US20080196883A1

US20080196883A1 - Centralizing apparatus

Info

Publication number: US20080196883A1
Application number: US12/074,172
Authority: US
Inventors: Gero D. Testa; Phillip Starr; Jan Bouma
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2006-11-15
Filing date: 2008-02-29
Publication date: 2008-08-21

Abstract

A wellhead isolation tool including a cup mandrel and a centralizing device. The centralizing device will align the tool so that the cup seal at the lower end of the cup mandrel sealingly engages the production casing. The cup mandrel has an open bore for allowing service tools to pass therethrough unimpeded.

Description

RELATED APPLICATIONS

This is a continuation-in-part of commonly assigned copending U.S. application Ser. No. 11/600,614, filed Nov. 15, 2006.

BACKGROUND

When a well is drilled to intersect a hydrocarbon-producing formation, it is often necessary to stimulate the formation to enhance the flow of hydrocarbons. Stimulation treatments generally include pumping of fluids under high pressure into a well and into a formation. The stimulation fluid may be, for example, an acid or a proppant containing fluid utilized for fracturing a formation. The stimulation fluids are in many instances corrosive and/or abrasive and can cause damage, sometimes irreparable damage, to wellhead equipment if the fluids are pumped directly through the wellhead into a well. To prevent, or at least limit damage to the wellhead, wellhead isolation tools are used. Wellhead isolation tools are designed to isolate the wellhead from the pressure and corrosive/abrasive fluids.
Known wellhead isolation tools generally utilize a mandrel that is inserted through the various valves and spools of the wellhead. The mandrel will isolate the wellhead from the elevated pressures and from the stimulation fluids utilized during the stimulation process. The mandrel of the wellhead isolation tool is typically connected to a valve through which stimulation fluids will be pumped, and a bottom end of the mandrel is configured with a pack-off assembly so that a seal is provided between the lower end of the mandrel and either the production tubing or casing.
Typically, if other operations are to be conducted in the well, the wellhead isolation tool must be removed to allow the passage of service tools. For example, if it is desired to set a packer or bridge plug in the well above or below a previously perforated formation and perforate an additional formation in the well, the wellhead isolation tool must be removed and the bridge plug, or packer, along with the perforating device can be lowered into the well on a tubing or wire line. Once the bridge plug is set and the additional formation perforated, the service tools must be removed and the wellhead isolation tool reinserted for any stimulation of the formation. The process of removing the wellhead isolation tool, and then reinserting must be repeated any time tools must be lowered into the well to conduct downhole operations. The following U.S. patents and published applications are examples of wellhead isolation tools: U.S. Pat. No. 7,168,495 B2; U.S. Pat. No. 6,817,421 B2; U.S. Pat. No. 6,817,423 B2; and U.S. Pat. No. 6,920,925 B2.
There is a need for a wellhead isolation tool that will provide a proper seal to prevent damage to the wellhead and that will also allow for the passage of other service tools therethrough.

SUMMARY

The wellhead isolation tool of the current invention is a self-aligning wellhead isolation tool that sealingly engages the production casing. The self-aligning wellhead isolation tool of the present invention is comprised of a tool mandrel, a centralizing device mounted and extending radially outwardly from the tool mandrel and a cup seal. The tool mandrel may comprise a multiple-piece mandrel, and thus may include a first tubular mandrel, to which the centralizing device is mounted and a second tubular mandrel which is connected to the first tubular mandrel and to which the cup seal is attached. The centralizing device is adapted to engage a wellhead along at least a portion of the interior thereof to align the isolation tool. The tool mandrel has a first end and a second end, wherein the cup seal is affixed to the second end and extends radially and axially therefrom. The cup seal has an unconstrained lower end that defines a leading edge of the wellhead isolation tool. The cup seal operably seals against the bore of a top casing joint in the wellhead to protect the wellhead during treatment of a well.
The cup seal and second tubular mandrel may be referred to as a cup mandrel. The second tubular mandrel has a first end and a second end, wherein the cup seal is affixed to the second end of the second tubular mandrel. The bore of the second tubular mandrel has an inner diameter large enough to receive a service tool therethrough unimpeded for conducting downhole service operations in a wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 schematically shows service tools positioned in a well.

FIGS. 2A-2D are cross-sectional views of the wellhead isolation tool extending into a production casing.

FIGS. 3A-3E are cross-sectional views of the wellhead isolation tool extending into the wellhead but withdrawn from the production casing.

FIG. 4 is a cross-sectional view of the centralizing device of the invention.

FIG. 5 is a perspective view of an additional embodiment of a centralizing device.

FIG. 6 is a cross-sectional view from line 6-6 of FIG. 5.

FIG. 7 is a cross-sectional view from line 7-7 of FIG. 5.

FIG. 8 is a cross-sectional view of an embodiment of a cup mandrel and with a centralizing device.

FIG. 9 is a cross-sectional view of the cup mandrel.

FIG. 10 is a detail cross-sectional view of the upper end of the cup mandrel with a wireline centralizer shown in dashed lines.

FIG. 11 is a cross-sectional view of the lower end of the cup mandrel.

FIG. 12 is a cross-sectional view of the cup mandrel engaging a casing bore.

FIG. 13 is a cross-sectional view of the tubular mandrel and wireline centralizer.

DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT

Referring to the drawings, FIG. 1 shows a well 10 comprising a wellbore 15 with a production casing 20 cemented therein which intersects formation 25. Perforations 30 may be provided by a manner known in the art to communicate formation 25 with well 10 so that hydrocarbons may be produced through the well. A tool string 31 is schematically shown disposed in well 10. Tool string 31 may include, for example, a sealing device 32 and a perforating device 34. FIG. 1 shows the tool string 31 lowered into well 10 on a wire line 36, but tubing such as jointed or coiled tubing may be used. Perforating device 34 may be, for example, a perforating gun of a type known in the art or, if the tool string 31 is lowered on a tubing, the sealing device may be of a type that utilizes fluid jets to perforate. Sealing device 32 may be a bridge plug, or other type of plug or packer known in the art for sealing the well to prevent flow therethrough. Apparatus known in the art to allow one-way flow may also be placed in the well, including, for example, but not limited to frac plugs. In FIG. 1, well 10 is shown intersecting an additional formation 38 which may be perforated to communicate the formation 38 with well 10 so that hydrocarbons therefrom may be produced up the well. Well 10 may intersect formations in addition to those shown.
Referring now to FIGS. 2A-2D, a cross section of a wellhead 40 is shown. Wellhead 40 defines a wellhead interior 42. A bit guide 44 is positioned in wellhead 40. A pair of seals 46 in a wellhead bore 48 seal against bit guide 44. Production casing 20 is suspended in well 10 with a casing hanger 50. Production casing 20 has outer surface 52 and inner surface 53 and will extend into the well to provide for the production of fluids therethrough. Outer surface 52 of production casing 20 is sealingly received in bit guide 44. The portion of production casing 20 shown in FIG. 2 extending from wellhead 40 may be referred to as a top casing, or top casing joint 54. Top casing joint 54 is received in an inner diameter 56 of bit guide 44, and sealingly engages seals 58. As is known in the art, production casing 20 extends into well 10 as depicted in FIG. 1. Surface casing 60 is suspended and extends from the wellhead 40 downwardly in well 10. Bit guide 44 is located in top head 62 and surface casing 60 extends downwardly from bottom head 64. Casing hanger 50 is seated in bottom head 64.
Wellhead isolation tool 68, which includes a centralizer apparatus 70 may be shown and described with reference to FIGS. 2A-2D and 3A-3E. Wellhead isolation tool 68 is a self-aligning isolation tool that will centralize in wellhead interior 42 of wellhead 40 so as to allow efficient sealing engagement with production casing 20. Referring now to FIG. 4, centralizer apparatus 70 comprises a mandrel 72 with a centralizing device 74 slidably disposed thereabout. Mandrel 72 has upper end 76 and lower end 78. A mandrel extension 80 is attached to upper end 76. Mandrel extension 80 is in turn connected to an upper portion of the wellhead isolation tool, which consists of valves and connections well known in the art. Mandrel 72 is preferably a thin-walled mandrel that defines a mandrel bore 82. Bore 82 is an open bore which provides for the passage of service tools therethrough so that wellhead isolation tool 68 may be utilized not only for treatment processes such as fracturing and acidizing, but as explained in detail hereinbelow, may be left in place when other service operations such as setting plugs, dropping balls or darts to engage seats or tools in the well, and perforating are conducted. Mandrel 72 defines an outer surface 84, with first or upper diameter 86 and second diameter 88 which is smaller in magnitude than upper diameter 86. A radially outwardly extending shoulder 90 is defined on first outer diameter 86. Shoulder 90 may be referred to as a bottom shoulder 90. A shoulder 92, which may be referred to as a top shoulder 92, is defined by a lower end 94 of mandrel extension 80. Shoulder 90 may comprise a ring connected to mandrel 72, or may be integral thereto.
Centralizing device 74 comprises an upper collar 96 and a lower collar 100 and includes a plurality of bow springs 98 extending between and connected to collars 96 and 100, respectively. Collars 96 and 100 may be attached to bow springs 98 by any means known in the art, such as fastening or spot welding. Any desired number of bow springs may be included and in one embodiment, six bow springs 98 are equally spaced around the circumference of collars 96 and 100.
Diameter 88 has a magnitude such that it may be slidably received in production casing 20. The portion of mandrel 72 with outer diameter 88 may be referred to as lower portion 102. A sealing system 104 is operably associated with mandrel 72 such that when mandrel 72 is inserted into top casing joint 54 of production casing 20, a seal is created therebetween. Sealing system 104 is preferably positioned in a groove 106 on lower portion 102. Sealing system 104 comprises an annular ring 108 disposed in groove 106. Annular ring 108 has one or more sealing rings thereon, adapted and sized to sealingly engage inner surface 53 of production casing 20.
In the embodiment of FIG. 4, sealing rings 110 and 112 are disposed about, and preferably integrally formed with annular ring 108. The sealing rings may have increasingly larger diameters from the top down so that a diameter 114 on sealing ring 110 is smaller than a diameter 116 on sealing ring 112. Such an arrangement may be used, but is not necessary. Any number of sealing rings may be formed on annular ring 108.
The operation of the isolation tool 68 is as follows. After well 10 has been drilled and production casing 20 has been installed in wellbore 15, casing 20 will be perforated to create perforations 30 in a manner known in the art, so that formation 25 is communicated with casing interior 22. Formation 25 may then be stimulated by a treatment process such as acidizing or fracturing. If desired, wellhead isolation tool 68 can be installed prior to perforating formation 25, or between the initial perforating step and the stimulating process. Generally, prior to perforating, a plug, packer or other well sealing device will be set in the well below the producing formation 25.
When wellhead isolation tool 68 is inserted into the wellhead 40, it will be inserted so that sealing system 104 is received in top casing joint 54. Sealing system 104 shown in the preferred embodiment includes two sealing rings or seals 110 and 112 of increasing diameter from the lower end 78 toward the upper end 76 of mandrel 72. If desired, more or less than the two sealing rings may be used and one seal only may be used as well. Sealing system 104, and thus seals 110 and 112 are preferably an elastomeric material. Seals 110 and 112 may be swellable elastomeric materials which swell when exposed to a triggering fluid such as water, salt water, hydrocarbons, diesel fuel, kerosene or other chemical materials. Such materials are known and used for example in Halliburton Easywell™ Swellable Technology. Once mandrel 72 is sealingly inserted into production casing 20, stimulation procedures may be conducted. Because mandrel 72 seals inside production casing 20 below bit guide 44, the high pressure experienced during the stimulation procedures does not act upon any components of wellhead 40. Thus, wellhead 40 is protected from not only the high pressure but from the corrosive and/or abrasive effects of the fluids that might be utilized in acidizing or fracturing processes. After the initial formation 25 has been stimulated, it may then be desirable to perforate, stimulate and produce hydrocarbons from one or more additional formations intersected by well 10. The separate locations treated in the well may be referred to as zones, which may be separate formations intersected by the well, or which may be different zones of a single formation.
Because wellhead isolation tool 68 has a relatively thin-walled mandrel and because it has open mandrel bore 82, wellhead isolation tool 68 does not have to be removed from wellhead 40 prior to passing service tools therethrough. Service tools such as, for example, perforating device 34 which may be a perforating gun lowered on a wire line, or a jetting apparatus lowered on a tubing and sealing device 32 may be passed through wellhead isolation tool 68 into production casing 20. Sealing device 32 and perforating device 34 are shown lowered into well 10 as a single tool string on a wire line 36. It is understood that such devices may be lowered separately, and may be lowered on tubing, coiled or jointed, as opposed to wire line 36. Sealing device 32, which may be any number of sealing devices known in the art such as bridge plugs, or packers, is set in well 10 below formation 38 and above formation 25. Perforating device 34 may then be utilized to perforate the additional formation 38 in well 10. Perforating device 34 may then be retrieved and formation 38 may be stimulated with an acidizing or fracturing fluid as known in the art. Such operations can be conducted sequentially in well 10 as many times as desired without the need for removal of the wellhead isolation tool which is more economical and efficient than prior methods. Thus, any desired number of formations may be perforated and treated as described herein without removing wellhead isolation tool 68. While the downhole operation described herein involves sealing the well and perforating at a plurality of locations, it is to be understood that equipment for performing other downhole operations, such as, for example, frac plugs, packers, coil tubing and coil tubing mud motors, drop darts and perforating balls may be lowered through mandrel 72 of wellhead isolation tool 68.
The wellhead isolation tool 68 described herein is a self-aligning isolation tool that is insertable in casing 20 without causing damage to the mandrel 72 or to sealing system 104. As isolation tool 68 is inserted through wellhead 40 and into production casing 20, bow springs 98 will engage wellhead interior 42 and will centralize mandrel 72 so that it will be received in production casing 20 with little or no damage to sealing system 104 and mandrel 72. Prior apparatus which do not utilize a centralizer require a much heavier wall to prevent damage to the mandrel. As such, a more restrictive bore, which does not provide for the passage of service tools, must be used. Tools that seal above top casing joint 54 do not adequately protect the wellhead. Isolation tool 68 resolves both issues. Sealing system 104 will sealingly engage inner bore or inner surface 53 of top casing joint 54 to provide preferably a pressure and fluid tight seal between isolation tool 68 and production casing 20. Because the thin-walled mandrel 72 is centralized, there is little or no risk of damage to the mandrel or the wellhead. Stimulation operations may then be performed as described hereinabove. After stimulation of the well 10, any number of service operations such as setting plugs, perforating and other operations may be conducted with the wellhead isolation tool 68 in place in wellhead 40. The process of stimulating and conducting downhole operations can be repeated as often as necessary, thus alleviating the need for removal of wellhead isolation tools.
Referring to FIGS. 5-7, an additional embodiment of a centralizer apparatus 150 for use in the wellhead isolation tool is shown. Centralizer apparatus 150 comprises a mandrel 152 with a centralizing device 154 slidably disposed thereabout. Mandrel 152 has upper end 156 and lower end 158. Upper end 156 may be attached to mandrel extension 80. Mandrel 152 is preferably a thin-walled mandrel that defines a mandrel bore 160. Bore 160 is an open bore which provides for the passage of service tools and/or coiled tubing therethrough, as with the previously discussed embodiment. The wellhead isolation tool of FIGS. 5-7 will be referred to as wellhead isolation tool 68 a when use with centralizing apparatus 150 is contemplated. Thus, wellhead isolation tool 68 or 68 a may be utilized not only for treatment processes such as fracturing and acidizing, but as explained in detail herein may be left in place when other service operations such as setting plugs and perforating are conducted. Mandrel 152 defines an outer surface 162, with a first or upper groove 164 and second or lower groove 166 defined therein. A shoulder 168 defines a lower end to a first outer diameter 170 defined by outer surface 162. A second outer diameter 172 is smaller than outer diameter 170.
Centralizing device 154 comprises an upper collar 176 and a lower collar 180 and includes a plurality of bow springs 178 extending between and connected to collars 176 and 180, respectively. Bow springs 178 may have first and second end rings 182 and 184, respectively, at the ends thereof. End rings 182 and 184 may be utilized to connect the bow springs to upper and lower collars 176 and 180, respectively. End ring 182 may be spot-welded through openings 186 in upper collar 176. Collar 176 may be attached to bow springs 178 by other means known in the art as well. Likewise, bow springs 178 may be attached by any means known in the art to lower collar 180. Upper collar 176 may comprise a collet that includes a plurality of collet fingers 188. While the centralizing device described herein includes upper and lower collars, other configurations that utilize bow springs may be used, for example, bow springs attached to a collar at only one end.
A sealing system 190 is operably associated with mandrel 152 such that when mandrel 152 is inserted into top casing joint 54 a seal is created therebetween. Sealing system 190 preferably comprises three separate seals, namely a first or upper seal 192, a second or intermediate seal 194 and a third or lower seal 196. Seals 192, 194 and 196 have outer diameters 198, 200 and 202, respectively. Preferably, diameter 202 is smaller than diameter 200 and diameter 200 is smaller than diameter 198 such that the seals are progressively larger in diameter from the lower end 158 of mandrel 152 in a direction upwardly toward upper end 156 of mandrel 152. Seals 192, 194 and 196 are preferably made of an elastomeric material and may be a swellable material as described herein.
When wellhead isolation tool 68 a is inserted into the wellhead 40, it will be inserted so that sealing system 190 is received in top casing joint 54. While sealing system 190 includes three seals 192, 194 and 196 of increasing diameter from the lower end 158 toward the upper end 156 of mandrel 152, more or less than three seals may be used and one seal only may be used as well. Shoulder 168 and groove 164 define the limits of axial movement of centralizing device 154. Lower groove 166 is configured so that collet fingers 188 will be received therein and will prevent any further downward movement relative to mandrel 152. Lower groove 166 therefore is the lower limit of axial movement for centralizing device 154. Grooves 164 and 166 are configured to allow collet fingers 188 to move upwardly, and upward travel relative to mandrel 152 stops when collar 180 engages shoulder 168.
Bow springs 178 will engage wellhead 40 in wellhead interior 42 to centralize and align mandrel 152 with production casing 20. Mandrel 152 may therefore be inserted in production casing 20 without prematurely engaging any other surfaces in wellhead interior 42. Mandrel 152 will not be damaged in the insertion process, and because the mandrel defines an open bore, and has a thin wall, service tools will pass therethrough. Just as described with respect to tool 68, tool 68 a, when inserted in production casing 20 protects wellhead 40 from not only the high pressure but from the corrosive and/or abrasive effects of the fluids that might be utilized in acidizing or fracturing processes. After the initial formation 25 has been stimulated, it may then be desirable to perforate, stimulate and produce hydrocarbons from one or more additional formations intersected by well 10. The operation described can be performed without the removal of isolation tool 68 a.
Referring to FIG. 8, another embodiment of a centralizer apparatus for use in the wellhead isolation tool includes a cup mandrel 300. Cup mandrel 300 comprises a tubular mandrel 302 and a cup seal 304. Cup mandrel 300 is depicted as part of centralizing apparatus 306. Tubular mandrel 302 has a tubular mandrel first end 308 and a tubular mandrel second end 310. Cup seal 304 extends longitudinally and radially from tubular mandrel second end 310.
The wellhead isolation tool of FIGS. 8-13 will be referred to as wellhead isolation tool 301. As discussed heretobefore, wellhead isolation tool 301 is a self-aligning isolation tool that will centralize in wellhead interior 42 of wellhead 40 so as to allow efficient sealing engagement with production casing 20.
Centralizer apparatus 306 comprises a tubular mandrel 311, which may be referred to as tool mandrel 311 and which may be a two-piece mandrel that includes tubular mandrel 302 and a centralizer mandrel 312. Tubular mandrel 302 may be referred to as first tubular mandrel 302 and centralizer mandrel 312 may be referred to as second tubular mandrel 312. A centralizing device 314 is slidably disposed about centralizer mandrel 312, and is similar to previously described centralizer mandrel 74. Centralizer mandrel 312 has upper end 316 and lower end 318. Upper end 316 may be attached to mandrel extension 80. Mandrel extension 80 is in turn connected to an upper portion of the wellhead isolation tool 301, which consists of valves and connections well known in the art. Centralizer mandrel 312 is preferably a thin-walled mandrel that defines a centralizer mandrel bore 322. Centralizer mandrel bore 322 is an open bore which provides for the passage of service tools therethrough so that wellhead isolation tool 301 may be utilized for treatment processes such as fracturing and acidizing and may be left in place for multiple treatments, or when other service operations such as setting plugs, dropping balls or darts to engage seats or tools in the well, and perforating are conducted. Centralizer mandrel 312 defines an outer surface 326, with first outer diameter 328. A radially outwardly extending shoulder 330 is defined on first outer diameter 328. Shoulder 330 may be referred to as a bottom shoulder 330. A shoulder 332, which may be referred to as a top shoulder 332, is defined by a lower end 334 of mandrel extension 80. Shoulder 330 may comprise a ring connected to centralizing mandrel 312, or may be integral thereto.
Centralizing device 314 comprises an upper collar 336 and a lower collar 340 and includes a plurality of bow springs 338 extending between and connected to collars 336 and 340, respectively. Collars 336 and 340 may be attached to bow springs 338 by any means known in the art, such as fastening, or spot welding. Any desired number of bow springs may be included, and in one embodiment, six bow springs 338 are equally spaced around the circumference of collars 336 and 340.
Referring now to first tubular mandrel 302, lower end 318 of centralizer mandrel 312 is mounted to the first end 308 thereof at threaded joint 342. First tubular mandrel 302 has an outer diameter 344 which is smaller in magnitude than upper diameter 328 of centralizing device 306. Because mandrels 312 and 302 are thin-walled, each may be made of a high-strength material, such as a high-strength stainless steel. First tubular mandrel 302 is preferably a thin-walled mandrel defining a tubular mandrel bore 346. Tubular mandrel 302 defines an inner shoulder 348, shown in FIGS. 9 and 10 at an upper end of bore 346. Thus, tubular mandrel 302 is a reduced mandrel bore, in that it has a diameter smaller than centralizer mandrel bore 322. Inner shoulder 348 provides a stop for an internal wireline centralizer 350. The shoulder will prevent internal wireline centralizer 350 from passing beyond inner shoulder 348 and into tubular mandrel bore 346 when a wireline is used to lower service tools therethrough. Internal wireline centralizer 350 is depicted employed on wireline 351 in FIG. 9 and stopped at inner shoulder 348. Inner shoulder 348 may provide a transition from the slightly larger inner diameter of centralizer mandrel bore 322 to tubular mandrel bore 346. Even though tubular mandrel bore 346 is nominally reduced in size, a full bore service tool is still able to pass through first tubular mandrel bore 346 unimpeded. In other words, tubular mandrel 302 of cup mandrel 300 is designed so that a tool designed to pass through the size of top casing joint 54, will also pass through tubular mandrel 302. For example, if a top casing joint 54 is a 5-½ inch nominal casing, a downhole tool, for example, a frac plug, designed for that size, will also pass through tubular mandrel 302. Thus, tubular mandrel 302 allows the use of full bore service tools designed for the top casing joint 54 to pass therethrough to perform operations in the wellbore.
Referring to FIGS. 9 and 11, cup seal 304 is shown affixed to first tubular mandrel second end 310. Second end 310, which is the second end of tool mandrel 311, has a reduced outer diameter 352 to which cup seal 304 is affixed. Cup seal 304 is affixed to tubular mandrel 302 at its first end 356 and may be bonded with a bonding agent. When a bonding agent is used, it will typically be applied to tubular mandrel 302, and heat and compression will be applied so that the cup seal 304 will bond thereto. Cup seal 304 may be affixed by other methods known to those skilled in the relevant art. Cup seal 304 has a second end which is a free end 358 defining a leading edge 360. Free end 358 is unsupported and will be exposed to wellbore fluids. Cup seal 304 has an inner diameter 362 which is at least as large as tubular mandrel bore 346 and which in an unconstrained state, tapers radially outwardly therefrom. Cup seal 304 is unprotected, in that the cup seal is bonded at one end, and is otherwise not supported, or protected by a housing, as is the case with other cup seals.
Referring to FIGS. 9 and 11, cup seal 304 progressively tapers outwardly, and progressively narrows into leading edge 360. Cup seal inner surface 364 and a first portion 365 of cup seal outer surface 366 both taper outward, but cup inner surface 364 tapers outwardly at a steeper angle from the vertical as viewed in the figures than cup outer surface 366. Cup seal 304 has a hinge point 368 on cup outer surface 366. Hinge point 368 may be slightly below a lip 369 on cup seal 304. Cup seal outer surface 366 also has a second portion 367 that angles radially inwardly from first portion 365 thereof towards leading edge 360 to form cup seal leading edge angle 370. Cup seal leading edge angle 370 may be about a 10° to 20° angle, and for example about a 13° inward angle from vertical as viewed in FIG. 9. First portion 365 of cup outer surface 366 may taper outwardly at a first angle 373 of about 1° to 5° and, for example, 2° from vertical and cup inner surface 364 may taper outwardly at a second angle 371 of about 1° to 5° and, for example, 3° from vertical. Angle 371 is preferably greater than angle 373.
In operation, the wellhead isolation tool 301 is lowered so that cup mandrel 300 is inserted into wellhead 40 and cup seal 304 received in top casing joint 54. Cup seal outer surface 366 engages bore 48 of top casing joint 54 to provide preferably a pressure and fluid tight seal. When in position, cup seal 304 is able to withstand a pressure differential of at least 10,000 pounds per square inch while maintaining a seal. Cup seal 304 is fully exposed in that the outer surface 366 and the inner surface 364 thereof are exposed to fluid flow and to wellbore conditions. Cup seal 304 leads the cup mandrel 300 into the top casing joint 54. In its engaged state, in which it engages top casing joint 54 to seal, inner diameter 362 of cup seal 304 thereof is equal to, or smaller than the diameter of mandrel bore 346 of first tubular mandrel 302. Because the tool 301 will self-align as described herein, cup seal 304 will be properly aligned for insertion into top casing joint 54, and will be inserted therein without damage and will efficiently seal.
Cup seal 304 is preferably made of an elastomeric material that is resistant to abrasives and chemicals used during well treatments. Cup seal 304 is also capable of withstanding temperatures of, for example, between about −15° F. and 225° F., which are common to wellbore 15.
Mandrel 302 defines a small annulus area between it and the casing bore against which cup mandrel 300 seals, and has a thin wall which allows a full bore tool to pass therethrough unimpeded. One benefit to the operator is the reduced expense of treating wellbore 15 while also reducing the time it takes to treat wellbore 15.
In practice, cup mandrel 300 will be designed for the particular well of interest. Each specific casing weight will have a specific cup mandrel 300 designed for it to ensure that the cup mandrel 300 will allow a full bore tool to pass therethrough. Cup mandrel 300 is cost efficient in that it may be unthreaded and thus is easily replaceable. Further, tubular mandrel 302 is reusable in that if cup seal 304 becomes damaged it may be forcibly removed, or cut from tubular mandrel 302, and another cup seal 304 may be bonded thereto.
Thus, it is seen that the apparatus and methods of the present invention readily achieve the ends and advantages mentioned as well as those inherent therein. While certain preferred embodiments of the invention have been illustrated and described for purposes of the present disclosure, numerous changes in the arrangement and construction of parts and steps may be made by those skilled in the art. All such changes are encompassed within the scope and spirit of the present invention as defined by the appended claims.

Claims

1. A cup mandrel comprising:

a tubular mandrel defining a bore therethrough and having first and second ends; and

a cup seal affixed to the second end thereof, the cup seal extending longitudinally and radially from the second end of the tubular mandrel and adapted to engage and seal against a casing having an inner diameter larger than an outer diameter of the tubular mandrel.

2. The cup mandrel of claim 1 wherein the bore of the tubular mandrel and the cup seal both have an inner diameter large enough to receive a service tool therethrough unimpeded for conducting downhole service operations in a wellbore.

3. The cup mandrel of claim 1, wherein the cup seal is made of an elastomeric material.

4. The cup mandrel of claim 1, further comprising an annular clearance between the outer diameter of the tubular mandrel and the inner diameter of the casing.

5. The cup mandrel of claim 1, further comprising a hinge point on the cup seal, wherein the cup seal will flex inwardly at the hinge point when the cup seal is inserted into the casing to seal against the casing.

6. The cup mandrel of claim 1, wherein the cup seal has outer and inner surfaces, and wherein the outer surface angles outwardly at a different angle than the inner surface.

7. A cup mandrel comprising:

a tubular mandrel defining a bore therethrough;

a cup seal having a first end affixed to an end of the tubular mandrel, the cup seal further comprising:

a second end, the second end comprising a free end defining a leading edge of the cup mandrel adapted to initially engage a casing in which the cup mandrel is inserted to seal against the casing, the cup seal defining a cup seal inner diameter at least as large as the bore of the tubular mandrel.

8. The cup mandrel of claim 7, wherein the cup mandrel has a low profile with an inner diameter large enough to allow a service tool to pass unimpeded therethrough.

9. The cup mandrel of claim 7, further comprising an annular clearance between an outer diameter of the tubular mandrel and an inner diameter of the casing into which the cup seal is inserted.

10. The cup mandrel of claim 7, further comprising a hinge on the cup seal, wherein the cup will flex inwardly at the hinge when the cup mandrel is inserted into the casing to seal against the casing.

11. The cup mandrel of claim 7, wherein the cup seal is fabricated from an elastomeric material capable of being inserted into a casing and left in place for a plurality of wellbore operations.

12. The cup mandrel of claim 11, wherein the cup seal is able to hold a seal against the casing up to 10,000 pounds per square inch.

13. The cup mandrel of claim 12, wherein the cup seal is able to withstand temperatures up to 225° F.

14. The cup mandrel of claim 7, wherein the service tool is a multistage full bore tool.

15. A self-aligning wellhead isolation tool comprising:

a tool mandrel having first and second ends;

a centralizing device mounted and extending radially outwardly and axially from the tool mandrel adapted to engage a wellhead along at least a portion of an interior thereof to align the isolation tool; and

a cup seal affixed to the second end of the tool mandrel, the cup seal extending radially and axially outwardly from the second end of the tool mandrel, wherein the cup seal is operable to seal against a bore of a top casing joint in the wellhead to protect the wellhead during treatment of a well.

16. The self-aligning wellhead isolation tool of claim 15, wherein the tool mandrel comprises an upper mandrel and a lower mandrel connected thereto.

17. The self-aligning wellhead isolation tool of claim 16, wherein the centralizing device is mounted to the upper mandrel, and wherein the lower mandrel and the cup seal comprise a cup mandrel.

18. The self-aligning wellhead isolation tool of claim 15, wherein the cup seal is made of an elastomeric material.

19. The self-aligning wellhead isolation tool of claim 15, wherein the cup seal has an inner diameter that is at least as great as an inner diameter of the lower mandrel when the cup seal is inserted into and seals against the bore of the top casing joint.

20. The self-aligning wellhead isolation tool of claim 15, wherein the tool may be placed in a wellhead to seal against the top casing joint and remain in place for a plurality treatments of a wellbore.

21. A self-aligning wellhead isolation tool comprising:

a centralizer mandrel having first and second ends;

a centralizing device mounted to and extending radially outwardly and axially from the centralizer mandrel and adapted to engage a wellhead along at least a portion of an interior thereof to align the isolation tool;

a tubular mandrel having first and second ends, the first end being connected to the centralizer mandrel; and

a cup seal affixed at the second end of the tubular mandrel, the cup seal having a free, unprotected lower end that defines a leading edge of the isolation tool, the cup seal being operable to seal against a top casing joint in the wellhead to protect the wellhead during treatment of a well.

22. The self-aligning wellhead isolation tool of claim 21, wherein the cup seal is made of an elastomeric material.

23. The self-aligning wellhead isolation tool of claim 22, wherein the cup seal comprises an inner surface and an outer surface and wherein the inner surface tapers outwardly from the tubular mandrel at a steeper angle than the outer surface.

24. The self-aligning wellhead isolation tool of claim 21, wherein the cup seal has an inner diameter, when sealingly engaged with the top casing joint that is at least as great as an inner diameter of the tubular mandrel.

25. The self-aligning wellhead isolation tool of claim 21, wherein the isolation tool is a low profile tool having a bore sized to allow a service tool to pass unimpeded therethrough for conducting downhole service operations in a wellbore.

26. The self-aligning wellhead isolation tool of claim 21, wherein the cup seal further comprises a hinge point, the hinge point allowing the cup seal to flex inwardly when the leading edge engages the top casing joint.