from thereservoir 234 is transmitted through thepassage 236 to the first setting chamber 216 and through the weephole 232 to thesecond setting chamber 226. - To activate the
packer assembly 200, theannulus 222 is pressurized to rupture therupture disc 224. Fluid from theannulus 222 will pass through theport 220 and enter the first setting chamber 216. The increased fluid pressure will bear against thelower side 238 of thepiston 208 and cause the shear pins 214 to shear. When thepins 214 are sheared, thesetting cylinder 206 is released and moves upwardly with respect to thecentral mandrel 202. Thesecond setting chamber 226 is collapsed, and thesetting cylinder 206 will set the associated packer and slip elements (not shown) in the manner described previously with regard topacker device 10. -
FIG. 4 illustrates an exemplaryalternative packer device 300 incorporating an improved setting assembly in accordance with the present invention. In the depicteddevice 300, thepacker element 302 is located above the settingassembly 304 while aslip anchoring assembly 306 is located below the settingassembly 304. The settingassembly 304 includes anupper setting cylinder 308 and alower setting sleeve 310. Anupper setting chamber 312 is defined radially between thecentral mandrel 314 and theupper setting cylinder 308. Theupper setting chamber 312 is bounded on its lower end byshoulder 316 and at its upper end by settingpiston 318. A chargingport 320 is disposed through thesetting cylinder 308 to permit theupper setting chamber 312 to be charged with a fluid. The chargingport 320 is closed off by a plug, as is known in the art. - A
lower setting chamber 322 is defined radially between thecentral mandrel 314 and thelower setting sleeve 310. Thelower setting chamber 322 is bounded at its upper end by afluid seal 324 between thelower setting sleeve 310 and thecentral mandrel 314. At its lower end, thelower setting chamber 322 is bounded by alower setting piston 326. Afluid port 328 is disposed through thelower setting piston 310 to permit thelower setting chamber 322 to be charged with a fluid. Thefluid port 328 is closed off by a closure plug, as is known in the art. Ashear screw 330 secures thelower setting sleeve 326 to theupper setting sleeve 308. - Prior to running the
packer device 300 into a wellbore, the upper andlower setting chambers packer device 300 to be run to deeper depths with higher hydrostatics within a wellbore. In this embodiment, the fluid pressure compensation reservoir is integrated into the settingchambers packer device 300 might also be constructed so as to have one or more separate fluid compensation reservoirs which is/are maintained separately from the settingchambers - When it is desired to set the
packer device 300, the annulus surrounding thepacker device 300 is pressurized from the surface to a predetermined level. The increased fluid pressure acts upon the outer radial surfaces of theupper setting cylinder 308 and thelower setting sleeve 310 and particularly at thepoint 332 where thecylinder 308 andsleeve 310 meet and causes theshear screw 330 to rupture, thereby releasing thecylinder 308 from thesleeve 310. The increased annular fluid pressure then causes the upper andlower setting chambers chambers upper setting cylinder 308 is moved axially upwardly with respect to thecentral mandrel 314, thereby setting thepacker element 302. Thelower setting sleeve 310 is moved axially downwardly with respect to thecentral mandrel 314, thereby setting theslip anchoring assembly 306.Body lock ring 332 maintains the axial compression force inpacker element 302 andslip anchoring assembly 306. - Those of skill in the art will recognize that numerous modifications and changes may be made to the exemplary designs and embodiments described herein and that the invention is limited only by the claims that follow and any equivalents thereof.
Claims (23)
1. A tool for operation within a wellbore comprising:
a tool operation portion having a moveable tool member;
a setting portion comprising:
a primary setting piston operably associated with the tool member such that movement of the setting piston in response to absolute well pressure moves the tool member;
a setting chamber associated with the primary setting piston to release the primary setting piston to move the tool member;
a fluid pressure compensation reservoir in fluid communication with the setting chamber and containing a pressurized fluid to offset hydrostatic pressure within the wellbore.
2. The tool of claim 1 further comprising a fluid communication port disposed between the setting chamber and an annulus of the wellbore, the port being releasably closed to selectively block fluid flow between the annulus and the setting chamber.
3. The tool of claim 1 wherein the tool operation portion comprises a packer assembly and the tool member comprises a packer element.
4. The tool of claim 1 further comprising a backup setting piston that is actuated by hydraulic pressure from a central flowbore to move the tool member.
5. The tool of claim 1 wherein the fluid pressure compensation reservoir is filled with pressurized nitrogen.
6. The tool of claim 1 wherein the fluid compensation reservoir is pressurized to a level of pressure above atmospheric pressure.
7. The tool of claim 1 further comprising a locking dog disposed within the setting chamber, the locking dog releasably securing the primary setting piston to a central mandrel and releasing the primary setting piston from the central mandrel portion when the setting chamber is filled with fluid from the annulus.
8. The tool of claim 7 further comprising a lock sleeve associated with the locking dog, the lock sleeve being moveable within the setting chamber in response to the setting chamber being filled with fluid from the annulus.
9. The tool of claim 2 wherein the fluid communication port is releasably blocked by a frangible rupture member.
10. A packer assembly for use in creating a seal within a wellbore, the packer assembly comprising:
a central mandrel defining a central flowbore along its length;
a packer assembly surrounding the central mandrel and axially compressible to selectively form a fluid seal with a surrounding wellbore wall;
a primary setting portion for selectively axially compressing the packer assembly, the setting assembly comprising:
a primary setting piston operably associated with the packer assembly such that movement of the primary setting piston with respect to the central mandrel compresses the packer assembly, the primary setting piston being moveable in response to absolute well pressure;
a setting chamber associated with the setting piston such that filling of the setting chamber with fluid will free the primary setting piston to move with respect to the central mandrel; and
a fluid pressure compensation reservoir in fluid communication with the setting chamber and containing a fluid that is pressurized at a pressure greater than atmospheric pressure.
11. The packer assembly of claim 10 further comprising a fluid communication port disposed between the setting chamber and an annulus of the wellbore, the port being releasably closed to selectively block fluid flow between the annulus and the setting chamber.
12. The packer assembly of claim 10 further comprising a set of anchoring slips associated with the setting portion to be set by movement of the setting piston.
13. The packer assembly of claim 10 wherein the fluid within the compensation reservoir comprises nitrogen.
14. The packer assembly of claim 10 further comprising a backup setting piston that actuated by hydraulic pressure from the central flowbore to set the packer assembly.
15. The packer assembly of claim 10 wherein the fluid communication port is releasably closed by a frangible rupture member.
16. A method of operating a tool within a wellbore, comprising the steps of:
a) providing a tool for operation within a wellbore, the tool comprising:
a tool operation portion having a settable tool member;
a primary setting portion comprising:
a primary setting piston operably associated with the tool member such that movement of the setting piston sets the tool member, the primary setting piston being moveable in response to absolute well pressure;
a setting chamber associated with the primary setting piston such that filling of the setting chamber with fluid will free the primary setting piston to move to set the tool member;
a fluid pressure compensation reservoir in fluid communication with the setting chamber; and
b) filling the fluid pressure compensation reservoir with a fluid that is pressurized at a pressure above atmospheric pressure;
c) disposing the tool within a fluid-filled wellbore;
d) lowering the tool to a desired depth for operation; and
3) moving the primary setting piston under impetus of absolute well pressure to set the tool member.
17. The method of claim 16 wherein the tool operation portion comprises a packer assembly and the tool member comprises a packer element.
18. The method of claim 16 wherein the fluid pressure compensation chamber is filled with nitrogen.
19. The method of claim 16 wherein a fluid communication port to permit fluid access to the setting chamber is releasably closed by a rupture member that is ruptured by absolute well pressure.
20. The method of claim 19 wherein the rupture member is ruptured by pressurizing the surrounding wellbore from the surface.
21. The method of claim 16 further comprises the step of flowing wellbore fluid into the setting chamber to free the primary setting piston.
22. The method of claim 21 wherein the step of flowing wellbore fluid into the setting chamber further comprises the step of moving a lock sleeve with the wellbore fluid to release the primary setting piston to be moved by absolute well pressure.
23. The method of claim 16 further comprising the step of actuating a backup setting piston to set the tool member.
Priority Applications (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US12/046,168 US20090229832A1 (en) | 2008-03-11 | 2008-03-11 | Pressure Compensator for Hydrostatically-Actuated Packers |
PCT/US2009/036108 WO2009114371A2 (en) | 2008-03-11 | 2009-03-05 | Pressure compensator for hydrostatically-actuated packers |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US12/046,168 US20090229832A1 (en) | 2008-03-11 | 2008-03-11 | Pressure Compensator for Hydrostatically-Actuated Packers |
Publications (1)
Publication Number | Publication Date |
---|---|
US20090229832A1 true US20090229832A1 (en) | 2009-09-17 |
Family
ID=41061751
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US12/046,168 Abandoned US20090229832A1 (en) | 2008-03-11 | 2008-03-11 | Pressure Compensator for Hydrostatically-Actuated Packers |
Country Status (2)
Country | Link |
---|---|
US (1) | US20090229832A1 (en) |
WO (1) | WO2009114371A2 (en) |
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US20090223675A1 (en) * | 2008-03-05 | 2009-09-10 | Schlumberger Technology Corporation | Integrated hydraulic setting and hydrostatic setting mechanism |
US20100252252A1 (en) * | 2009-04-02 | 2010-10-07 | Enhanced Oilfield Technologies, Llc | Hydraulic setting assembly |
US20110042105A1 (en) * | 2009-08-21 | 2011-02-24 | Baker Hughes Incorporated | Zero backlash downhole setting tool and method |
WO2012054253A2 (en) * | 2010-10-19 | 2012-04-26 | Baker Hughes Incorporated | Apparatus and method for compensating for pressure changes within an isolated annular space of a wellbore |
US20140019102A1 (en) * | 2012-07-11 | 2014-01-16 | Landmark Graphics Corporation | System, method & computer program product to simulate the progressive failure of rupture disks in downhole environments |
US20140019107A1 (en) * | 2012-07-11 | 2014-01-16 | Landmark Graphics Corporation | System, method & computer program product to simulate rupture disk and syntactic foam trapped annular pressure mitigation in downhole environments |
US20140076537A1 (en) * | 2012-09-14 | 2014-03-20 | Baker Hughes Incorporated | Multi-Piston Hydrostatic Setting Tool With Locking Feature Outside Actuation Chambers for Multiple Pistons |
US20140076536A1 (en) * | 2012-09-14 | 2014-03-20 | Baker Hughes Incorporated | Multi-Piston Hydrostatic Setting Tool With Locking Feature and a Single Lock for Multiple Pistons |
US8684096B2 (en) | 2009-04-02 | 2014-04-01 | Key Energy Services, Llc | Anchor assembly and method of installing anchors |
WO2014107395A1 (en) | 2013-01-04 | 2014-07-10 | Halliburton Energy Services, Inc. | Pressure activated down hole systems and methods |
US8813857B2 (en) | 2011-02-17 | 2014-08-26 | Baker Hughes Incorporated | Annulus mounted potential energy driven setting tool |
US8881798B2 (en) | 2011-07-20 | 2014-11-11 | Baker Hughes Incorporated | Remote manipulation and control of subterranean tools |
US20150013965A1 (en) * | 2013-06-24 | 2015-01-15 | Blake Robin Cox | Wellbore composite plug assembly |
US9033056B2 (en) | 2012-08-15 | 2015-05-19 | Halliburton Energy Srvices, Inc. | Pressure activated down hole systems and methods |
US9068413B2 (en) * | 2012-09-14 | 2015-06-30 | Baker Hughes Incorporated | Multi-piston hydrostatic setting tool with locking feature and pressure balanced pistons |
US9303477B2 (en) | 2009-04-02 | 2016-04-05 | Michael J. Harris | Methods and apparatus for cementing wells |
US9334338B2 (en) | 2010-04-30 | 2016-05-10 | Halliburton Energy Services, Inc. | Water-soluble degradable synthetic vinyl polymers and related methods |
EP2867446A4 (en) * | 2012-07-02 | 2016-05-25 | Halliburton Energy Services Inc | Packer assembly having dual hydrostatic pistons for redundant interventionless setting |
US9739118B2 (en) | 2014-10-20 | 2017-08-22 | Baker Hughes Incorporated | Compensating pressure chamber for setting in low and high hydrostatic pressure applications |
US9850725B2 (en) | 2015-04-15 | 2017-12-26 | Baker Hughes, A Ge Company, Llc | One trip interventionless liner hanger and packer setting apparatus and method |
WO2018094217A1 (en) * | 2016-11-18 | 2018-05-24 | Baker Hughes, A Ge Company, Llc | High pressure interventionless borehole tool setting force |
WO2019152086A1 (en) * | 2018-02-02 | 2019-08-08 | Geodynamics, Inc. | Hydraulically activated setting tool and method |
US11248428B2 (en) * | 2019-02-07 | 2022-02-15 | Weatherford Technology Holdings, Llc | Wellbore apparatus for setting a downhole tool |
CN115506748A (en) * | 2022-09-26 | 2022-12-23 | 中海石油(中国)有限公司 | Packer setting energy storage device and using method thereof |
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US7836961B2 (en) * | 2008-03-05 | 2010-11-23 | Schlumberger Technology Corporation | Integrated hydraulic setting and hydrostatic setting mechanism |
US20090223675A1 (en) * | 2008-03-05 | 2009-09-10 | Schlumberger Technology Corporation | Integrated hydraulic setting and hydrostatic setting mechanism |
US8453729B2 (en) | 2009-04-02 | 2013-06-04 | Key Energy Services, Llc | Hydraulic setting assembly |
US20100252252A1 (en) * | 2009-04-02 | 2010-10-07 | Enhanced Oilfield Technologies, Llc | Hydraulic setting assembly |
US8684096B2 (en) | 2009-04-02 | 2014-04-01 | Key Energy Services, Llc | Anchor assembly and method of installing anchors |
US9303477B2 (en) | 2009-04-02 | 2016-04-05 | Michael J. Harris | Methods and apparatus for cementing wells |
US8109339B2 (en) * | 2009-08-21 | 2012-02-07 | Baker Hughes Incorporated | Zero backlash downhole setting tool and method |
US20110042105A1 (en) * | 2009-08-21 | 2011-02-24 | Baker Hughes Incorporated | Zero backlash downhole setting tool and method |
US9334338B2 (en) | 2010-04-30 | 2016-05-10 | Halliburton Energy Services, Inc. | Water-soluble degradable synthetic vinyl polymers and related methods |
WO2012054253A3 (en) * | 2010-10-19 | 2012-07-05 | Baker Hughes Incorporated | Apparatus and method for compensating for pressure changes within an isolated annular space of a wellbore |
GB2497481A (en) * | 2010-10-19 | 2013-06-12 | Baker Hughes Inc | Apparatus and method for compensating for pressure changes within an isolated annular space of a wellbore |
WO2012054253A2 (en) * | 2010-10-19 | 2012-04-26 | Baker Hughes Incorporated | Apparatus and method for compensating for pressure changes within an isolated annular space of a wellbore |
GB2497481B (en) * | 2010-10-19 | 2018-07-25 | Baker Hughes Inc | Apparatus and method for compensating for pressure changes within an isolated annular space of a wellbore |
US9488028B2 (en) | 2011-02-17 | 2016-11-08 | Baker Hughes Incorporated | Annulus mounted potential energy driven setting tool |
US8813857B2 (en) | 2011-02-17 | 2014-08-26 | Baker Hughes Incorporated | Annulus mounted potential energy driven setting tool |
US8881798B2 (en) | 2011-07-20 | 2014-11-11 | Baker Hughes Incorporated | Remote manipulation and control of subterranean tools |
US9790764B2 (en) | 2012-07-02 | 2017-10-17 | Halliburton Energy Services, Inc. | Packer assembly having dual hydrostatic pistons for redundant interventionless setting |
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US8983819B2 (en) * | 2012-07-11 | 2015-03-17 | Halliburton Energy Services, Inc. | System, method and computer program product to simulate rupture disk and syntactic foam trapped annular pressure mitigation in downhole environments |
US9009014B2 (en) * | 2012-07-11 | 2015-04-14 | Landmark Graphics Corporation | System, method and computer program product to simulate the progressive failure of rupture disks in downhole environments |
US20140019107A1 (en) * | 2012-07-11 | 2014-01-16 | Landmark Graphics Corporation | System, method & computer program product to simulate rupture disk and syntactic foam trapped annular pressure mitigation in downhole environments |
US20140019102A1 (en) * | 2012-07-11 | 2014-01-16 | Landmark Graphics Corporation | System, method & computer program product to simulate the progressive failure of rupture disks in downhole environments |
US9033056B2 (en) | 2012-08-15 | 2015-05-19 | Halliburton Energy Srvices, Inc. | Pressure activated down hole systems and methods |
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US9238954B2 (en) | 2012-08-15 | 2016-01-19 | Halliburton Energy Services, Inc. | Pressure activated down hole systems and methods |
US9068414B2 (en) * | 2012-09-14 | 2015-06-30 | Baker Hughes Incorporated | Multi-piston hydrostatic setting tool with locking feature and a single lock for multiple pistons |
US20140076537A1 (en) * | 2012-09-14 | 2014-03-20 | Baker Hughes Incorporated | Multi-Piston Hydrostatic Setting Tool With Locking Feature Outside Actuation Chambers for Multiple Pistons |
US9062506B2 (en) * | 2012-09-14 | 2015-06-23 | Baker Hughes Incorporated | Multi-piston hydrostatic setting tool with locking feature outside actuation chambers for multiple pistons |
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US20140076536A1 (en) * | 2012-09-14 | 2014-03-20 | Baker Hughes Incorporated | Multi-Piston Hydrostatic Setting Tool With Locking Feature and a Single Lock for Multiple Pistons |
US9068413B2 (en) * | 2012-09-14 | 2015-06-30 | Baker Hughes Incorporated | Multi-piston hydrostatic setting tool with locking feature and pressure balanced pistons |
WO2014107395A1 (en) | 2013-01-04 | 2014-07-10 | Halliburton Energy Services, Inc. | Pressure activated down hole systems and methods |
US20150013965A1 (en) * | 2013-06-24 | 2015-01-15 | Blake Robin Cox | Wellbore composite plug assembly |
US9739118B2 (en) | 2014-10-20 | 2017-08-22 | Baker Hughes Incorporated | Compensating pressure chamber for setting in low and high hydrostatic pressure applications |
US9850725B2 (en) | 2015-04-15 | 2017-12-26 | Baker Hughes, A Ge Company, Llc | One trip interventionless liner hanger and packer setting apparatus and method |
WO2018094217A1 (en) * | 2016-11-18 | 2018-05-24 | Baker Hughes, A Ge Company, Llc | High pressure interventionless borehole tool setting force |
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US11078738B2 (en) | 2018-02-02 | 2021-08-03 | Geodynamics, Inc. | Hydraulically activated setting tool and method |
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Also Published As
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WO2009114371A2 (en) | 2009-09-17 |
WO2009114371A3 (en) | 2009-12-03 |
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Legal Events
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AS | Assignment |
Owner name: BAKER HUGHES INCORPORATED, TEXAS Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:KING, JAMES G.;REEL/FRAME:020892/0253 Effective date: 20080429 |
|
STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |