US3295600A - Underwater production method - Google Patents

Underwater production method Download PDF

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Publication number
US3295600A
US3295600A US501057A US50105765A US3295600A US 3295600 A US3295600 A US 3295600A US 501057 A US501057 A US 501057A US 50105765 A US50105765 A US 50105765A US 3295600 A US3295600 A US 3295600A
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United States
Prior art keywords
tubing
tubing hanger
mandrel
head
hanger mandrel
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Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Expired - Lifetime
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US501057A
Inventor
Cicero C Brown
Jr Charles E Wakefield
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Richfield Oil Corp
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Richfield Oil Corp
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Publication date
Priority to US310203A priority Critical patent/US3305015A/en
Priority to NL6410937A priority patent/NL6410937A/xx
Priority to GB38365/64A priority patent/GB1082825A/en
Application filed by Richfield Oil Corp filed Critical Richfield Oil Corp
Priority to US501057A priority patent/US3295600A/en
Application granted granted Critical
Publication of US3295600A publication Critical patent/US3295600A/en
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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

Definitions

  • the present application is a divisional application of Serial No. 310,203 filed September 20, 1963, and relates to the underwater production of oil and gas. More particularly, the present invention relates to an improved method for installing underwater production head apparatus remotely at an underwater location.
  • the packing elements employed are of the packer cup type, they are not set for sealed annulus until fluid pressure is exerted thereon.
  • the automatic latching type tubing hanger is designed to be locked to the tubing head by well zone pressure but is not positively mechanically locked until such time as a head plug can be set in the tubing head above the tubing hanger mandrel. Prior to the setting of the head plug, it is possible that the tubing hanger may not be properly actuated by zone pressure, in which case the tubing could be blown out by the hole. At present, there is no method of determining whether the tubing hanger is locked down in such devices since the tubing hanger seating area is inside the production head.
  • a tubing hanger mandrel is mechanically locked against vertical movement relative to the tubing head with transversely movable dogs which lock into a shouldered groove in the tubing head, and packing elements are positively set to seal between the tubing hanger mandrel and the tubing head.
  • An orientation cam is not necessary with the pres- 3,295,600 Patented Jan. 3, 1967 ICC cut remotely installed production head apparatus, since there is an annular space in the tubing hanger mandrel adjacent each side outlet in the mandrel, which outlets are adjacent the corresponding side outlets of the tubing head.
  • FIG. 1 shows in cross-sectional view an assembled well head in accordance with the present invention.
  • FIG. 2 shows in cross section the tool used to retrieve the tubing hanger shown in FIG. 4.
  • FIG. 3 shows in partial cross section the tubing hanger setting tool utilized to lock down the tubing hanger and set the packers shown in FIG. 4.
  • FIG. 3a shows an enlarged view of a J slot safety de- I vice used on the casing hanger setting tool.
  • FIG. 4 shows in partial cross-sectional elevation the tubing hanger mandrel within the tubing head.
  • FIG. 5 shows the tubing hanger mandrel of FIG. 4 locked relative to the tubing head.
  • FIG. 6 shows the tubing hanger mandrel of FIG. 4 with the packing elements in set position.
  • FIG. I a production head is shown in FIG. I mounted on the ocean floor on a conventional landing base 9.
  • the production head consists essentially of a casing head 61 and a tubing head 17
  • the casing 60 is run and set in the casing head, after which the tubing hanger mandrel 11 is run, mechanically locked in position, and the packers thereafter hydraulically set with a tool 96 designed for this purpose and shown in FIG. 3.
  • the tubing hanger setting tool 96 is inserted into the tubing hanger mandrel 11 on a drill pipe (not shown) and connected thereto by turning the setting tool to the left with the drill pipe so that the sliding nut 10 engages the tubing hanger mandrel at threaded section 12.
  • Pin 19 prevents downward movement of the hammer 13 of the setting tool shown in FIG. 3.
  • the drill pipe must be rotated approximately one-eighth turn to the left, as shown in phantom line in FIG. 3A, to move the J slot in a position to permit downward movement of hammer 18.
  • a pressure fluid is then passed down the drill pipe (not shown) and through the hole 36 of the setting tool 96, hole 37 of the tubing hanger mandrel 11, and into the chamber 38 of the tubing hanger mandrel.
  • the pressure exerted by this fluid forces the cylinder 39 downward towards the shoulder 16 thus hydraulically compressing packers 42, 44, and 46, as shown in FIG. 6.
  • the hydraulic fluid used to hydraulically set the tubing hanger packcm is trapped in the setting tool 96 by inserting plug 98 therein.
  • extrude means that the packer or sealing element, e.g. packers 42, 44, and 46, is mechanically compressed to form a fiuid-tight seal between two members, e.g. the tubing hanger mandrel and the tubing or production head.
  • Slips 41 prevent return of the cylinder 39 and mandrel 11 relative to the mandrel body 29 when the hydraulic pressure on cylinder 39 is released, thus maintaining the packers in set position.
  • the slips permit the packers to be compressed between the shoulders 33 and 16 of the tubing head.
  • the drill pipe (not shown) may be rotated to the right to release the setting tool 96 from the tubing hanger mandrel 17 after which the drill pipe and the setting tool may be pulled from the hole.
  • sufiicient space is provided between the spacer rings 43 and 45 and the production mandrel 17 at the openings in the tubing hanger mandrel to obviate the need for registering adjacent openings of the two mandrels, as with an orientation cam.
  • Alignment pins 102 prevent rotation of the spacer rings 43 and 45.
  • the tubing hanger can be removed from the production mandrel by running the retrieving tool 50 shown in FIG. 2 into the tubing hanger mandrel and threadably engaging the top sub 52 of the tool with the tubing hanger mandrel top sub 22 at threaded portion 56 by turning the drill pipe to the right.
  • a spline connection between sleeve 24 and top cap 31 prevents rotation of sleeve 24 as the releasing tool is threaded into top sub 22.
  • a stinger portion 54 may be coupled to the retrieving tool 50 when it is desired to pack olf the side outlets of the tubing hanger mandrel when it is above the blowout preventers as it is being pulled.
  • the drill pipe is then pulled upward so that sleeve 24 is pulled from behind dogs 32 allowing them to retract into the position shown in FIG. 4, after which the entire tubing hanger may then be pulled from the production mandrel 17 on the drill pipe.
  • a macaroni string 106 and macaroni hanger 108 (FIG.
  • tubing hanger mandrel is landed within the production mandrel. top of the macaroni string and has a check valve therein through which fluid may be pumped to kill the well.
  • a method for completing a well in a formation underlying a body of Water from a structure over said well comprising:
  • a macaroni hanger plug 112 closes off the r

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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)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)

Description

Jan. 3, 1967 Original Filed Sept.
C. C. BROWN ET AL UNDERWATER PRODUCTION METHOD 3 Sheets-Sheet 1 Q WW M Jan. 3, 1967 c. 0. BROWN ET UNDERWATER PRODUCTION METHOD Original Filed Sept. 20, 1963 5 Sheets-Sheet 2 Jan. 3, 1967 Original Filed Sept. 20, 1963 c. c. BROWN ET UNDERWATER PRODUCTION METHOD 3 Sheets-Sheet 3 MM (2.1m;
United States Patent 2 Claims. (Cl. 166.5)
The present application is a divisional application of Serial No. 310,203 filed September 20, 1963, and relates to the underwater production of oil and gas. More particularly, the present invention relates to an improved method for installing underwater production head apparatus remotely at an underwater location.
Underwater well heads heretofore known which may be remotely installed on the ocean floor, have been installed by first running the casing and thereafter hanging the tubing inside a tubing head on a donut type hanger with several packing elements separating the various annuli. When the packing elements employed are of the packer cup type, they are not set for sealed annulus until fluid pressure is exerted thereon.
The automatic latching type tubing hanger is designed to be locked to the tubing head by well zone pressure but is not positively mechanically locked until such time as a head plug can be set in the tubing head above the tubing hanger mandrel. Prior to the setting of the head plug, it is possible that the tubing hanger may not be properly actuated by zone pressure, in which case the tubing could be blown out by the hole. At present, there is no method of determining whether the tubing hanger is locked down in such devices since the tubing hanger seating area is inside the production head.
In addition, some prior proposals for underwater production heads such as that described in copending application of C. E. Wakefield, Ir., Serial No. 100,411 filed April 3, 1961, require registry with an orientation cam to register the annulus openings in the tubing hanger mandrel with the corresponding annulus openings in the tubing head.
It is therefore an object of our present invention to provide an underwater production system wherein movement of the tubing hanger mandrel relative to the tubing head is prevented in either direction when the tubing hanger mandrel is landed therein.
It is also an object of our present invention to provide an underwater production system wherein the openings of the tubing hanger mandrel communicate with the side openings of the tubing head without the use of an orientation cam.
It is a further object of our present invention to provide a tubing hanger system wherein the tubing is mechanically locked against vertical movement within the tubing head independent of the well zone pressure.
It is also an object of our present invention to provide a tubing hanger system wherein the packing elements are positively set independent of the fluid pressure exerted thereon.
Other objects and a more complete understanding of our present invention may be had by reference to the following specification taken in conjunction with the appended claims and the drawings.
According to the teaching of the present invention, a tubing hanger mandrel is mechanically locked against vertical movement relative to the tubing head with transversely movable dogs which lock into a shouldered groove in the tubing head, and packing elements are positively set to seal between the tubing hanger mandrel and the tubing head. An orientation cam is not necessary with the pres- 3,295,600 Patented Jan. 3, 1967 ICC cut remotely installed production head apparatus, since there is an annular space in the tubing hanger mandrel adjacent each side outlet in the mandrel, which outlets are adjacent the corresponding side outlets of the tubing head.
In the drawings:
FIG. 1 shows in cross-sectional view an assembled well head in accordance with the present invention.
FIG. 2 shows in cross section the tool used to retrieve the tubing hanger shown in FIG. 4.
FIG. 3 shows in partial cross section the tubing hanger setting tool utilized to lock down the tubing hanger and set the packers shown in FIG. 4.
FIG. 3a shows an enlarged view of a J slot safety de- I vice used on the casing hanger setting tool.
FIG. 4 shows in partial cross-sectional elevation the tubing hanger mandrel within the tubing head.
FIG. 5 shows the tubing hanger mandrel of FIG. 4 locked relative to the tubing head.
FIG. 6 shows the tubing hanger mandrel of FIG. 4 with the packing elements in set position.
With reference to the drawings, a production head is shown in FIG. I mounted on the ocean floor on a conventional landing base 9. The production head consists essentially of a casing head 61 and a tubing head 17 The casing 60 is run and set in the casing head, after which the tubing hanger mandrel 11 is run, mechanically locked in position, and the packers thereafter hydraulically set with a tool 96 designed for this purpose and shown in FIG. 3.
Preparatory to landing the tubing hanger mandrel 11 in the tubing head 17, as shown in FIG. 4, the tubing hanger setting tool 96, shown in FIG. 3, is inserted into the tubing hanger mandrel 11 on a drill pipe (not shown) and connected thereto by turning the setting tool to the left with the drill pipe so that the sliding nut 10 engages the tubing hanger mandrel at threaded section 12.
The tubing hanger mandrel 11, with production tubing 13 threaded to the lower end thereof, is lowered into the production head 17 until the shoulder 14 in the tubing hanger mandrel lands on the shoulder 16 of the production mandrel 17, as shown in FIG. 1. A J slot 15, shown in FIG. 3a, is provided on the setting tool as a safety device to prevent unintentional shearing of the shear pin 30. Pin 19 prevents downward movement of the hammer 13 of the setting tool shown in FIG. 3. Thus, the drill pipe must be rotated approximately one-eighth turn to the left, as shown in phantom line in FIG. 3A, to move the J slot in a position to permit downward movement of hammer 18.
Hammer 18 abuts the shoulder 20 of the top sub 22 of the tubing hanger mandrel 11 to drive the top sub 22 and sleeve 24 downward until the lower shoulder 26 of the top sub abuts shoulder 28 of the mandrel body 29. As the sleeve 24 is driven down around the mandrel 11, pin 30 shears and the latching dog 32 is driven outward by sleeve 24 into window 34 (the position shown in FIG. 5) where it locks'in circumferentially spaced slots 35 of the production mandrel 17. Thus, the tubing hanger is positively locked into position.
A pressure fluid is then passed down the drill pipe (not shown) and through the hole 36 of the setting tool 96, hole 37 of the tubing hanger mandrel 11, and into the chamber 38 of the tubing hanger mandrel. The pressure exerted by this fluid forces the cylinder 39 downward towards the shoulder 16 thus hydraulically compressing packers 42, 44, and 46, as shown in FIG. 6. The hydraulic fluid used to hydraulically set the tubing hanger packcm is trapped in the setting tool 96 by inserting plug 98 therein. As the cylinder 39 moves downward towards 16, the pin 48 shears and seal mandrels 42a, 44a, 46a and the entire tubing hanger mandrel assembly from cylinder 39 to nipple 40, along with spacer rings 43 and 45, are moved downwardly against the shoulder 16 of the tubing head 17, thus extruding packer rubbers 42, 44, and 46 as the lower shoulder 14 engages shoulder 16 of the tubing head to form seals with the inner surface of the tubing head 17 around the side outlets 114 and 116 of the tubing hanger mandrel and the tubing head, respectively. The term extrude as used herein means that the packer or sealing element, e.g. packers 42, 44, and 46, is mechanically compressed to form a fiuid-tight seal between two members, e.g. the tubing hanger mandrel and the tubing or production head.
Slips 41 prevent return of the cylinder 39 and mandrel 11 relative to the mandrel body 29 when the hydraulic pressure on cylinder 39 is released, thus maintaining the packers in set position. The slips permit the packers to be compressed between the shoulders 33 and 16 of the tubing head.
When the packers are set, the drill pipe (not shown) may be rotated to the right to release the setting tool 96 from the tubing hanger mandrel 17 after which the drill pipe and the setting tool may be pulled from the hole.
Due to the gaps 100 between the seal mandrels 42a, 44a, and 46a, sufiicient space is provided between the spacer rings 43 and 45 and the production mandrel 17 at the openings in the tubing hanger mandrel to obviate the need for registering adjacent openings of the two mandrels, as with an orientation cam. Alignment pins 102 prevent rotation of the spacer rings 43 and 45.
The tubing hanger can be removed from the production mandrel by running the retrieving tool 50 shown in FIG. 2 into the tubing hanger mandrel and threadably engaging the top sub 52 of the tool with the tubing hanger mandrel top sub 22 at threaded portion 56 by turning the drill pipe to the right. A spline connection between sleeve 24 and top cap 31 prevents rotation of sleeve 24 as the releasing tool is threaded into top sub 22. A stinger portion 54 may be coupled to the retrieving tool 50 when it is desired to pack olf the side outlets of the tubing hanger mandrel when it is above the blowout preventers as it is being pulled. The drill pipe is then pulled upward so that sleeve 24 is pulled from behind dogs 32 allowing them to retract into the position shown in FIG. 4, after which the entire tubing hanger may then be pulled from the production mandrel 17 on the drill pipe.
A macaroni string 106 and macaroni hanger 108 (FIG.
1) may be landed'and locked in the tubing hanger man-1 drel on shoulder 104 in a manner similar to that which;
the tubing hanger mandrel is landed within the production mandrel. top of the macaroni string and has a check valve therein through which fluid may be pumped to kill the well.
Although our invention has been described with a certain degree of particularity, the scope of our invention is not limited to the details set forth, but is of the full breadth of the appended claims.
We claim:
1. A method for completing a well in a formation underlying a body of Water from a structure over said well, the steps comprising:
installing a tubing head in said well adjacent said formation, installing production tubing on a tubing hanger mandrel at said structure,
lowering said tubing and tubing hanger mandrel from said structure into said well, landing said tubing hanger mandrel on a shoulder in said tubing head,
mechanically locking said tubing hanger mandrel in a recess in said tubing head, and
extruding packing in the annulus between said tubing said annulus with said packing about a transversely disposed tubing flow passage extending through a side out-.
let of said tubing hanger mandrel and an adjacent side outlet in said tubing head.
References Cited by the Examiner UNITED STATES PATENTS 2,475,429 7/1949 Humason 166-88 2,504,025 4/1950 Humason 166-88 3,143,172 8/1964 Wakefield 166-.5 3,177,942 4/ 1965 Haeber 166-.5
JACOB L. NACKENOFF, Primary Examiner.
CHARLES E. OCONNELL, Examiner.
I. A. LEPPINK, Assistant Examiner.
A macaroni hanger plug 112 closes off the r

Claims (1)

1. A METHOD FOR COMPLETING A WELL IN A FORMATION UNDERLYING A BODY OF WATER FROM A STRUCTURE OVER SAID WELL, THE STEPS COMPRISING: INSTALLING A TUBING HEAD IN SAID WELL ADJACENT SAID FORMATION, INSTALLING PRODUCTION TUBING ON A TUBING HANGER MANDREL AT SAID STRUCTURE, LOWERING SAID TUBING AND TUBING HANGER MANDREL FROM LANDING SAID TUBING HANGER MANDREL ON A SHOULDER IN LANDING SAID TUBING HANGER MANDREL ON A SHOULDER IN SAID TUBING HEAD, MECHANICALLY LOCKING SAID TUBING HANGER MANDREL IN A RECESS IN SAID TUBING HEAD, AND EXTRUDING PACKING IN THE ANNULUS BETWEEN SAID TUBING HANGER MANDREL AND SAID TUBING HEAD BY HYDRAULICALLY MOVING PISTON MEANS ASSOCIATED WITH SAID TUBING HANGER MANDREL BETWEEN SAID RECESS AND SAID SHOULDER.
US501057A 1963-09-20 1965-10-22 Underwater production method Expired - Lifetime US3295600A (en)

Priority Applications (4)

Application Number Priority Date Filing Date Title
US310203A US3305015A (en) 1963-09-20 1963-09-20 Tubing head apparatus and method
NL6410937A NL6410937A (en) 1963-09-20 1964-09-18
GB38365/64A GB1082825A (en) 1963-09-20 1964-09-21 Tubing head apparatus and method
US501057A US3295600A (en) 1963-09-20 1965-10-22 Underwater production method

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Application Number Priority Date Filing Date Title
US310203A US3305015A (en) 1963-09-20 1963-09-20 Tubing head apparatus and method
US501057A US3295600A (en) 1963-09-20 1965-10-22 Underwater production method

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US501057A Expired - Lifetime US3295600A (en) 1963-09-20 1965-10-22 Underwater production method

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Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5211228A (en) * 1992-04-13 1993-05-18 Dril-Quip, Inc. Diverter system
US5213162A (en) * 1991-02-14 1993-05-25 Societe Nationale Elf Aquitaine (Production) Submarine wellhead
WO1993024730A1 (en) * 1992-06-01 1993-12-09 Cooper Industries, Inc. Wellhead
US20040200614A1 (en) * 2003-04-09 2004-10-14 Cooper Cameron Corporation Drill-through spool body sleeve assembly

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US3357486A (en) * 1965-06-22 1967-12-12 Atlantic Richfield Co Well casing hanger
US3353596A (en) * 1965-06-30 1967-11-21 Atlantic Refining Co Tubing hanger and method of testing packing thereon
US3420308A (en) * 1967-08-16 1969-01-07 Fmc Corp Well casing hanger
CA1034488A (en) * 1975-09-10 1978-07-11 Mcevoy Oilfield Equipment Co. Seal
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

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US2475429A (en) * 1945-10-01 1949-07-05 E E Townes Wellhead
US2504025A (en) * 1945-01-25 1950-04-11 Granville A Humason Special wellhead
US3143172A (en) * 1961-10-16 1964-08-04 Richfield Oil Corp Self-aligning landing base for off-shore deep water drilling
US3177942A (en) * 1958-01-27 1965-04-13 Shell Oil Co Well head assembly with telescoping tubing

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US2188589A (en) * 1939-05-22 1940-01-30 Elwin B Hall Method for handling well casings
US2546638A (en) * 1945-10-15 1951-03-27 Edgar E Townes Jr Wellhead construction
US2598512A (en) * 1947-02-28 1952-05-27 Hugh F Cypher Method for running a liner in flowing gas wells
US3054449A (en) * 1957-11-04 1962-09-18 Otis Eng Co Well tools for submarine wells
US3090438A (en) * 1958-10-29 1963-05-21 Otis Eng Co Multiple flow conductor suspension apparatus
US3209829A (en) * 1961-05-08 1965-10-05 Shell Oil Co Wellhead assembly for under-water wells
US3154148A (en) * 1962-04-19 1964-10-27 Andrew M Peterson Pitless adapter

Patent Citations (4)

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Publication number Priority date Publication date Assignee Title
US2504025A (en) * 1945-01-25 1950-04-11 Granville A Humason Special wellhead
US2475429A (en) * 1945-10-01 1949-07-05 E E Townes Wellhead
US3177942A (en) * 1958-01-27 1965-04-13 Shell Oil Co Well head assembly with telescoping tubing
US3143172A (en) * 1961-10-16 1964-08-04 Richfield Oil Corp Self-aligning landing base for off-shore deep water drilling

Cited By (15)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5213162A (en) * 1991-02-14 1993-05-25 Societe Nationale Elf Aquitaine (Production) Submarine wellhead
US5211228A (en) * 1992-04-13 1993-05-18 Dril-Quip, Inc. Diverter system
US5544707A (en) * 1992-06-01 1996-08-13 Cooper Cameron Corporation Wellhead
US7308943B2 (en) * 1992-06-01 2007-12-18 Cameron International Corporation Well operations system
US6039119A (en) * 1992-06-01 2000-03-21 Cooper Cameron Corporation Completion system
US6547008B1 (en) 1992-06-01 2003-04-15 Cooper Cameron Corporation Well operations system
WO1993024730A1 (en) * 1992-06-01 1993-12-09 Cooper Industries, Inc. Wellhead
US20050155774A1 (en) * 1992-06-01 2005-07-21 Cooper Cameron Corporation Well operations system
US20050173122A1 (en) * 1992-06-01 2005-08-11 Cooper Cameron Corporation Well operations system
US7314085B2 (en) 1992-06-01 2008-01-01 Cameron International Corporation Well operations system
US7093660B2 (en) 1992-06-01 2006-08-22 Cooper Cameron Corporation Well operations system
US7117945B2 (en) 1992-06-01 2006-10-10 Cameron International Corporation Well operations system
US20060272823A1 (en) * 1992-06-01 2006-12-07 Cameron International Corporation Well operations system
US20040200614A1 (en) * 2003-04-09 2004-10-14 Cooper Cameron Corporation Drill-through spool body sleeve assembly
US6966381B2 (en) 2003-04-09 2005-11-22 Cooper Cameron Corporation Drill-through spool body sleeve assembly

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GB1082825A (en) 1967-09-13
US3305015A (en) 1967-02-21
NL6410937A (en) 1965-03-22

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