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Publication numberUS3457992 A
Publication typeGrant
Publication dateJul 29, 1969
Filing dateDec 14, 1966
Priority dateDec 14, 1966
Also published asDE1583825A1
Publication numberUS 3457992 A, US 3457992A, US-A-3457992, US3457992 A, US3457992A
InventorsBrown Cicero C
Original AssigneeAtlantic Richfield Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Underwater tubing head
US 3457992 A
Images(5)
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Description  (OCR text may contain errors)

5 Sheets-Sheet 1 C. C. BROWN UNDERWATER TUBING HEAD FiledDeC. 14, 1966 ma? c ian/fw INVENTOR.

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July 29, 1969 c. c. BROWN UNDERWATER TUBING HEAD 5 Sheets-Sheet 2 Filed Deo. M, 1966 July 29, 1969 Filed Deo. 14, 1966 C.CL BFDVVN UNDERWATER TUBING HEAD 5 Sheets-Sheet 5 5 Sheets-Sheet 4 July 29, 1969 c. c. BROWN UNDERWATER TUBING HEAD Filed Dec. 14, 1966 July 29, 1969 C. C. BROWN 3,457,992

UNDERWATER TUBING HEAD Filed Dec. 14, 1966 5 Sheets-Sheet 5 United States Patent O 3,457,992 UN DERWATER TUBING HEAD Cicero C. Brown, Houston, Tex., assignor to Atlantic Richlield Company, Philadelphia, Pa., a corporation of Pennsylvania Filed Dec. 14, 1966, Ser. No. 601,627 Int. Cl. E21b 33/035, 43/01, 7/12 U.S. Cl. 166-.6 9 Claims ABSTRACT F THE DISCLOSURE An offshore production head for producing petroleum is disclosed having multiple tubing hangers each hung directly in a production mandrel and positively locked therein.

This invention relates to an 'apparatus for producing petroleum from offshore well sites, and, more particularly, relates to a tubing hanger device for producing and controlling the flow of oil and gas from an underwater well with the Wellhead positioned adjacent the ocean floor.

lIn my copending application Ser. No. 468,377, iiled June 30, 1965, a tubing hanger assembly for an ocean floor completion is shown and described wherein concentric tubing strings are hung in a tubing head which is positioned on the ocean oor. The tubing strings are hung within a production mandrel with the inner string, that is, the smaller string being hung Within the outer string which itself is hung in the production mandrel. When larger tubing strings or more tubing strings are desired in this type of tubing head, the bore of the production mandrel must be correspondingly larger in order to contain the larger or additional tubing hangers.

It is an object of my present invention to provide a tubing head wherein the tubing hangers Iare each hung within the production mandrel so that larger tubing strings or additional tubing strings can be hung in a production mandrel of a given bore size.

In the apparatus of my aforementioned copending application, the tubing hangers for the -various strings of tubing hung in the production mandrel are of different sizes since they are hung one within the other. IIt is a further object of my present invention to provide a tubing hanger device wherein the tubing hangers for hanging the several tubing strings are identical so that they may be used interchangeably regardless of the size of tubing hung thereon.

Another object of my present invention is to provide a tubing hanger assembly with several identical tubing hangers each hung in a production mandrel with crossovers in the tubing hangers to adapt for tubing strings of varying diameters.

It is also an object of my present invention to provide running tools and retrieving tools for running and retrieving the tubing hangers in an offshore tubing hanger apparatus designed for hanging each of the tubing strings in the outer mandrel.

`Other objects and a more complete understanding of my present invention may be had by reference to the following specification and the appended claims when taken in conjunction with the drawings, wherein:

FIG. 1 shows, partially in section, the lowermost tubing hanger of my present apparatus run into and landed in a production mandrel on a running tool;

FIG. 2 shows, partially in section, the apparatus of FIG. 1 with the tubing hanger locked into its landed position in the production mandrel by appropriate manipulation of the running tool;

FIG. 3 shows the production mandrel with a second tubing hanger hung and locked in the production mandrel ICC above the first tubing hanger, with the running tool removed and a tubing hanger retrieving tool inserted;

FIG. 4 shows, in partial cross section, a production mandrel plug run on its running tool into the upper portion of the production mandrel above the second tubing hanger;

FIG. 5 shows the mandrel plug locked in position within the production mandrel and with the mandrel plug retrieving tool inserted therein;

FIG. 6 is a sectional View taken on line 6-6 of FIG. 3 showing the locking dogs locked in the production mandrel and held in position with a locking sleeve;

FIG. 7 shows the production mandrel with two tubing hangers and a production mandrel plug locked within the production mandrel with dogs, and a capping plug threaded into the top end of the production mandrel.

When an oifshore well has been drilled and production zones encountered, a production mandrel 10 is lrst installed on the ocean floor with or as a part of a drilling mandrel or by latching into a drilling mandrel, as shown in my copending applications Ser. Nos. 456,968 and 456,969, or by other suitable means. The largest string of tubing is hung on a lower tubing hanger 12 with an appropriate crossover 14 on a tubing hanger running tool 16 with pipe 18 from a structure or a vessel at the surface of the ocean. The running tool 16 is manipulated to force the locking dogs 20 outwardly into locking position after which the running tool is disengaged from the tubing hanger and retrieved to the vessel. A second tubing hanger 22 is then lowered into the production mandrel 10 and landed on the top of the lower or iirst tubing hanger 12, and locked into the production mandrel 10` as shown in FIG. 3, in accordance with the method used to run the first tubing hanger 12. A production mandrel plug 24 is then run into the production mandrel on Ian appropriate running tool, as shown in FIG. 4, and locked by manipulation of the running tool, after which the running tool is retrieved from the production mandrel on the pipe 18. A capping plug 28 is then run into the upper end of the production mandrel on a third running tool and threaded into the top of the production mandrel, as shown in FIG. 7, as a secondary holddown and pack-olf.

Referring now more particularly to the drawings, after the production mandrel 10 is secured at the underwater well site, as by running on a special running tool which screws into the top of the production mandrel, and landing and locking the production mandrel into or onto the drilling mandrel (not shown) by rotation of the pipe 18 from the vessel, as taught in my aforementioned copending applications, the blowout preventers and the riser (not shown) are reattached to the top of the production mandrel on the latching neck 30 which is best shown in FIGS. 4 and 7. At this point it may be desirable to perforate the well, remove bridge plugs, or perform other work downhole before the tubing is run.

The largest string of tubing is then threaded onto the crossover 14 on threads 34 and the crossover 14 threaded into the flrst or lowermost tubing hanger 12. The tubing hanger running tool 16 at threads 36 is then threaded onto the threaded portion 37 of the upper end of the tubing hanger, at the vessel, and lowered with the hanger 12 into the production mandrel 10 on pipe 18. The tubing hanger is landed on the shoulder 38 of the production mandrel as the landing ring 40 of the tubing hanger seats on shoulder 38. The tubing hanger running tool 16 is threaded to the tubing hanger on a running sleeve 60' which is slidably connected to the body 16 of the running tool with a I -slot connection consisting of a pin 44 on the tool body and J-slot 46 in the running sleeve.

When the tubing hanger is landed on the shoulder 38 of the production mandrel, the drill pipe is turned to the left to move the pin 44 into the vertical portion of the I-slot and the tool slacked off (weighted down) so that the locking sleeve 48 of the tubing hanger is driven down and drives the locking dogs 20 outwardly into the groove 50 of the production mandrel as the tool body 16 is stroked downwardly. A drive ring 56 on the running tool engages the surface 58 at tlte top of the locking sleeve 48 of the running tool to drive the dogs 20 outwardly into the groove in the production mandrel.

Accidental downward movement of the locking sleeve 48 is prevented by attachingy the sleeve to tubing hanger 12 with shear pins 49 which are sheared when the locking sleeve is driven downward by drive ring 56, as intended. Accidental upward movement of the locking sleeve 48 is prevented by snap ring 148. When the tubing hanger locking sleeve 48 is in the unset position shown in FIG. 1, snap ring 148 is in groove 15() and is pushed in and downward to groove 152 by shoulder 153 as the locking sleeve 48 is driven downward to knock dogs 20 outward into locking position. As best shown in FIG. 7, there are a series of circumferentially spaced dogs 20 on each tubing hanger which lock that tubing hanger into the production mandrel. The dogs 20 are driven outwardly on taper shoulders 52 and 53 of the locking sleeve 48.

In order to remove the running tool 16 from the tubing hanger 12, the pipe 18 is rotated to the right to turn the running sleeve 60 to thereby unthread the running tool threads 36 from the threads 37 of the hanger after which the running tool is pulled out of the production mandrel 10 with drill pipe 18.

With the tubing hanger running tool 16 released and retrieved to the vessel, the second tubing hanger may be threaded into threads 36 of the running sleeve 60 of the tubing hanger running tool 16 and the second tubing hanger 22 run into the production mandrel 10 with pipe 18 and landed in production mandrel 10 by engagement of skirt 156 on the upper shoulder 62 of the rst tubing hanger, as best shown in FIG. 3. Hanger skirts 156 are affixed to the tubing hangers with set screws 158. After landing the second tubing hanger 22 on the lower tubing hanger 12, it is locked into the production mandrel 10 with locking dogs 64 by appropriate manipulation of the tubing hanger running tool, as described above with respect to the running and locking of the first tubing hanger 12.

Thus, the lower tubing hanger 12 hangs the outer string of tubing (not shown) threaded onto threads 34 of crossover 14 and isolates the two lower outlets 66 and 68 of the production mandrel from each other with packing 160. The packing is supported from below by landing ring 40 which is held on tubing hanger 12 by snap ring 162. The lower outlet 66 is the casing annulus (the annulus between the casing and the large or outer tubing) outlet and the middle production mandrel outlet 68 is the outlet for the annulus between the large tubing and the small tubing (not shown).

The top outlet 82 in the production mandrel is an outlet for the inner tubing string and provides access thereto. As shown in FIGS. 4 and 7, the mandrel plug 24 seals the production mandrel above the top outlet 82 with a Chevron-type packing 84 and forms the top closure for the inner tubing string (not shown) hung on tubing hanger 22. A double check valve 170 (FIG. 4) is provided in the lower end of the bore of the mandrel plug, to prevent fluid liow through the plug 24 in either direction but yet permit downhole pressure indication by the retrieving tool (FIG. as will be described below.

After the second tubing hanger has been locked into the production mandrel and the running tool retrieved, the running tool 26 for the mandrel plug 24, which is shown pinned to the mandrel plug with shear pins 70, is threadably connected to the pipe 18. The mandrel plug 24 is then run into the production mandrel and landed on the upper end 72 of the second tubing hanger 22, as shown in FIG. 4. Fluid trapped below the mandrel plug can escape through the plug 24 when it is lowered into the production mandrel as shown in FIG. 4, through slots 73 of Stringer 75, which is provided in the plug running tool 26 to hold the ball 170a off its seat. After the mandrel plug is landed in the production mandrel, the running tool 26 is rotated to the right and slacked off to un-J the tool by moving pins into the vertical portion of the J-slot 29 and to drive the lower end of the running tool body 74 downwardly against the top of the locking sleeve 76 of the mandrel plug to knock the dogs 78 out into the groove 80 of the production mandrel and thereby lock the mandrel plug 24 into the upper end of the production mandrel 10. Downward movement of the running tool body 74 after the tool is unjayed, also shears pin 77 so that the stinger carriage member 79, which is threaded into the running tool body, moves downward relative to the T-head 81 of the stinger 75. After the mandrel plug is locked into the production mandrel with dogs 78, the mandrel plug running tool 26 is released from the mandrel plug by pulling up on the pipe to shear pins 70 and thereby sever the connection between the running tool 26 and the mandrel plug 24.

Above the mandrel plug a capping plug 28 (FIG. 7) is threaded into the production mandrel 1() with an appropriate running tool 86 to form a secondary seal above all other seals within the production mandrel and to provide another holddo'wn for the tubing hangers and mandrel plug. The capping plug is threaded into the production mandrel by turning the tool 86 to the left until the plug is in the position shown in FIG. 7. Further rotation to the left shears pin and closes port 90 by threading the inner section 87 of the plug upwardly with respect to the outer plug member 28. The running tool 86 is released from the capping plug 28 by rotating the running tool and pulling off.

In the event that a workover is to be performed on the Well or it is desirable to do other remedial work downhole or abandon the well, it may become necessary to retrieve the capping plug, mandrel plug and the tubing hangers. It should be understood, however, that normal wire-line work may be performed through the inner tubing string by removing the capping plug and the mandrel plug. In order to retrieve the capping plug, the same capping plug running tool 86 is utilized to retrieve the capping plug by lowering the tool over the pin 88 and unthreading the capping plug from the production mandrel. By turning the tool 86 to the right, the port 92 is first opened to pressure from below by threading inner plug section 87 down with respect to the plug 28 to unseat the inner section. Further rotation to the right unthreads the plug from the production mandrel.

The mandrel plug is retrieved by running the mandrel plug retrieving tool 93 (FIG. 5) into the mandrel plug 24 so that the nose portion 96 of the plug is inserted into the lower end 94 of the mandrel plug bore. The point 172 of the mandrel plug retrieving tool unseats ball 174 of the double check valve 170 to indicate pressure below through check valve 98 in the nose of the retrieving tool. If pressure below is indicated, uid is pumped through the drill pipe down through the mandrel plug retrieving tool 93 through ports 97 to equalize the downhole pressure. Pressurized fluid pumped into the ports 97 first moves differential area valve 176 upward and continued pressure unseats ball 178 which then permits fluid to pump into the well to equalize the aforementioned downhole pressure. Seals 99 and 101 isolate the fluid pumped through ports 97 of the retrieving tool 93. After downhole pressure is equalized, shear pin 180 is sheared by slacking off on the pipe, the retrieving tool is turned to the right to un-J the retrieving tool. Relative rotary movement between the retrieving tool and the mandrel plug is prevented by frictional engagement of seals 99 and 101.

After the retrieving tool 93 is slacked off and rotated to the right, the threads of the retrieving tool outer sleeve 108 are in position for threading into the mandrel plug threads 112. After threading the retrieving tool 93 into threads 112, the tool may be lifted upwardly with the pipe and sleeve 122 lifted from `behind the dogs 78.

Continued upward movement of the sleeve 122 causes the upper shoulder 128 of the inner sleeve to contact the lower surface 132 of the bushing 130 which is threaded into the upper end of the mandrel plug, retracting the dogs 78 from the locking groove 80 of the production mandrel as they contact the taper 124 of the locking groove to effect removal of the mandrel plug assembly from the production mandrel.

The tubing hangers 12 and 22 may be retrieved by threading the tubing hanger retrieving tool 134 (FIG. 3) into the tubing hanger inner sleeve 136 with pipe 18. AS the inner sleeve 136 is lifted up with pipe threaded into the upper end of the retrieving tool, the sleeve 136 is pulled from behind the dogs 64 to unlock the upper tubing hanger 22 from the production mandrel 10. Continued upward movement of the retrieving tool 134 and the inner sleeve l136 causes the shoulder 142 thereof to contact the lower surface 144 of the bushing 146 and continued upward movement removes the tubing hanger 22 from the production mandrel. The lower tubing hanger 12 (and the outer tubing string attached thereto) may be removed from the production mandrel in a manner identical to the removal of the upper tubing hanger 22 (and the inner tubing string attached thereto). Although not shown, additional tubing hangers could be landed on top of the upper tubing hanger 22 (in a longer production mandrel) to provide additional inner tubing strings.

It is thus apparent that my present tubing hanger assembly provides a tubing head for several tubing strings each of which are locked into the production mandrel per se, thus allowing the running of larger tubing strings on concentric type hangers in a production mandrel of a given size. Also, my present invention permits the use of interchangeable tubing hangers in a multiple string tubing head.

While my present invention has been described in detail with a certain degree of particularity with reference to a single embodiment of my present invention, it is to be understood that my invention is not to be limited to the embodiment shown but should be afforded the full scope of the appended claims.

I claim:

1. An underwater tubing head apparatus for producing oil and gas from a well drilled in a formation underlying a body of water, comprising in combination:

(a) a production mandrel having a side outlet,

(b) a first tubing hanger means for hanging a tubing string on a shoulder in said production mandrel,

(c) means for positively locking said first tubing hanger means against vertical movement with respect to said production mandrel by moving a locking dog into locking position between a second shoulder of said production mandrel and a shoulder of said hanger means by remotely manipulating a locking tool from the surface of said body of water,

(d) a second tubing hanger means for hanging a second smaller tubing string within said first tubing string, said second tubing hanger means being arranged to land in said mandrel above said first tubing hanger means,

(e) means for sealing the annulus between said production mandrel and said first and second tubing hanger means above and below said outlet to provide a fiuid flow path between said first tubing string and said outlet, and

(f) means for positively remotely locking said second tubing hanger means in said production mandrel to prevent relative vertical movement between said sec- (clmc tubing hanger means and said production man- 2. The apparatus of claim 1 including means for landing said second tubing hanger means in said mandrel on top of said first tubing hanger means.

3. The apparatus of claim 1 wherein both said first tubing hanger means and said second tubing hanger means are locked into recesses in said production mandrel.

4. The apparatus of claim 1 including a production mandrel plugging means remotely lockable in said production mandrel above said second tubing hanger means to seal oi said production mandrel above said side outlet.

5. An underwater tubing head apparatus for producing oil and gas from a well drilled in a formation underlying a body of water, comprising in combination:

(a) a production mandrel having first, second, and

third side outlets longitudinally spaced in ascending order,

(b) a first tubing hanger means for hanging a tubing string on a shoulder in said production mandrel,

(c) means for positively locking said first tubing hanger means against vertical movement with respect to said production mandrel by moving the locking dog into locking position between a second shoulder of said production mandrel and a shoulder of said hanger means by remotely manipulating a locking tool from the surface of said body of Water,

(d) first means for sealing the annulus between said production mandrel and said tubing string Iabove said first side outlets to provide a fluid fiow path between said first outlet and the annulus between said first tubing string and said mandrel,

(e) a second tubing hanger means for hanging a second smaller tubing string within said first tubing string, said second tubing hanger means being arranged to land in said mandrel above said first tubing hanger means,

(f) means for sealing the annulus between said production mandrel and said second tubing hanger means above said second side outlet to provide a fluid flow path between 4said second side outlet and said first tubing string,

(g) means for positively remotely locking said second tubing hanger means in said production mandrel to prevent relative vertical movement between said tubing hanger means and said production mandrel, and

(h) means for sealing the bore of said mandrel above said third side outlet to provide a fluid flow path between sad third side outlet and said second tubing string.

6. The apparatus of claim 5 wherein said means for sealing above said third side outlet is a mandrel plug provided with a double check valve in the lower end thereof to permit pressure indication before said plug is removed from said production mandrel.

7. The apparatus of claim 5 including means for equalizing down-hole pressure before said mandrel plug is removed, said means including a fluid operated differential area valve and a check valve to prevent entry of down-hole pressure into said mandrel plug.

8. An underwater tubing head apparatus for producing oil and gas from a well drilled in a formation underlying a body of water, comprising in combination:

(a) production mandrel having first, second and third side outlets longitudinally spaced in ascending order,

(b) a first tubing hanger means for hanging a tubing string on a shoulder in said production mandrel between said first and said second side outlets,

(c) means for positively locking said first tubing hanger means against vertical movement with respect to said production mandrel by moving the locking dog into locking position between a second shoulder of said production mandrel and a sh0ul der of said hanger means by remotely manipulating a tool from the surface of said body of water,

(d) means for sealing the annulus between said first tubing hanger means and said production mandrel between said first and second side outlets,

(e) a second tubing hanger means for hanging a second tubing string between said second and third side outlets, said second tubing hanger means being landed in said production mandrel on top of said rst tubing hanger means,

(f) -means for sealing the annulus between said production mandrel and said second tubing hanger means between said second and third side outlets t0 provide a fluid flow path between said iirst tubing string and said second side outlet,

(g) means for sealing olf said mandrel above said third side outlet to provide a tluid ow path between said second tubing string and said third side outlet, and

(h) means for positively remotely locking said second tubing hanger means in a second recess in said production mandrel to prevent relative movement between said second tubing hanger means and said production mandrel.

9. The apparatus of claim 1 including means for seal- JAMES A. LEPPINK,

drel.

References Cited UNITED STATES PATENTS 3/1936 4/1966 8/1966 9/1966 ll/l966 11/1967 Penick et al. 166-89 Pierce 166-89 Bishop et al. 166-89 Bishop et al. 166-.6 Brown 166-.6 Brown 166-.6

Primary Examiner U.S. Cl. X.R.

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US2035834 *Sep 17, 1934Mar 31, 1936Penick Arthur JWellhead assembly
US3248132 *Feb 25, 1963Apr 26, 1966Gray Tool CoCombined retractable hold-down means and hanger support
US3268242 *Aug 19, 1963Aug 23, 1966Armco Steel CorpWellhead assemblies
US3273915 *Aug 19, 1963Sep 20, 1966Armco Steel CorpRemotely installed well devices and wellhead assemblies including the same
US3288493 *Feb 28, 1964Nov 29, 1966Brown Oil ToolsCoupling device for underwater wellheads
US3353596 *Jun 30, 1965Nov 21, 1967Atlantic Refining CoTubing hanger and method of testing packing thereon
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US4019580 *Jan 19, 1976Apr 26, 1977Fmc CorporationApparatus and method for running, setting and testing a compression-type well packoff
US4046405 *Jan 22, 1975Sep 6, 1977Mcevoy Oilfield Equipment Co.Run-in and tie back apparatus
US4093030 *Jan 24, 1977Jun 6, 1978Mcevoy Oilfield Equipment CompanyRun-in and tie back apparatus
US4291768 *Jan 14, 1980Sep 29, 1981W-K-M Wellhead Systems, Inc.Packing assembly for wellheads
US4421164 *Oct 29, 1981Dec 20, 1983Armco Inc.Weight-set pack-off unit
US5509476 *Mar 7, 1994Apr 23, 1996Halliburton CompanyShort wellhead plug
US5515917 *Oct 12, 1994May 14, 1996Dril-Quip, Inc.Well apparatus
US6039119 *Jul 12, 1996Mar 21, 2000Cooper Cameron CorporationCompletion system
US6547008Sep 7, 2000Apr 15, 2003Cooper Cameron CorporationWell operations system
US7093660Feb 13, 2003Aug 22, 2006Cooper Cameron CorporationWell operations system
US7308943 *Jul 25, 2006Dec 18, 2007Cameron International CorporationWell operations system
US7559364 *Sep 14, 2006Jul 14, 2009Gerald BullardBridge plug and setting tool
US7757756Mar 12, 2009Jul 20, 2010Gerald BullardBridge plug and setting tool
US20110240307 *Mar 27, 2009Oct 6, 2011Cameron International CorporationWellhead Hanger Shoulder
US20120024542 *Apr 19, 2010Feb 2, 2012Cameron International CorporationHanger floating ring and seal assembly system and method
US20120312542 *Jun 8, 2011Dec 13, 2012Vetco Gray Inc.Expandable solid load ring for casing hanger
EP0137335A2 *Sep 12, 1984Apr 17, 1985Fmc CorporationSubsea casing hanger suspension system
Classifications
U.S. Classification166/335, 166/360, 166/88.1
International ClassificationE21B33/047, E21B33/03, E21B33/043
Cooperative ClassificationE21B33/047, E21B33/043
European ClassificationE21B33/043, E21B33/047