US 3540533 A
Description (OCR text may contain errors)
United States Patent  Inventor Charles D. Morrill Bellalre, Texas [21 Appl. No. 783,943
 Filed Dec. 16, 1968 Nov. 1 7, l 970 Rockwell Manufacturing Company Houston, Texas a corporation of Pennsylvania  Patented  Assignee  REMOTE PACKOFF METHOD AND APPARATUS Primary ExaminerJames A. Leppink AItorneysBill B. Berryhill, Murray Robinson, Ned L.
Conley, James A. Bargfrede and Robert W. B. Dickerson ABSTRACT: A packoff assembly foran underwater wellhead and a method of remotely completing a well with the packoff assembly. 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. To install the packoff in a wellhead it is lowered on a tool into an annular space between the wellhead and a casing and hanger assembly supported thereby. 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.
Patented Nov. 17, 1970 3,540,533
Sheet 1 of5 Char/e: fl. Mar/v 0 INVENTOR.
J0 BY P ltented Nov. 17, 1970 i I I I I I I I I I I I ulll lll Ill (bar/e: .0. Mar/'1 I I NVENT OR.
A77 ENE) Sheet (bar/e: .0. Mar/v INVENTOR.
Patented Nov. 17, 1970 3,540,533
Sheet 5 of5 I NVENT OR.
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.
2. Description of the Prior Art Offshore drilling and completion of oil and gas wells has become common in the past few years. Various methods and apparatus have been developed to solve the unique problems inherent in these underwater wells. Some of the methods utilize a permanent platform with more or less ordinary type completion apparatus at the platform. Other more recently developed methods use mudline suspension apparatus with tubing extensions to the surface where a christmas tree is installed on a permanent platform. In this manner most of the casing and tubing strings are supported at the mudline so that a less expensive platform is required. Still others permit drilling and control equipment to be placed at the surface until the well is brought in, then installation of an underwater christmas tree at the mudline so that no permanent platform is required. This method usually employs a jack-up type drilling platform which is relatively stable during drilling operations.
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.
SUMMARY OF THE INVENTION 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.
BRIEF DESCRIPTION OF DRAWINGS Other objects and advantages of the invention will becomeapparent from the description which follows when taken in conjunction with the drawings in which:
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 Referring first to Figure I. a wellhead installation for a 30"-20-l3%"9%"-7" casing program and a dualtubing string is shown. Of course. other casing and tubing stringprograms may be employed with the present invention. this particular program being used for illustration purposes only.
First. a 30 inch conductor casing I0 and attached casing head 11 are normally driven or jetted into place at the floor or mudline l of a body of water. Conductor CasinglO may be run in a drilled hole if bottom conditions require it.
Next. 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. A plurality of longitudinal ribmembersSZ-S. welded to surface casing 20, centralize surface casing '20 as it is lowered into position. Conductor casing head 11 isprovided with'ports 13 through its walls to allow exit of excess cement returns when casing20 is cemented inplace.
The interior of 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.
After surface casing 20 is set, a hole is drilled for 13% inch casing 30. Casing 30 is run in place, landed and cemented with a relatively long tubular wellhead-member 31 attached to its upper end. On theexterior of wellhead member 31 are a 'plurality of support lugs 32 which rest on hub support shoulder 24. A plurality of latch members '33 engagegroove. 25 asra holddown device. Passageways 34 provide a path for cement returns from the annular space surrounding casing '30. The major length of the interior of wellhead member 31 is of a continuous uniform bore interrupted only by a plurality of annular latch grooves 35. 36 and 37. the-purpose of which will'be more fully understood subsequently. At its lower interior the bore is reduced to provide upwardly facing support shoulder 38. At the upper end of wellhead member'Sl is a flanged portion"39.
After conductor 30 and wellhead3l are set. 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. Several remote connectors are now commercially available. The remainder of the drilling may be completed through the 13% inch blowout preventer. without removing it until the well is ready for its christmas tree to be installed.
Next a hold is drilled for 9% inch casing 50. Casing 50 with casing hanger 51 attached to its upper end is run in place,
landed on wellhead support shoulder 38, and cemented in. Hanger 51 is provided with a support ring 52 through which passages 53 are formed for cement returns. As an option, 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. After casing 50 has been set, lower annular packoff assembly 60 is lowered into place on a setting tool around casing hanger 51 and latched into wellhead groove 35. A detailed description of the packoff assembly and its installation will follow later.
Following the setting of packoff assembly 60 a hole is drilled for 7 inch casing 70, the casing 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.
Next, 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.
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.
After tubing 90 is run and its handling string removed, 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.
At this point several alternatives are available. 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.
1f the well is immediately completed, after plugging the tubing, the blowout preventer is uncoupled from wellhead flange 39 and an underwater christmas tree (not shown) attached to remote connector 40 is lowered'into place and coupled to wellhead flange 39. Tubing run extensions 104, 105 attached to the christmas tree make up with tubing hanger 91. A centralizer 106, welded to one of the extensions 105, helps guide the christmas tree and extensions 104, 105 into place.
Occasionally, casing may become stuck in a well hole before its hanger reaches its position of support. FIG. 2 illustrates apparatus used in such a situation. Instead of the regular hangers 51 and 71 of FIG. 1, slip type hangers 59 and 79 would be used to support casing 50 and 70 should they become stuck.
The use of slip type hangers 59 and 79 require a slight alteration of packoff assemblies. Lower packoff assembly 69 and intermediate packoff assembly 89 will still be essentially the same as normally used packoffs 60 and 80 of FIG. 1. The
only difference would be in the lower seal carrying portion. A wider seal would be required to bridgethe gap between their respective casing ends and wellhead 31. Installation of packoffs 69 and 89 would be identical to packoffs 60 and 80.
Referring now'to FIG. 3. a packoff assembly according to a preferred embodiment of the invention will be described in detail. 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. On the larger external cylindrical surface of locking sleeve 210 a plurality of L- slots 219 are machined at regular intervals. The L-slots have longitudinal leg portions 219,, and circumferential foot portions 2l9,,.
There are a plurality of 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.
As previously mentioned, 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. Likewise, 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.
When seals 260 and 270 are placed on limit ring 280 and connected therewith to energizer ring 250, seal energizing ridges 256, 257, 283 and 284 engage seals 260 and 270 in the annular spaces 274, 264, 27-5 and 265, respectively. When 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. However, if limit ring 280 is forced upwardly relative to energizer ring 250 the cooperation of energizer ridges 256, 257, 283 and 284 force the lips of seal flange portions 261, 262, 271 and 272 into sealing engagement with cylindrical portion 281 and the inner and outer confines of an annular space in which the packoff assembly may be installed.
Referring now to 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. 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. Mounted around the lower end of body 180 and retained thereon by lip seal retainer 195.is annular lip seal which is sized to sealingly engage the interior wall of easing hanger I15. Different size lip seal 190 may be used for different size hangers.
In the running position of FIG. 4. the packoff assembly is supported on tool pins 163 at the extreme upper corner of the foot portion 249,, of compression sleeve L-slots 249. Locking sleeve 210 is held at its uppermost position by the engagement of support screws 235 at the extreme toe end of the foot portion 219,, of stop ring L-slots 219. Latches 220 are in a retracted position as shown. These relative positions are held against accidental displacement by small shear pins (not shown) through latch retainer ring 230 and locking sleeve 210 and by shear pin 173 placed through holes 174 around the edge of flange member 164 and engaging holes 218 in the upper face of locking sleeve 210.
As the tool 150 and packoff assembly are lowered into wellhead 110 on running string 152, 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. In this movement 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. At this point 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,
through its cooperating threaded engagement 236, 241 with latch retainerring 230 and ball bearings 243 to transmit a compression force from energizer ring 250 to seal rings 260 and 270 until they sealingly engage wellhead 112 and hanger 115 as shown in FIG. 5.
After compressing the seals 260 and 270 by a predetermined amount, 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.
At this point 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,,. However, if for some reason the packoff assembly need be removed, such is easily accomplished. 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. Thus, a simple method and apparatus for completing a well in deep water without the assistance of divers has been described herein. 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.
Various embodiments of the invention are shown in the drawing and described in the specification, but many variations thereof will be apparent to those skilled in the art. It is not practical to show or describe all the variations included within the invention, and therefore the embodiments described should be considered illustrative only, and not limiting, the scope of the invention being as broad as is defined by the appended claims. The form of the claims and the specification, including the Abstract, is adopted solely for easier reading and understanding, and should not be considered in interpreting the scope ofthe invention claimed.
l. 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.
2. A packoff assembly as set forth in claim 1, characterized by limit means engageable with said energizer means to limit said longitudinal movement thereof.
3. A packoff assembly as set forth in claim 1, characterized in that said seal carrying means comprises antirotation means engaging cooperating antirotation means in said annular space to prevent the rotation of said annular seal means relative to said wellhead.
4. 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.
5. 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.
6. Apparatus as set forth in claim 5. characterized in that said tubular means is provided with stop means to restrict downward movement of said seal means. said seal means comprising a resilient annular seal mounted between an upper member and a lower member of said seal means for compression thereof on longitudinal movement of said upper member relative to said lower member.
7. Apparatus as set forth in claim 6, characterized in that said upper and lower members are provided with limit means to limit compression of said resilient annular seal.
8. Apparatus as set forth in claim 6, characterized in that 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.
9. Apparatus as set forth in claim 5, characterized in that 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.
10. Apparatus as set forth in claim 5, characterized in that said locking means is positionable behind said latch members only after partial rotation thereof relative to saitl retainer means.
11. Apparatus as set forth in claim 5, characterized in that cooperative antirotation means is provided on said seal means and said latching means so that on rotation of said compression means said latching means and at least a portion of said seal means are longitudinally displaced from one another without rotation relative to each other.
12. Apparatus as set forth in claim 11, characterized in that said 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.
13. Apparatus as set forth in claim 5, characterized by second tubular means disposed in said wellhead leaving a second annularspace therebetween and a second packoff assembly sealingly engaging said second annular space to prevent fluid flow therethrough.
14. Apparatus as set forth in claim 13, characterized in that the inside and outside dimensions of said second packoff assembly are substantially identical to the outside dimensions of said packoff assembly.
15. 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.
16. 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 and said retainer means preventing rotation of said retainer means also.
17. A packoff assembly as set forth in claim 15, characterized in that said seal carrying means comprises two telescopically engageable members between which said resilient seal means is mounted.
18. 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.
19. 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.
20. A method ot'installing a packoff assembly as set forth in claim 19 wherein said latching is accomplished by rotation and longitudinal movement of a portion of said packoff assembly.
ll) 21. A method of installing a packoff assembly as set forth in claim 19 wherein said rotating portion of said packoff assembly causes said portion to travel longitudinally by said thread means without rotating said annular seal meansv 22. A method of installing a packoff assembly as set forth in claim 19, comprising the additional step of: unlatching said assembly from said wellhead without rotation of any portion of said packoff assembly thereby allowing said seal means to return to its uncompressed state and allowing removal of said assembly.
23. 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.
24. 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.
25. 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.
26. 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.
27. 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.
28. 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.
29. 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.