US3540533A - Remote packoff method and apparatus - Google Patents

Remote packoff method and apparatus Download PDF

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Publication number
US3540533A
US3540533A US783943A US3540533DA US3540533A US 3540533 A US3540533 A US 3540533A US 783943 A US783943 A US 783943A US 3540533D A US3540533D A US 3540533DA US 3540533 A US3540533 A US 3540533A
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United States
Prior art keywords
wellhead
seal
packoff
assembly
casing
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Expired - Lifetime
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US783943A
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English (en)
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Charles D Morrill
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Rockwell Manufacturing Co
Smith International Inc
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Rockwell Manufacturing Co
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Assigned to SMITH INTERNATIONAL, INC., A CORP. OF CA reassignment SMITH INTERNATIONAL, INC., A CORP. OF CA ASSIGNMENT OF ASSIGNORS INTEREST. Assignors: MCEVOY OILFIELD EQUIPMENT COMPANY
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    • 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
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/04—Casing heads; Suspending casings or tubings in well heads
    • E21B33/043—Casing heads; Suspending casings or tubings in well heads specially adapted for underwater well heads
    • 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
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/04—Casing heads; Suspending casings or tubings in well heads
    • E21B33/047—Casing heads; Suspending casings or tubings in well heads for plural tubing strings

Definitions

  • the packoff assembly comprises a latch retainer ring, latches, locking sleeve, compression sleeve, energizer ring, inner and outer seal rings and a limit ring.
  • the locking sleeve is telescopically engageable with the latch retainer ring for movement behind the latches for latching theentire assembly to a wellhead.
  • the compression sleeve is connected by threads to the latch retainer ring and the energizer ring is rotatably connected by ball hearings to the lower end of the compression sleeve.
  • the inner and outer seal rings are mounted on either side of a limit ring and in engagement with the lower end of the energizer sleeve.
  • the tool and locking sleeve are then rotated to the right where they drop downward causing the latches to lockingly engage the wellhead. Further rotation to the right causes the seal rings to compress and sealingly engage the surrounding wellhead and the casing and hanger assembly.
  • the tool may be removed simply by pulling upwardly thereon.
  • A77 ENE 1. Field of the Invention This invention is related to well completion methods and apparatus. More specifically it is related to methods and apparatus for remotely completing an underwater well without the assistance of divers.
  • Oil is being found at locations of ever increasing'water depths. In relatively deep water. e.g. 600 feet or more. it may be difficult if not impossible to use a permanent platform or even a jack-up type drilling platform. More recently, methods are being developed using a floating-type platform with most of the drilling equipment and essentially all of the completion apparatus being supported at the mudline. Such a method must present a solution for many problems. For instance, the method must provide a relatively high degree of flexibility between the drilling platform and the underwater apparatus since floating platforms are naturally less stable than stationary platforms. Otherproblems are encountered due to the water depths which hinder the activities of divers. Thus. completely remote, diverless completion methods and apparatus are desirable.
  • Packoff assemblies are normally installed in the annular spaces between casing. tubing and their supporting heads. These packoff assemblies are normally installed after their respective casing and tubing is installed and supported at the mudline. In the past it has been difficult to install, by remote means, a packoff which will assure an effective seal. It has also been difficult to design a packoff which, after being latched in place, provides a means of further compressing its sealing ele ment. Still another problem has been the development of a packoff which may be easily and remotely removed for workover operations or for repair ofthe packoff.
  • latch locking means engageable with the tubular latch retainer means and movable to a position behind the latch means preventing retraction thereof, tubular seal carrying means i for sealing engagement of the wellhead and the apparatus supported therein.
  • the packoff assembly may be easily installed by lowering it on a special tool into the annular space between the wellhead and its supported apparatus.
  • the tool and locking sleeve are rotated to the right to a point where they drop downwardly causing the latches to lockingly engage the wellheadbFurther rotation to the right causes the seal rings to compress and sealingly engage the surrounding wellhead and the supported apparatus.
  • the tool may then be removed by simply pulling upwardly thereon.
  • Several packoff assemblies may be installed one above the other in the wellhead using the same tool.
  • FIG. 1 is an elevational view. partially in section. of an underwater wellhead installation according to a preferred embodiment of the invention
  • FIG. 2 is an elevational view partially in section. of an underwater wellhead installation according to an alternative em- DESCRIPTION OF THE PREFERRED EMBODIMENT
  • Figure I a wellhead installation for a 30"-20-l3%"9%"-7" casing program and a dualtubing string is shown.
  • casing and tubing stringprograms may be employed with the present invention. this particular program being used for illustration purposes only.
  • Conductor CasinglO may be run in a drilled hole if bottom conditions require it.
  • a hold is drilled for 20 inch surface casing 20.
  • the casing is run in place. landed and cemented.
  • Surface casing 20 is supported on casing head 11 by tubular casing head or hub member which is welded to the upper end thereof.
  • Hub member 21 is provided with laterally acting latches 22 which engage an annular groove 12 on casing head I l. as a holddown device.
  • Conductor casing head 11 isprovided with'ports 13 through its walls to allow exit of excess cement returns when casing20 is cemented inplace.
  • hub member 21 has an annularupwardly facing support shoulder 24 and an annular latch groove 25. Its upper end is provided with a flange portion26 which may be used for coupling to a 20 inch blowout preventer and ariser extension (not shown) through which further drilling "may proceed.
  • the 20 inch blowout preventer and extension normally attached to hub flange 26, may be removed and a l3%inch blowout preventer and extension (not shown) may be attached to wellhead flange 39 by a remote connector such as the connector generally represented at 40.
  • a remote connector such as the connector generally represented at 40.
  • Hanger 51 is provided with a support ring 52 through which passages 53 are formed for cement returns.
  • hanger 51 may be provided with plungers 54 to engage a groove on wellhead 31 as a holddown.
  • Notches or recesses 55 are cut at regular intervals around the upper portion of support ring 52. These recesses function as packoff rotation limiting means as will subsequently be seen.
  • casing 70 is run in, landed and cemented.
  • Casing 70 is supported on the upper surface 61 of packoff assembly 60 by easing hanger 71.
  • the major outside diameter of intermediate hanger 71 is substantially the same as lower hanger 51. It is also provided with cement return passages 72 and rotation limit recesses 73.
  • intermediate packoff assembly 80 is installed around the upper end of easing hanger 71 sealing the annular space between the hanger 71 and wellhead 31. it is latched in wellhead groove 36.
  • Packoff assembly 80 is identical to lower packoff assembly 60 and may be set with the same tools. As previously mentioned these packoffs and their installation will be more fully described hereafter.
  • tubing hanger 91 After setting packoff 80, 7 inch casing 70 would be perforated and tubing 90 would be run in the well and supported on packoff assembly 80 by tubing hanger 91.
  • the tubing hanger 91 shown in the drawings is a boll weevil type supported by the cooperation of its frustoconical surface 92 and the frustoconical surface 82 of packoff assembly 80.
  • upper packoff assembly 100 is installed in the same manner as lower packoff 60 and intermediate packoff 80. It is latched into wellhead groove 37 sealing the annular space between tubing head 91 and wellhead 31.
  • the well may be permanently abandoned. temporarily abandoned or immediately completed. If temporarily abandoned the blowout preventer stack can be uncoupled from wellhead flange 39 and a protective cap may be attached to either wellhead flange 39 or hub flange 26 protecting the well from the underwater environment.
  • FIG. 2 illustrates apparatus used in such a situation.
  • slip type hangers 59 and 79 would be used to support casing 50 and 70 should they become stuck.
  • packoffs 69 and 89 would be identical to packoffs 60 and 80.
  • the assembly comprises the following major portions: locking sleeve 210, latches 220. latch retainer ring 230. compression sleeve 240. energizer ring 250. inner seal ring 260. outer seal ring 270, and limit ring 280.
  • the exterior of locking sleeve 210 is generally defined by an upper cylindrical surface connected to a lower smaller diameter cylindrical surface by downwardly facing frustoconical shoulder 211.
  • the lower cylindrical surface is connected to lower annular face 212 by beveled edge 213.
  • the interior of locking sleeve 210 is defined by a generally cylindrical surface connected to upper annular face 214 by upwardly facing frustoconical surface 215.
  • An annular groove 216 is cut on the cylindrical interior of locking sleeve 210.
  • Four holes 217 are drilled and tapped in the upper face 214. They may be used for handle members if desired. For installation these holes 217 will be used to receive shear pins, the purpose of which will be more clearly understood later.
  • Antirotation recesses 218 are cut at 90 intervals on the upper face 214.
  • the L-slots have longitudinal leg portions 219,, and circumferential foot portions 2l9,,.
  • segmented latches 220 which are cut from a ring with a cylindrical outer face 221 and inner face 222.
  • Frustoconical surfaces 223 and 224 connect outer face 221 to upwardly facing flat surface 225 and downwardly facing flat surface 226 respectively.
  • a beveled cam surface 227 joins flat surface 225 to inner face 222.
  • Latch retainer ring 230 a tubular member. has an upper portion of reduced internal diameter 231 which is provided with window slots 232 in which latches 220 may be retained for lateral sliding movement. Diameter 231 is slightly greater than the upper external diameter of locking sleeve 210 to permit a sliding or telescopic fit.
  • An annular groove 233 is machined around the interior of retainer ring 230 and a plurality of tapped holes 234 communicate with groove 233 and the exterior of retainer ring 230.
  • Halfdog set screws 235 may be inserted in holes 234 for engaging locking sleeve L-slots 219, allowing limited longitudinal and rotational movement of locking sleeve 210 relative to retainer ring 230 but preventing the lateral escape of latches 220 from window slots 232.
  • the lower smaller internal diameter 236 of retainer ring 230 is threaded for engagement with compression sleeve 240.
  • the lower end of retainer ring 230 is provided with depending stop lugs 237.
  • Compression sleeve 240 is threaded on its upper exterior 241 for threading engagement with the lower interior 236 of retainer ring 230.
  • the lower exterior of sleeve 240 is provided with an annular groove 242 whose cross section is a semicircle. This groove 242 cooperates with a similar oppositely facing groove 251 on energizer ring 250 to form a race for ball bearings 243 so that compression sleeve 240 and energizer ring 250 are rotatingly connected.
  • Ball bearings 243 may be inserted through a hold (not shown), in the wall of sleeve 240, which is plugged after the balls are in place.
  • the generally cylindrical interior 244 of sleeve 240 is connected to upper and lower flat faces 245 and 246 by frustoconical surfaces 247 and 248 respectively.
  • a plurality of L-slots 249 with leg portion 249,, and foot portion 249, are cut on the interior of sleeve 240.
  • the leg portion 249a opens toward upper surface 245 through frustoconical surface 247.
  • the purpose of L-slots 249 is for engagement of a running and pulling tool to be fully described hereafter.
  • energizer ring 250 is rotatingly connected to sleeve 240 by the cooperation of ball race grooves 242, 251 and ball bearings 243.
  • the exterior of energizer ring 250 is generally cylindrical in shape. its interior is defined by a larger diameter portion connected to a smaller diameter portion by upwardly facing annular shoulder 252.
  • the upper flat face 253 of energizer ring 250 is interrupted at 180 intervals by lug notches 254 which cooperate with retainer ring lugs 237 as will be better understood hereafter to prevent rotation of energizer 250 relative to retainer ring 230.
  • the lower end of energizer ring 250 comprises a relatively deep annular slide groove 255 opening downwardly and arcuate seal energizing ridges 256 and 257 on either side of slide groove 255.
  • Limit ring 280 comprises an upper cylindrical sleeve portion 281 connected to a foot portion 282.
  • the wall thickness of cylindrical sleeve portion 281 is slightly less than the width of energizer slide groove 255 permitting'a telescopic sliding fit between limit ring 280 and energizer ring 250.
  • the foot portion 282 is provided withupwardly projectingarcuate seal energizing ridges 283 and 284. At regular intervals around the bottom of foot portion 282, antirotation lugs 285 are provided to cooperate with a hanger as subsequently explained to prevent rotation of limit ring 280 relative to the hanger.
  • An annular groove 286 is cut on the exterior of cylindrical portion 281 for engagement by a plurality of screws 258 which project inwardly from tapped holes 259 in energizer ring 250.
  • the groove 286 is wide enough to permit limited longitudinal movement of limit ring 280 relative to energizer ring 250.
  • Inner and outer resilient seal rings 260, 270 are designed to fit between the foot portion 282 of limit ring 280 and the lower end of energizer ring 250, one on each side of cylindrical portion 281.
  • Inner seal ring 260 comprises an inner arcuate flange portion 261 connected to an outer arcuate flang'e portion 262 by a short body portion 263, leaving small annular spaces 264, 265 above and below body portion 263 and between the lips of flange portions 261, 263.
  • outer seal ring 270 comprises an inner arcuate flange portion 271 connected to an outer arcuate flange portion 272 by short body portion 273 leaving annular spaces 274, 275 between the lips of flange portions 271, 273.
  • seal energizing ridges 256, 257, 283 and 284 engage seals 260 and 270 in the annular spaces 274, 264, 27-5 and 265, respectively.
  • limit ring 280 is in the lowest position permitted by screws 258 and groove 286, seal rings 260 and 270 are in an unstressed or relaxed condition.
  • FIGS. 4 and 5 the installation of a packoff assembly, whose parts and reference numbers correspond to the packoff assembly shown in FIG. 3, will be described.
  • the packoff assembly is shown in a wellhead 110 supporting a casing hanger 115 and attached casing (not shown) on upwardly facing support shoulder 111 in substantially the same relationship as wellhead 31 and casing hanger 51 of FIG. 1.
  • the wellhead'110 is provided with an annular latch groove 112 cor- V responding to groove 35 in FIG. 1.
  • FIG. 4 represents the running position of the packoff assembly and FIG. 5 represents the set position.
  • the packoff assembly is mounted around arunning and pulling tool 150 which is in turn connected by threads 151 or the like to a running string 152.
  • Tool 150 comprises tubular head portion 160, tubular body portion 180, annular lip seal 190 and lip seal retainer 195.
  • the exterior of head portion 160 is defined by varying diameter cylindrical portions connected by flange member 164, downwardly facing flat shoulders 161, and frustoconical shoulder 162.
  • the lower exterior of head 160 is provided with a plurality of outwardly and radially projecting pins 163. These pins 163 are designed to engage L-slots 249 of compres sion sleeve 240.
  • Also mounted on head 160 are a plurality of packoff recovery pins 165. These pins 165 are mounted in radial holes 166 provided for them and biased in a retracted position as shown by spring 167.
  • the inner ends of pins 165 communicate with the bore 168 of head portion I60 and the bore of running string 152.
  • a sliding seal I69 prevents pressure loss-from around the pins 165.
  • Pins are provided with an annular shoulder 170.
  • a lock pin 171 Mounted through flange member 164 and resiliently biased into contact with shoulder 170 is a lock pin 171, the purpose of which will be understood more fully hereafter.
  • Body portion of tool 150 is sealingly connected to the head portion by threads 181 and annular seal 182.
  • the bore 183 of body portion 180 provides flow communication between head 'bore 168 and the casing supported by hanger 115.
  • a test port 184 and plug 185 provide a means of communication between bore 183 and the space surrounding body portion 180.
  • limit ring 280 comes to a stop against support ring 113 of hanger 115. If the antirotation lugs 285 are not already engaging antirotation recesses 114 of hanger support ring 113, the entire packoff assembly is rotated to the right by tool 150 until they do so engage the recesses.
  • the small shear pins (not shown) between stop ring 210 and latch retainer ring 230 would prevent rotation of locking sleeve 210 until the packoff assembly is properly buttomed up and engaging recesses 114. Even ifthese small shear pins were not used no harm would be done since, normally, latches 220 could not move outwardly until the entire assembly is properly bottomed up with latches 220 in a juxtapositional relationship with groove 112.
  • Next tool 150 and locking sleeve 210 are rotated to the. right, after first shearing the small shear pins (not shown) between latchretainer ring 230 and locking sleeve 210.
  • tool 'pins 163 move along the upper edge of L-slot foot portion 249,, and stop ring L-slots 219 move relative to support screws 235 until these support screws 235 enter the leg portion 219,, of L-slots 219.
  • the weight of tool 150 and its attached running string 152 cause locking sleeve 210 and tool 150 to move downwardly forcing latches 220 into engagement with wellhead latch groove I12.
  • Locking sleeve 210 is forced downwardly until it is completely behind latches 220 locking them in engagement asshown in FIG. 5. 0n furtherrotation of tool 150 to the right, shear pin 173 is sheared and tool pins 163 moved against the back of compression sleeve L-slot leg portions 249 Continued rotation of tool 150 then causes compression sleeve 240 to rotate and,
  • the seals may be tested by pressuring through the annular space surrounding -running string 152 or, if preferred, by pressuring through the running string 152 and tool bore 183 and test port- 184. If the seal requires further compression the tool may be rotated further.
  • the length of limit ring cylindrical portion 281 prevents the seals from being compressed to a point of collapsing hanger or wellhead walls by stopping rotation when cylindrical sleeve portion 281 bottoms up in energizer slide groove 255.
  • the tool 150 may be removed by simply pulling upwardly on running string 152, tool pins 163 sliding upwardly out of L-slot legs 249,,.
  • a ball 196 of a resilient material is dropped through string 152 coming to rest at the mouth of body portion bore 183. Then the string is pressured up. The pressure forces packoff recovery pins 165 into groove 216 on the interior of stop ring 210. Lock pins 171 are urged behind pin shoulders 170 locking the recovery pins l65 into the groove 216.
  • An upward pull on string 152 will cause locking sleeve 210 to move upwardly freeing'latches 220 for movement to the retracted position shown in FIG. 4, allowing the entire assembly to be removed.
  • the packoff assembly can also be removed at a future date in the same method after the tool is lowered into position.
  • All of the packoff assemblies shown in H08. 1 and 2 can be set in the same manner using the same running and pulling too]. However, the bottom of some of the packoffs such as 100 in FIG. 1 and 89 in FIG. 2 engage recesses such as 2l8 (FIGS. 3-5) in the top of adjacent packoffs to prevent rotation instead of engaging hangers.
  • the method utilizes a unique packoff assembly which is compressed after latching the assembly in place and which may be removed simply by pulling upwardly on a portion of the assembly.
  • a packoff assembly for installation in a wellhead comprising tubular latch retainer means on which is mounted laterally movable latch means, latch locking means engageable with said tubular latch retainer means and movable to a position behind said latch means preventing retraction thereof, tubular seal carrying means connected to said latch retainer means and annular seal means mounted on said seal carrying means, characterized in that said tubular seal carrying means comprises tubular energizer means rotatingly connected to compression sleeve means, said compression sleeve means being threadingly connected to said tubular latch retainer means, said annular seal means being in contact with said energizer means and on longitudinal movement of said energizer means being longitudinally compressive for sealingly engaging the inner and outer confines of an annular space in said wellhead, said longitudinal movement of said energizer means being effected by rotation and axial advancement of said compression sleeve means through said threaded connection with said latch retainer means.
  • a packoff assembly as set forth in claim 1 characterized in that said tubular energizer means and said latch retainer means are provided with antirotation means allowing limited longitudinal movement relative to each other but preventing rotational movement relative to each other.
  • Apparatus for installation in an underwater well comprising a wellhead supported near the floor of a body of water, tubular means concentrically disposed in said wellhead leaving an annular space therebetween and a packoff assembly sealingly engaging said annular space to prevent fluid flow therethrough, characterized in that said packoff assembly comprises latching means engageable with said wellhead, locking means engageable with said latching means to prevent disengagement from said wellhead.
  • annular seal means engaging said annular space, compression means rotatably connected to said seal means and threadingly connected to said latching means whereby a torque applied to said compression means transmits a longitudinal force to said seal means for activation thereof without movement of said latching means.
  • said resilient seal means comprises an inner arcuate flange portion connected to an outer arcuate flange portion by a body portion leaving annular spaces above and below said body portion and between the lips of said flange portions, said upper and lower seal means member being provided with annular ridge members for engaging said resilient seal means annular spaces to force said flange lips outwardly therefrom.
  • said latching means comprises a tubular retainer member on which are mounted laterally movable latch members
  • said locking means comprising sleeve means mounted on said latching means for limited movement and provided with camming means for moving said latch members outwardly into engagement with groove means on the interior of said wellhead, said sleeve means being positionable behind said latch members locking them in said wellhead groove means.
  • seal means is provided with a resilient annular seal mounted between a lower stop portion of said seal means and said longitudinally displaced portion, said stop portion being stationary on said compression means rotation to compress said resilient annular seal into sealing engagement with said wellhead and said tubular means concentrically disposed therein.
  • a packoff assembly for installation in an underwater wellhead in which is supported tubular means with an annular space between a portion of said tubular means and said wellhead; comprising tubular latch retainer means; latch members mounted on said retainer means for lateral movement to engage a groove within said wellhead; locking sleeve means attached to said retainer means for limited movement. said sleeve means being positionable behind said latch members to lock said assembly to said wellhead; compression sleeve means connected to said retainer means through mutually engageable continuous threads; seal carrying means rotatingly connected to said compression sleeve means; a resilient annular seal mounted on said seal carrying means. said resilient seal being compressible to sealingly engage said wellhead and said tubular means within said annular space on said compression sleeve means being rotated through said continuous threads to longitudinally displace said retainer means and a portion of said seal carrying means.
  • a packoff assembly for installation in an underwater wellhead in which is supported tubular means with an annular space between a portion of said tubular means and said wellhead; comprising tubular latch retainer means; latch members mounted on said retainer means for lateral movement to engage a groove within said wellhead; locking sleeve means attached to said retainer means for limited movement, said sleeve means being positionable behind said latch members to lock said assembly to said wellhead; compression sleeve .means threadingly connected to said retainer means; seal cartying means rotatingly connected to said compression sleeve means; a resilient annular seal mounted on said seal carrying means, said resilient seal being compressible to sealingly engage said wellhead and said tubular means within said annular space on said compression sleeve means being rotated to longitudinally displace said retainer means and a portion of said seal carrying means, characterized by first antirotation means on said seal carrying means engageable with stop means within said annular space to prevent rotation of said seal carrying means and second antirotation means on said seal carrying means
  • a packoff assembly as set forth in claim 17 characterized in that said resilient seal means comprises an inner seal ring mounted on the interior of a cylindrical sleeve portion of one of said telescopically engageable members and an outer seal ring mounted on the exterior of said cylindrical sleeve portion.
  • a method of installing a packoff assembly in an annular space between a remote wellhead and other apparatus concentrically disposed therein comprising the steps of: lowering said packoff assembly into said annular space, latching said assembly to said wellhead and, after said latching, rotating a portion of said packoff assembly through continuous thread means to continuously compress annular seal means on said assembly throughout said rotating for sealing engagement with said wellhead and said other apparatus.
  • a method of completing a well having a wellhead supported near the floor of a body of water comprising the steps of: running a casing string into said well, suspending said casing string on a casing hanger within said wellhead, lowering a packoff assembly with an annular seal means thereon into an annular space between said wellhead and said casing and hanger assembly, latching said packoff assembly to said wellhead and. subsequently thereto, rotating a portion of said packoff assembly to continuously compress said seal means for sealing engagement of said wellhead and said casing and hanger assembly.
  • a method of completing a well as set forth in claim .23 comprising the additional steps of: running a second casing string into saidWeILsuspending said second casing string on a second casing hanger within said wellhead, lowering a second packoff assembly with annular seal means thereon into an annular space between said wellhead and said second casing and hanger assembly, latching said second packoff assembly to said wellhead and, subsequently thereto, rotating a portion of said second packoff assembly to continuously compress said seal means for sealing engagement of said wellhead and said casing and hanger assembly.
  • a method of completing a well as set forth in claim 23, comprising the subsequent steps of: running at least one tubing string into said well, suspending said tubing string on a tubing hanger within said wellhead, lowering another packoff assembly with annular seal means thereon into an annular space between said wellhead and said tubing and hanger assembly, latching said another packoff assembly to said wellhead and rotating a portion of said another packoff assembly to compress said seal means for sealing engagement of said wellhead and said tubing and hanger assembly.
  • a method of installing a packoff assembly as set forth in claim 19 comprising the additional step of testing said sealing engagement by pressuring said annular space on one side of said seal means.
  • a method of installing a packoff assembly as set forth in claim 26 comprising the additional step of further rotating said portion of said packoff assembly to further compress said annular seal means.
  • a method ofinstalling a packoff assembly as set forth in claim 23 comprising the additional step of testing said sealing engagement by pressuring said annular space on one side of said seal means.
  • a method of installing a packoff assembly as set forth in claim 28 comprising the additional step of further rotating said portion of said packoff assembly to further compress said annular seal means.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
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US783943A 1968-12-16 1968-12-16 Remote packoff method and apparatus Expired - Lifetime US3540533A (en)

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US (1) US3540533A (enrdf_load_stackoverflow)
DE (1) DE1962443C3 (enrdf_load_stackoverflow)
FR (1) FR2026197A1 (enrdf_load_stackoverflow)
GB (1) GB1276886A (enrdf_load_stackoverflow)
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US4284142A (en) * 1979-05-07 1981-08-18 Armco Inc. Method and apparatus for remote installation and servicing of underwater well apparatus
US4340204A (en) * 1976-02-06 1982-07-20 Smith International, Inc. High pressure gate valve with preloaded, stacked, solid lubricated stem seals
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US4408783A (en) * 1980-12-22 1983-10-11 Smith International Inc. Holddown apparatus
US4411317A (en) * 1981-11-02 1983-10-25 Cameron Iron Works, Inc. Flowline connector
US4416472A (en) * 1980-12-22 1983-11-22 Smith International, Inc. Holddown and packoff apparatus
US4499950A (en) * 1983-05-27 1985-02-19 Hughes Tool Company Wellhead stabilization
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US5515917A (en) * 1994-10-12 1996-05-14 Dril-Quip, Inc. Well apparatus
USRE37538E1 (en) 1992-11-12 2002-02-05 Hydril Company Ram type blowout preventer
US20070261857A1 (en) * 2006-04-25 2007-11-15 Canrig Drilling Technology Ltd. Tubular running tool
US20080164693A1 (en) * 2007-01-04 2008-07-10 Canrig Drilling Technology Ltd. Tubular handling device
US20090321064A1 (en) * 2008-06-26 2009-12-31 Nabors Global Holdings Ltd. Tubular handling device
US20110147010A1 (en) * 2008-06-26 2011-06-23 Canrig Drilling Technology Ltd. Tubular handling device and methods
US20120102684A1 (en) * 2009-11-20 2012-05-03 Hamblin Andrew Simon Stabplate connections

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FR2299492A1 (fr) * 1975-01-31 1976-08-27 Erap Dispo
GB2200154B (en) * 1987-01-08 1990-12-05 Seaboard Lloyd Seal energising device
DE69102130T2 (de) * 1991-01-17 1994-09-01 Cooper Ind Inc Metallsteckdichtung mit unterstützter Lippe niedriger Interferenz.
CN110552651B (zh) * 2018-06-04 2024-06-11 上海霞为石油设备技术服务有限公司 一种新型深水井口设备

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US3688841A (en) * 1971-03-15 1972-09-05 Vetco Offshore Ind Inc Orienting tubing hanger apparatus
US4046405A (en) * 1972-05-15 1977-09-06 Mcevoy Oilfield Equipment Co. Run-in and tie back apparatus
US4093030A (en) * 1972-05-15 1978-06-06 Mcevoy Oilfield Equipment Company Run-in and tie back apparatus
US3809158A (en) * 1972-07-27 1974-05-07 Rockwell International Corp Well completion apparatus and method
DE2510174A1 (de) * 1974-03-11 1975-10-02 Putch Vorrichtung zur dichtung und verriegelung zwischen teilen eines bohrloches
US4340204A (en) * 1976-02-06 1982-07-20 Smith International, Inc. High pressure gate valve with preloaded, stacked, solid lubricated stem seals
US4363465A (en) * 1976-06-16 1982-12-14 Smith International, Inc. Extreme temperature, high pressure balanced, rising stem gate valve with super preloaded, stacked, solid lubricated, metal-to-metal seal
US4229027A (en) * 1977-09-15 1980-10-21 Mcevoy Oilfield Equipment Company Remote automatic make-up stab-in sealing system
US4252187A (en) * 1979-05-07 1981-02-24 Armco Inc. Bearing-equipped well tool
US4284142A (en) * 1979-05-07 1981-08-18 Armco Inc. Method and apparatus for remote installation and servicing of underwater well apparatus
US4408783A (en) * 1980-12-22 1983-10-11 Smith International Inc. Holddown apparatus
US4416472A (en) * 1980-12-22 1983-11-22 Smith International, Inc. Holddown and packoff apparatus
US4411317A (en) * 1981-11-02 1983-10-25 Cameron Iron Works, Inc. Flowline connector
US4499950A (en) * 1983-05-27 1985-02-19 Hughes Tool Company Wellhead stabilization
GB2221485A (en) * 1988-07-22 1990-02-07 Cooper Ind Inc Rotatable sealing assemblies.
GB2221485B (en) * 1988-07-22 1992-04-08 Cooper Ind Inc Rotatable sealing assemblies
USRE37538E1 (en) 1992-11-12 2002-02-05 Hydril Company Ram type blowout preventer
US5515917A (en) * 1994-10-12 1996-05-14 Dril-Quip, Inc. Well apparatus
US20070261857A1 (en) * 2006-04-25 2007-11-15 Canrig Drilling Technology Ltd. Tubular running tool
US7445050B2 (en) 2006-04-25 2008-11-04 Canrig Drilling Technology Ltd. Tubular running tool
US20080164693A1 (en) * 2007-01-04 2008-07-10 Canrig Drilling Technology Ltd. Tubular handling device
US7552764B2 (en) 2007-01-04 2009-06-30 Nabors Global Holdings, Ltd. Tubular handling device
US8074711B2 (en) 2008-06-26 2011-12-13 Canrig Drilling Technology Ltd. Tubular handling device and methods
US20110147010A1 (en) * 2008-06-26 2011-06-23 Canrig Drilling Technology Ltd. Tubular handling device and methods
US20090321064A1 (en) * 2008-06-26 2009-12-31 Nabors Global Holdings Ltd. Tubular handling device
US8720541B2 (en) 2008-06-26 2014-05-13 Canrig Drilling Technology Ltd. Tubular handling device and methods
US8851164B2 (en) 2008-06-26 2014-10-07 Canrig Drilling Technology Ltd. Tubular handling device and methods
US9303472B2 (en) 2008-06-26 2016-04-05 Canrig Drilling Technology Ltd. Tubular handling methods
US9903168B2 (en) 2008-06-26 2018-02-27 First Subsea Limited Tubular handling methods
US10309167B2 (en) 2008-06-26 2019-06-04 Nabors Drilling Technologies Usa, Inc. Tubular handling device and methods
US20120102684A1 (en) * 2009-11-20 2012-05-03 Hamblin Andrew Simon Stabplate connections
US8550168B2 (en) * 2009-11-20 2013-10-08 Vetco Gray Controls Limited Stabplate connections

Also Published As

Publication number Publication date
NL6918802A (enrdf_load_stackoverflow) 1970-06-18
DE1962443A1 (de) 1970-08-27
FR2026197A1 (enrdf_load_stackoverflow) 1970-09-18
GB1276886A (en) 1972-06-07
DE1962443C3 (de) 1980-03-27
DE1962443B2 (de) 1979-07-26

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