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Publication numberUS20070000664 A1
Publication typeApplication
Application numberUS 11/171,061
Publication dateJan 4, 2007
Filing dateJun 30, 2005
Priority dateJun 30, 2005
Also published asCA2551067A1, CA2551067C
Publication number11171061, 171061, US 2007/0000664 A1, US 2007/000664 A1, US 20070000664 A1, US 20070000664A1, US 2007000664 A1, US 2007000664A1, US-A1-20070000664, US-A1-2007000664, US2007/0000664A1, US2007/000664A1, US20070000664 A1, US20070000664A1, US2007000664 A1, US2007000664A1
InventorsLev Ring, Paul Metcalfe, Simon Harrall, David Hillis
Original AssigneeWeatherford/Lamb, Inc.
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Axial compression enhanced tubular expansion
US 20070000664 A1
Abstract
Methods and apparatus for expanding a tubular with the aid of a compressive force are disclosed. A tubular is run into a wellbore. While the tubular is in a compressive state, the tubular is expanded into its desired form. The expanded tubular can be used for multiple downhole functions such as completing multilateral junctions in a wellbore, patching apertures in a wellbore and lining a wellbore.
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Claims(22)
1. A method of expanding a tubular in a wellbore, comprising:
positioning the tubular in the wellbore;
affixing at least first and second locations spaced along a length of the tubular to desired locations in the wellbore; and
expanding a portion of the tubular between the locations outward radially with a rotary expander tool, such that the tubular is in axial compression while expanding.
2. The method of claim 1, wherein affixing the second location includes supporting a lower end of the tubular on a bottom of the wellbore.
3. The method of claim 1, wherein affixing the at least first and second locations includes expanding the tubular into frictional contact with a surrounding surface.
4. The method of claim 1, wherein affixing the at least first and second locations includes setting slips on an outer surface of the tubular.
5. The method of claim 1, wherein affixing the second location includes supporting a lower end of the tubular on a plug.
6. The method of claim 1, wherein the tubular is longitudinally corrugated.
7. The method of claim 1, wherein the tubular includes shaped pipe.
8. The method of claim 1, wherein the compression is at least partly as a result of the expanding.
9. A method of lining a drilled wellbore, comprising:
running a tubular into a wellbore;
applying a compressive force to at least a portion of the tubular; and
applying fluid pressure to an inside surface of the tubular in an area of the tubular that is in compression to expand the tubular to a larger diameter.
10. The method of claim 9, further comprising supporting a lower end of the tubular on a bottom of the wellbore.
11. The method of claim 10, wherein applying the compressive force includes placing weight on an upper end of the tubular.
12. The method of claim 9, wherein applying the compressive force includes operating a compressive force apparatus.
13. The method of claim 9, wherein applying the fluid pressure to the inside surface of the tubular expands a lower portion of the tubular into a bell shaped configuration.
14. The method of claim 9, wherein running the tubular includes positioning the tubular in the wellbore proximate to a window in the wellbore.
15. The method of claim 14, wherein applying the fluid pressure to the inside surface of the tubular forms a bulge in a wall of the tubular that extends into a lateral junction which starts at the window.
16. The method of claim 15, further comprising drilling out a portion of the wall of the tubular that is extended into the lateral junction.
17. The method of claim 16, further comprising hanging a liner from the tubular extended into the lateral junction.
18. An apparatus for wellbore completion, comprising:
a tubular coupled to a conveyance member;
one or more compression pistons for applying a compressive load to at least a length of the tubular; and
first and second seals for isolating an inside of the tubular corresponding to at least a portion of the length of the tubular having the compressive load applied thereto, wherein a port to the inside of the tubular supplies hydraulic pressure for acting on a inner surface of the tubular and expanding the tubular.
19. The apparatus of claim 18, further comprising a radially extendable expander for expanding sections of the tubular proximate the first and second seals.
20. The apparatus of claim 18, wherein the tubular is longitudinally corrugated.
21. The apparatus of claim 18, wherein the tubular is shaped pipe.
22. A method of expanding a tubular in a wellbore, comprising:
positioning the tubular in the wellbore;
applying a compressive force to at least a portion of the tubular; and
expanding the portion of the tubular in compression outwardly, wherein expanding includes translating an expansion tool axially while the tubular is in compression.
Description
BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the invention generally relate to expanding tubulars in a wellbore. More particularly, embodiments of the invention relate to the expansion of the tubulars enhanced by use of compressive forces applied to the tubulars.

2. Description of the Related Art

Hydrocarbon and other wells are completed by forming a borehole in the earth and then lining the borehole with pipe or casing to form a wellbore. After a section of wellbore is formed by drilling, a section of casing is lowered into the wellbore and temporarily hung therein from the surface of the well. Using apparatus known in the art, the casing is cemented into the wellbore by circulating cement into the annular area defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.

Recent developments in the oil and gas exploration and extraction industries have included using expandable bore lining tubing. Apparatus and methods are emerging that permit tubulars to be expanded in situ. The most common expansion apparatus is a cone or a swedge. Some expansion apparatus include expander tools which are fluid powered and are run into the wellbore on a working string. These hydraulic expander tools can include radially extendable members which, through fluid pressure, are urged outward radially from the body of the expander tool and into contact with a tubular therearound. As sufficient pressure is generated on a piston surface behind these extendable members, the tubular being acted upon by the expansion tool is expanded past its point of plastic deformation. In this manner, the inner and outer diameter of the tubular is increased in the wellbore. By rotating the expander tool in the wellbore and/or moving the expander tool axially in the wellbore with the extendable members actuated, a tubular can be expanded along a predetermined length in a wellbore. Other methods include using hydraulic pressure inside the tubular to expand the tubular past its point of plastic deformation.

Multiple uses for expandable tubulars are being discovered. For example, an intermediate string of casing can be hung off a string of surface casing by expanding a portion of the intermediate string into frictional contact with the lower portion of surface casing therearound. This allows for the hanging of a string of casing without the need for a separate slip assembly. Additional applications for the expansion of downhole tubulars exist. These include the use of an expandable sand screen, employment of an expandable seat for seating a diverter tool, and the use of an expandable seat for setting a packer.

There are problems associated with the expansion of tubulars. One particularly associated with rotary expander tools is that the rotary expansion of the tubular makes the wall of the tubular thinner. This then increases the overall length of the tubular which is problematic when trying to determine location in the well. Further, expandable tubulars are currently limited to an expansion of 10%-25% of their original diameter using existing expansion techniques that are constrained by the tubular burst pressure and friction applied thereto. Also when using hydraulic pressure to expand the tubular, due to the high pressure required, weaknesses in the tubular are exploited limiting the amount of expansion that can be achieved before the tubular ruptures.

There exists a need for an improved method and apparatus for expanding casing or other tubulars within a wellbore. Further, there exists a need for method and apparatus for expanding a tubular which requires less outward force or hydraulic pressure on the tubular with increased expansion. There exists yet a further need for an apparatus and method for expanding a tubular which reduces the risk of uneven expansion of the tubular by reducing the amount of force needed for the expansion operation. Further, there exists a need for a method of expanding a tubular and accurately controlling the location of the tubing.

SUMMARY OF THE INVENTION

Embodiments of the invention generally relate to methods and apparatus for expanding tubulars in a wellbore enhanced by compressive force applied to the tubulars. According to one aspect of the invention, a method of expanding a tubular in a wellbore includes positioning the tubular in the wellbore, affixing at least two locations spaced along a length the tubular to desired locations in the wellbore, and expanding a portion of the tubular between the two locations outward radially with a rotary expander tool, such that the tubular is in compression while expanding. According to another aspect of the invention, methods and apparatus provide for expanding a tubular run into a wellbore by applying a compressive force to at least a portion of the tubular and applying fluid pressure to an inside surface of the tubular to expand the tubular to a larger diameter. The tubular can be located proximate to a window in the wellbore such that expanding the compressed portion of the tubular covers the window and may form a bulge extending through the window.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments thereof which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

FIG. 1 is a sectional view of a wellbore having a tubular disposed therein for expansion according to aspects of the invention;

FIG. 2 is a sectional view of a tubular and an expansion assembly attached to a work string and disposed in a wellbore;

FIG. 3 is a sectional view of the tubular of FIG. 2 after expansion with hydraulic pressure applied to an inside surface thereof;

FIG. 4 is a sectional view of the tubular of FIG. 2 after completing expansion with hydraulic pressure;

FIG. 5 is a sectional view of the tubular of FIG. 4 after being expanded in a wellbore with a multilateral junction;

FIG. 6 is a sectional view of the tubular of FIG. 5 after being fully expanded;

FIG. 7 is a sectional view of the multi-lateral junction of FIG. 5 completed with the tubular expanded and drilled out; and

FIGS. 8 to 11 are schematic illustrations of steps in the process of lining a bore in accordance with embodiments of the invention.

DETAILED DESCRIPTION

FIG. 1 illustrates a cross-sectional view of a wellbore 100 and a tubular 110 disposed therein. The tubular 110 can be casing or any other type of tubular used in downhole drilling operations, such as a liner or a patch. First and second fixed locations 120, 130 spaced apart along the length of the tubular 110 substantially prevent axial movement of the tubular 110 in the wellbore 100 such that the distance between the fixed locations 120, 130 cannot vary. The fixed locations 120, 130 can be achieved by any method or combination of methods known in the art, such as by using anchors or slips on an outside of the tubular 110 to engage a surrounding surface, by selectively expanding the tubular 110 at one or both of the fixed locations 120, 130 into frictional contact with the surrounding surface or by locating the bottom of the tubular 110 on a stop such as a plug, a packer or a bottom of the borehole (see, FIGS. 9-12). In the embodiment shown in FIG. 1, the fixed locations 120, 130 have been expanded to place the outside surface of the tubular 110 into contact with a surrounding surface. Expansion of the fixed locations 120, 130 can be performed by either using a rotary expander tool 140 or additional expander(s) (not shown), such as one or more inflatable members or packers, capable of selective expansion at the fixed locations 120, 130. The fixed locations 120, 130 create an annular space between the tubular 110 and the wellbore 100. To facilitate expansion of the tubular 110, fluid in the annular space can escape through apertures (not shown) in a surrounding casing and into a formation, through apertures in the tubular 110, across flow paths at one or both of the fixed locations 120, 130 such as by only partial circumferential expansion, and/or directly into the surrounding formation when in an open wellbore. For example, the tubular 110 may serve as a patch to remedy excessive mud loss in an open hole such that fluid from the annular space can easily be pushed into the formation.

U.S. Pat. No. 6,457,532, which is herein incorporated by reference in its entirety, discloses an exemplary rotary expander tool that can be used as the rotary expander tool 140 schematically illustrated in FIG. 1. The rotary expander tool 140 operates to expand the length of the tubular 110 between the fixed locations 120, 130. Typically, the rotary expander tool 140 starts at one fixed location (e.g., the first fixed location 120) and progresses to the other fixed location (e.g., second fixed location 130) expanding the tubular 110 along the way. If only one location along the tubular is initially fixed, expansion can start a distance from that location to thereby provide the other fixed location prior to the rotary expander tool 140 moving toward the initially fixed location. The tubular need not be placed in compression prior to starting expansion of the tubular 110 between the two fixed locations 120, 130 since a compressive load in the tubular 110 develops as expansion with the rotary expander tool 140 progresses. This is due to the fact that use of the rotary expander tool 140 lengthens the tubular 110 by thinning of the tubular wall which, because the fixed locations 120 130 are set to prevent the elongation of the tubular 110, compresses the tubular 110. In contrast, a cone used to expand a tubular typically causes the tubular to shorten during expansion such that tension and not compression develops if the cone is used to expand a section between two fixed locations. The compression in the tubular 110 enhances the expansion process by increasing the expansion possible and decreasing the amount of force required by the rotary expander tool 140.

Before both of the two fixed locations 120, 130 are set, the tubular 110 can optionally be placed in compression either through use of gravity or a mechanical, electrical, or hydraulic device adapted to apply a compressive load on the tubular. Since the tubular 110 is expanded between end points that are fixed, this increases accurate location of the tubular 110 in the wellbore 100. Thus, this process enables accurate placement of liners, patches and other tubulars in the wellbore without the side effects of having the liner elongate or shorten during expansion.

FIG. 2 shows a section of the wellbore 100 with a liner 230 and expandable tubing 200. The expandable tubing 200 can be casing, liner, a patch, or any other type of tubing used in downhole operations for expansion into the liner 230, casing or an open wellbore. FIG. 2 depicts the expandable tubing 200 as a patch used for closing an aperture 235 in the wellbore 100 that is lined. The patch can include a seal 256 and an anchoring element 257 on the outside of the expandable tubing 200.

The expandable tubing 200 attaches to a work string 210 via a setting tool 220. The lower end of the expandable tubing 200 attaches to the work string 210 by a carrying mechanism 240 of the setting tool 220. The carrying mechanism 240 is any suitable temporary connection known in the art such as carrying dogs, collets, threads, latches, slips etc. In one embodiment the carrying mechanism 240 is a set of pre-set slips 231. The pre-set slips 231 engage the inside diameter of the expandable tubing 200 with a series of teeth 232. The pre-set slips 231 support the weight of the expandable tubing 200 and the piston assembly. The pre-set slips 231 are held in place by wedges 233 and 234. Wedge 234 is fixedly attached to the work string 210. Wedge 233 is attached to a slip release assembly 236. The slip release assembly 236 connects to a seat 237. The seat 237 holds a sealing member such as a dart, or ball 270 at its upper end in order to hydraulically seal the work string 210. The seat 237 connects to the work string 210 with a shear pin 238. Above the pre-set slips 231 is a lower pressure seal cup 239 for hydraulically sealing the interior of the expandable tubing 200. At the upper end of the expandable tubing 200, a compression piston 250 of the setting tool 220 attaches the expandable tubing 200 to the work string 210. The compression piston 250 has a shoulder 253 which engages the upper end of the expandable tubing 200. The compression piston 250 moves relative to the work string 210 and a piston base 251. The piston base 251 fixedly attaches to the work sting 210, thus as fluid flows in to an annulus 252, the piston 250 pushes the expandable tubular 200 down relative to the work string 210. With the lower end of the expandable tubular 200 fixed to the work string 210 by carrying mechanism 240, the expandable tubular 200 is in compression. More than one compression piston can be used in order to increase the compressive force applied to the expandable tubing 200, as is known in the art. The carrying mechanism 240 and the compression piston 250 can be adapted to seal the top and bottom of the expandable tubing 200.

As illustrated in FIG. 3, the work string 210 lowers into the wellbore 100 to a desired location for the expandable tubing 200. Once at the desired location, the compression piston 250 actuates upon application of hydraulic pressure through the work string 210, which can be selectively plugged by a stopper, such as a ball 270 dropped onto the seat 237, a diverter valve such as that disclosed in U.S. patent application Ser. No. 10/954,866 assigned to Weatherford/Lamb, Inc. which is hereby incorporated by reference, could also be used. The compression piston 250 urges the attached top of the expandable tubing 200 toward the carrying mechanism 240. This places the expandable tubing 200 in compression since the attachment of the top of the expandable tubing 200 via the compression piston 250 permits relative movement between the work string 210 and the expandable tubing 200 while the attachment of the expandable tubing 200 at the carrying mechanism 240 prevents relative axial movement between the lower end of the expandable tubing and the work string 210. Simultaneously, hydraulic pressure provided through port 245 acts on an inside surface of the expandable tubing 200 to cause radial expansion of the expandable tubing 200 along a length of the expandable tubing 200 between the lower pressure seal cup 239 and an upper pressure seal cup 254.

The expandable tubing 200 can utilize changes in material and configuration in order to enhance expansion. In one embodiment, the tubing thickness at the two fixed end points, the piston 250 and carrying mechanism 240 is larger that the expandable tubing 200 wall thickness between the fixed points. Further, in another embodiment the yield strength and/or elastic modulus of the expandable tubular 200 is changed between the fixed points. In another embodiment the expandable tubular 200 is longitudinally corrugated between the fixed points. In yet another embodiment the expandable tubular 200 has a different material than the material at the fixed points. Further, any of these methods can be used in combination to enhance expansion of the expandable tubular 200. These embodiments ensure the expandable tubular 200 expands from the middle portion first and then outwards toward both ends. This ensures that fluids are not trapped in the annulus between the Expandable tubular 200 and the liner 230.

After expansion of the expandable tubing 200 with hydraulic pressure it is necessary to ensure the expandable tubular 200 is secure in the wellbore by pulling or pushing on the work string 210. The setting tool 220 then releases the expandable tubular 200 at the carrying mechanism 240. By increasing the hydraulic pressure in the work string 210 the seat 237 shears the shear pin 238. This causes the slip release assembly 236 to move down which moves the lower wedge 233 down, releasing the pre-set slips 231 as shown in FIG. 4. Additionally, an expander 265 (shown schematically) actuates to an extended position having an increased outer diameter. The expander 265 can be any type of expandable cone or hydraulically actuated rotary expander tool, such as those disclosed in U.S. Pat. No. 6,457,532, U.S. patent application Ser. No. 10/808,249 and U.S. patent application Ser. No. 10/954,866, which are hereby incorporated by reference.

FIG. 4 shows the expandable tubing 200 while the expander 265 completes expansion of the expandable tubing 200 along its entire length. In operation, lowering the work string 210 moves the expander 265 through the expanded section of the expandable tubular 200 and across the end of the expandable tubular 200 where expansion was previously prevented by the carrying mechanism 240. As the expander 265 moves through the expandable tubular 200, the expander 265 insures proper expansion and/or further expands the previously expanded length of the expandable tubular 200 and expands the bottom end of the expandable tubular 200. Accordingly, the previously unexpanded top end of the expandable tubular 200 where expansion was previously prevented due to attachment to the compression piston 250 occurs upon pulling the expander 265 out of the expandable tubular 200 during removal of the work string 210. For some embodiments, the expander 265 may not be required if it is not desired to expand the ends of the expandable tubular 200 where the expandable tubular attaches to the setting tool 220. Further, the expander 265 can be arranged to work in conjunction the hydraulic expansion in order to enhance the expansion process. Further, the expander 265 can be attached either below or above the expandable tubular 200 or on another tool and actuated once hydraulic expansion is complete. The work string 210 is removed upon completion of the expansion leaving the expandable tubing 200 in place. Thus, the expandable tubing 200 can be used to patch apertures in the casing, liner or the wellbore itself with no liner. In another embodiment, the unexpanded portions of the expandable tubular 200 could be removed by the apparatus and methods disclosed in U.S. Pat. No. 6,598,678 assigned to Weatherford/Lamb, Inc. or as disclosed U.S. Pat. No. 6,752,215 assigned to Weatherford/Lamb, Inc which are hereby incorporated by reference. This procedure can be done multiple times in the wellbore in order to control production from the formations.

FIGS. 5-7 depict an embodiment of the invention that utilizes an assembly similar to that illustrated in FIGS. 2-4. FIG. 5 shows the wellbore 100 with a window 310 cut in the side to provide an opening for a lateral junction 320. An expandable tubing 300 is shown expanded so that it covers the lateral junction 320. The expandable tubular 300 expands using the methods described above. Thus, the expandable tubing 300 is compressed. While in compression, the expandable tubing 300 is expanded by fluid pressure acting on an inside surface of the expandable tubing to initially expand the expandable tubing 300 up to an inner diameter of the wellbore 100, as shown in FIG. 5. The expansion process continues by further application of hydraulic pressure to cause a wall of the expandable tubing 300 to bulge at the window 310 and enter the lateral junction 320, as shown in FIG. 6. For enhanced expansion, the expandable tubing may comprise any suitable material which can sustain an expansion ratio of greater than 20%. Further, the expandable tubing can be initially longitudinally corrugated in order to facilitate a high expansion ratio. The expander 265 is removed from the wellbore. The lateral junction 320 can then be drilled out using techniques known in the art providing a multi-lateral junction, as shown in FIG. 7. A subsequent liner (not shown) can be run into the lateral junction 320 and suspended off of the tubing 300 therein.

FIGS. 8-11 depict an embodiment of the invention used to line a wellbore 400. FIG. 8 shows the lower end of the wellbore 400 including an unlined bore section 410. Above the unlined section 410, casing 420 lines the wellbore 400. As shown, the lower end of the casing 420 includes a larger diameter end section 425, or bell-end, however, the lower end of the casing 420 can be straight pipe.

An expandable tubing or liner 430 is run into the wellbore 400 on a work string 440. The liner 430 is initially coupled to the work string 440 via a setting tool 450. The liner 430 is located in the wellbore 400 such that the upper end of the liner 430 overlaps the larger diameter casing end section 425. The lower end of the liner 430 is positioned at the end of the wellbore 400. The liner 430 itself or a shoe 460 contacts the bottom of the wellbore 400. Next, weight can optionally be set down on the liner 430. The weight can be from the length of the work string 440, or any other method that places the liner 430 in a compressive state.

As shown in FIG. 9, once the liner 430 is in compression, an anchor 470 is set. The anchor 470 can be any type of liner hanger known in the art. With the anchor 470 set, the liner 430 is held in compression between the anchor 470 and the end of the wellbore 400. For some embodiments, the compressive state, as discussed above with regard to FIG. 1, may be caused solely by the expansion process itself and not initially applied to the liner 430 prior to setting of the anchor 470.

Next, as shown in FIG. 10, a rotary expander tool 480 moves downwardly through the liner 430 to expand the liner 430 to a larger diameter such that the expanded inner diameter of the liner 430 corresponds to the inner diameter of the casing 420. A more detailed description of the setting tool and expansion tool can be found in U.S. Patent Application Publication No. 2003/0127225, which is herein incorporated by reference in its entirety. The compressive state of the liner 430 enhances the expansion process and requires less force from the rotary expander tool 480 than conventional methods. Once the desired expansion of the liner is complete, the liner 430 can be cemented in place, and the annulus between the liner 430 and the casing 420 proximate the anchor 470 can be sealed.

FIG. 11 shows creation of a bulge formed monobore shoe, which can be an additional step to the method described in FIGS. 8-10. Once the liner 430 is on the bottom of the wellbore 400, weight is applied to the liner 430 to place the liner 430 in compression. The bottom of the liner 430 is then expanded by fluid pressure applied to the inner surface of the liner 430 to form a bell shaped end 500. For some embodiments, the material used at the bell shaped end 500 of the liner 430 has a thinner wall thickness than the rest of the liner 430 and/or is shaped pipe in order to facilitate expansion thereof and provide the bell shaped end 500 upon expansion. Further, the bell shaped end 500 may be hydraulically isolated from the rest of the liner such that the fluid pressure is applied to only the bell shaped end 500. Additional bell shaped ends (not shown) having smaller diameters than the bell shaped end 500 may be located above the bell shaped end 500. These additional bell shaped ends may be formed by application of a different fluid pressure than applied to the bell shaped end 500 and/or they may be formed of a different material than the bell shaped end 500. The remainder of the liner 430 can be expanded using any expansion method such as a rotary expansion, a swedge or cone, hydraulic pressure and any methods described above.

Any of the expandable tubing described above can be longitudinally corrugated tubing or shaped pipe in order to further facilitate expansion. Using shaped pipe or corrugated tubing also reduces the tendency for pipe to buckle. This allows for compression of longer lengths of pipe enhancing the expansion process further.

Further, the methods described above can be used in any type of down hole tubular expansion including but not limited to liner hangers, packers, straddles, PBRs, drilling-with-liner, etc.

While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US7753130 *Mar 21, 2006Jul 13, 2010Bbj Tools Inc.Method and tool for placing a well bore liner
US8100188 *Oct 24, 2007Jan 24, 2012Halliburton Energy Services, Inc.Setting tool for expandable liner hanger and associated methods
US8109340Jun 27, 2009Feb 7, 2012Baker Hughes IncorporatedHigh-pressure/high temperature packer seal
US8201636Feb 19, 2009Jun 19, 2012Weatherford/Lamb, Inc.Expandable packer
US8393389Apr 20, 2007Mar 12, 2013Halliburton Evergy Services, Inc.Running tool for expandable liner hanger and associated methods
US8499844Jun 14, 2012Aug 6, 2013Weatherford/Lamb, Inc.Expandable packer
US8627884Mar 22, 2011Jan 14, 2014Halliburton Energy Services, Inc.Setting tool for expandable liner hanger and associated methods
US8839870Mar 30, 2010Sep 23, 2014Weatherford/Lamb, Inc.Apparatus and methods for running liners in extended reach wells
US8967281Jul 15, 2013Mar 3, 2015Weatherford/Lamb, Inc.Expandable packer
US8991489 *May 5, 2009Mar 31, 2015Weatherford Technology Holdings, LlcSignal operated tools for milling, drilling, and/or fishing operations
US20110232355 *Mar 26, 2010Sep 29, 2011Evans Merle EDynamic load expansion test bench
US20110253394 *Nov 16, 2009Oct 20, 2011Mark Wilson AndersonModifying expansion forces by adding compression
US20120097391 *Oct 22, 2010Apr 26, 2012Enventure Global Technology, L.L.C.Expandable casing patch
US20130000914 *Jun 29, 2011Jan 3, 2013Baker Hughes IncorporatedThrough Tubing Expandable Frac Sleeve with Removable Barrier
US20130160999 *Aug 30, 2011Jun 27, 2013Welltec A/SSealing system
WO2012041955A2 *Sep 29, 2011Apr 5, 2012Welltec A/SDrill pipe
WO2012127229A2Mar 21, 2012Sep 27, 2012Read Well Services LimitedApparatus and a method for securing and sealing a tubular portion to another tubular
WO2013012931A2Jul 18, 2012Jan 24, 2013Weatherford/Lamb, Inc.Apparatus and method of zonal isolation
WO2014207085A1 *Jun 26, 2014Dec 31, 2014Welltec A/SPatch setting tool
Classifications
U.S. Classification166/277, 166/380, 166/207
International ClassificationE21B23/00
Cooperative ClassificationE21B43/103, E21B43/105, E21B41/0042
European ClassificationE21B43/10F1, E21B41/00L2, E21B43/10F
Legal Events
DateCodeEventDescription
Jun 30, 2005ASAssignment
Owner name: WEATHERFORD/LAMB, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:RING, LEV;METCALFE, PAUL;HARRALL, SIMON;AND OTHERS;REEL/FRAME:016752/0866;SIGNING DATES FROM 20050614 TO 20050621