US3656549A

US3656549A - Underwater completion system

Info

Publication number: US3656549A
Application number: US858765A
Authority: US
Inventors: Marvin L Holbert Jr; Milton T Childress
Original assignee: Gray Tool Co
Current assignee: Vetco Gray LLC
Priority date: 1969-09-17
Filing date: 1969-09-17
Publication date: 1972-04-18
Anticipated expiration: 1989-04-18

Abstract

The guide base installed as an initial step in drilling an underwater well includes an upwardly opening generally hemispherical shell. Later, during christmas tree installation or work-over operations a man-carrying chamber is lowered to mate with the shell. Sealing between the chamber and the shell is accomplished using axially spaced inflatable toric circumferential seal elements carried exteriorly of the lower end of the chamber and expansible into sealing contact with the shell.

Description

llnited States Patent Holbert, Jr. et al.

[151' 3,656,549 51 Apr. 18, 1972 dress, both of Houston, Tex.

[73] Assignee: Gray Tool Company, Houston, Tex.

[22] Filed: Sept. 17, 1969 211 Appl. No.: 858,765

[52] US. Cl ,.166/.5, 61/69 [51] Int. Cl ..E2lb 43/01 [58] Field ofSearch ..l66/.5,.6; 175/5,6, 8,9; 61/69, 46.5

[56] References Cited UNITED STATES PATENTS 2,854,215 9/1930 Cox ..166/.5 2,988,144 6/1961 Conrad ..166/.5

3,361,199 1/1968 Haeber et al. ,.l66/.5 3,408,822 11/1968 Chate et a1 ....6 l /69 3,482,410 12/1969 Roesky et a1 ..166/.5 X 3,504,740 4/1970 Manning 166/ .5 3,513,910 5/1970 Townsend ..166/.5 3,525,388 7/1970 McClintock ..61/46.5 X

Primary Examiner-Marvin A. Champion 7 Assistant Examiner-Richard E. Favreau Attorney-Cushman, Darby & Cushman [5 7] ABSTRACT The guide base installed as an initial step in drilling an underwater well includes an upwardly opening generally hemispherical shell. Later, during christmas tree installation or work-over operations a man-carrying chamber is lowered to mate with the shell. Sealing between the chamber and the shell is accomplished using axially spaced inflatable toric circumferential seal elements carried exteriorly of the lower end of 3,020,956 2/1962 sudel'ow the chamber and expansible into sealing contact with the shell. 3,202,218 8/1965 Watts 612 a1 ..166/.5 3,353,364 11/1967 Blanding et al. ..166/.5 3 Claims, 12 Drawing Figures 44 l 2 #46 H l '11 PATENTEDAPR 18 m2 3.656549 22 /vy v 56 v INVENTORS 74 F A fi azageg Jig ATTOR N E Y5 PATENTEDA R 18 m2 3, 656,549

- I NVENTORS flew/VJ 174165641 5 ATTORNEYS PATENTEDAPR 18 I972 8 656, 549

SHEET as @s' g INVENTORS Mdw/Vfdb/lpgfss MMQ ATTORNEYS PATENTEDAPRW I972 3,655,549

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ATTORNEY;

UNDERWATER COMPLETION SYSTEM BACKGROUND OF THE INVENTION In the course of drilling and completing oil and gas wells, a means of gathering and transporting production to a storage and/or delivery point is usually required.

As the drilling operation and the laying of production pipe lines (flow lines) are necessarily conducted as separate operations, the final connection between wellhead and flow line (and the storage facility, if submerged), has historically presented problems of considerable magnitude.

The normal solution has been the use of divers and seems effective where depths are not excessive, visibility good and water temperatures not unbearably low.

However, in view of recently proposed deep water drilling concepts, the use of divers and equipment considered operational and efficient at depths less than 300 feet is not desirable when considered at 300 to 1,000 feet.

In an effort to circumvent the limitation imposed by these deep water activities, attempts have been made to automate flow line connection operations so that they may be carried out remotely.

The remote equipment thus far developed is quite complex and necessarily expensive. In addition, the obvious possibility of damage and malfunction in such an inaccessible location could result in loss of production and water pollution.

Examples of remote flow line connection systems known to the present inventors are shown in the following United States patents:

Inventor Patent No. Issue Date Haeber 2,965,174 Dec. 20, I960 Knapp et al. 2,970,646 Feb. 7, I961 Geer et al. 3,052,299 Sept. 4, I962 Watkins 3,166,123 Jan. 19,1965 Geer et al. 3,233,666 Feb. 8, 1966 Shatto, .Ir. 3,299,950 Jan. 24, 1967 Shane, Jr. 3,307,627 Mar. 7, I967 Haeber et al. 3,361,199 Jan. 2,1968

Similar problems are encountered in other underwater well completion and work-over operations.

Others have proposed the use of man and equipment carrying submersible chambers for use in the completion of wells or for working upon wells. Examples of which the present inventors are aware are shown in the following United States patents.

The provision of a work chamber which includes a fixed lower portion and an upper portion which may be lowered, latched and sealed to the portion so that workers may complete the well in an air-filled, atmospheric pressure caisson is illustrated in the 1961 U.S. patent of Conrad, U.S. Pat. No. 2,988,144. In this patent, the latches provided are of the cable actuated, swinging

dog type

60, 90; the seals 63, 38 are of a noninflated, rubber type; and the flow line connection at 86 is described as being made-up using divers or other caisson equipment (not further explained), column 5, lines 36-42.

In the general context of the present invention, two axially spaced, although noninflated, seals were provided in Watts et al., U.S. Pat. Nos. 3,202,216 and 3,202,217. FIG. 11 of the fonner shows communication provided at 173 to the space between the seals for venting and plastic packing material injection. In Watts et al., U.S. Pat. No. 3,202,216 a hydraulic piston-type latch is provided at 100' in FIG. 11.

In the expired U. S. patent of Ferro, U.S. Pat. No. 2,303,831 a noninflated rubber seal is shown at 31, 32 (FIG. 2) between a base (submarine) and a chamber (escape bell).

Getting such sealing areas to slide past one another to their intended sealed relationship can be difficult because of the close tolerances involved.

Inflatable seals for connecting lowerable working chambers to guide bases or fixed chamber floor elements are shown at 31 in FIG. 2 of Suderow, U.S. Pat. No. 3,020,956 and at 439 in FIG. 18 of Blanding et al., U.S. Pat. No. 3,353,364. The Suderow patent mentions that its seals are similar to those shown in Pointer, U.S. Pat. No. 2,775,869.

, 2 SUMMARY OF THE INVENTION The present invention relates to an underwater completion system utilizing a submersible work chamber which seals with a permanent hemispherical shell at the wellhead via inflatable seals which are positively actuated and allow a large clearance to be provided between the shell and the work chamber.

When using the apparatus of the invention, personnel may perform conventional oil field operations at sub-sea" locations in an acceptable environment with respect to normal breathing and temperature conditions. This, of course, would eliminate the need for auxiliary breathing apparatus, diving suits and time consuming decompression procedures. Although the immediate use of this system is discussed in terms 0 oil field operations, this certainly is not intended to be a limitation of its use in sub-sea (including sub-aquatic) environments including use with underwater vessels, undersea resource exploration and extraction equipment, diving bells and escape devices.

Briefly, the submersible chamber carrying specialists trained in the efficient manipulation of, in this case, oil field equipment, may be lowered and attached to a permanently located receptacle. Following this, the juncture is sealed and the sea water removed from the enclosed space. This evacuated chamber, charged with a breathable gas mixture, can then be safely entered by the specialists and all manner of operations performed in an accommodating atmosphere.

It should be appreciated that when the work chamber is attached to the lower hemisphere, adequate means must be provided for sealing the juncture, to the exclusion of sea water. In addition, the seal must withstand full hydrostatic differential between the enclosed work area and the external pressure of sea water once the work area has been purged of sea water and the internal pressure reduced to l atmosphere (approximately). In addition, inevitable marine growth and other fouling would present very hostile conditions on permanently submerged sealing surfaces.

As rather large annular clearances are highly desirable between the work chamber and the lower hemisphere to facilitate their assembly and disassembly, the present inven. tion provides inflatable type seals. These seals are carried on the chamber for sealing against the hemispherical shell.

Once the chamber is in place, hydraulic fluid under pressure is injected into the seal elements, causing them to expand, contacting the inner surfaces of the hemispherical shell. The inflating pressure thus entrapped provides a leak-proof barrier between the work chamber and sea water.

Preferably, two axially spaced seals are provided. The purpose of two separate seal elements is threefold: (l) for the safety factor of a secondary seal, (2) the void between the two elements can be monitored to prove the integrity of the primary seal-also, this cavity can be exhausted through use of a pump, relieving the secondary seal of unnecessary stress until such time it may be required, (3) a third benefit of the dual seal system is that of permitting the passage of hydraulic power from the work chamber of the upper member which can be utilized to operate valves or other equipment which may have been permanently installed in the lower hemispherical shell.

For several years, the petroleum industry has recognized the fact that as the search for petroleum extended into the deeper waters of the continental shelves, there would be a water depth eventually reached where the cost of conventional and accepted means of depleting an oil reservoir via fixed platforms would be economically prohibitive. It was further recognized that any technological breakthrough in this regard would probably entail development of the tools and techniques whereby the wells could be completed, produced and serviced on the ocean floor thereby circumventing the need for fixed platforms which become extremely expensive in deeper waters.

The system disclosed herein may be utilized as an integral part of a program for depleting oil from an offshore petroleum reservoir in water depths of from about up to about 1,000

feet, by drilling, completing, producing and servicing a plurality of wells from the ocean floor. n so doing, wells may be drilled with a floating rig or mobile bottom supported units in certain conditions, and completed on the ocean floor with the base structure, in the form of a face-up hemispherical shell, being an integral part of the wellhead assembly and encompassing the christmas tree. This hemispherical base structure will have a top connection that will be compatible with a diving bell or work chamber which will be logistically supported by a bell tender on the ocean surface. This diving bell will transport men and tools, in a l-atmosphere environment, from the bell tender to any particular well where a water-tight seal will be effected between the bell and the wellhead hemisphere. The trapped water will then be expelled, thereby exposing the wellhead, so that operations such as installation and maintenance of christmas trees and wellhead separators, installation and connection of flow lines, service work, pressure surveys, and other wireline work can be performed.

Each individual well may be equipped with a wellhead separator which will be utilized to separate most of the gas from the oil; the gas may be vented to the ocean if uneconomical to gather and the oil may be routed into a submarine pipeline system which does not form a part of the present invention. Such a submarine pipeline system may connect the wells with a central gathering manifold resting on the ocean floor near a monobuoy mooring complex. The oil can be routed through flexible piping from the central manifold up through the monobouy and then onto a moored, floating storage vessel for further processing, storage and eventual trans-shipment to shore.

BRIEF DESCRIPTION OF THE DRAWINGS In the Drawings:

FIG. 1 is a longitudinal vertical sectional view of a partly completed underwater well at a first stage thereof showing the primary landing base in place;

FIG. 2 is a longitudinal vertical sectional view of a partly completed underwater well at a second succeeding stage thereof, showing the wellhead hemisphere in its last few feet of descent;

FIG. 3 is a longitudinal vertical sectional view of a partly completed underwater well at a third stage thereof showing drilling operations with mud returns diverted over the side of the wellhead hemisphere;

FIG. 4 is a longitudinal vertical sectional view of a partly completed underwater well at a fourth stage thereof showing drilling for receipt of the next inner string of casing, through a blowout preventor (B.O.P.) stack;

FIG. 5 is a longitudinal vertical sectional view of a partly completed underwater well at a fifth stage thereof showing further drilling operations conducted through a narrower bore blowout preventor stack;

FIG. 6 is a longitudinal vertical sectional view of a partly completed underwater well at a sixth stage thereof showing all casing and tubing hung and locked in place and/or cemented and the wellhead hemisphere ready for receipt of the work chamber;

FIG. 7 is a side elevation view of the work chamber with parts in section to expose detail, showing connection with the wellhead hemisphere for installation of production flow lines, the conducting of tests and related completion and servicing activities;

FIG. 8 is a top plan view of the underwater work chamber;

FIG. 9 is a side elevation view of the underwater work chamber;

FIG. 10 is a fragmentary longitudinal vertical sectional view of an underwater well showing the submersible underwater work chamber latched in place with the seals inflated and production flow line equipment installed on the well;

FIG. 11 is a fragmentary longitudinal vertical sectional view, on an expanded scale, of the seal and latch area of the hemispherical shell and upper work chamber;

FIG. 11A is a fragmentary radial horizontal sectional view substantially along the line AA of FIG. 11'; and

FIG. 12 is a perspective view of the upper work chamber leaving after conducting completion, servicing or work-over operations on an underwater well which is one of several in an underwater field, each well being permanently equipped with a wellhead hemisphere.

The principles of the invention will be further hereinafter discussed with reference to the drawings wherein a preferred embodiment is shown. The specifics illustrated in the drawings are intended to exemplify, rather than limit, aspects of the invention as defined in the claims.

DESCRIPTION OF THE PREFERRED EMBODIMENT The following is a description of a typical well drilling, and completion, by stages, utilizing the hemispherical shell, wellhead hemisphere" and the submersible work chamber of the invention. In the following description, the particular casing program, dimensions and the designation of apparatus of particular manufacturers are exemplary.

THE DRILL SHIP IS POSITIONED OVER PREDETER- MINED LOCATION. IF CONSIDERED NECESSARY, OCEAN FLOOR 10 (FIG. 1) COULD BE CHECKED FOR SUITABILITY OF RECEIVING THE PRIMARY BASE 12.

STAGE I A. MAKE UP J TOOL 14 ON DRILL PIPE 16 AND JAY INTO PRIMARY BASE UNDER THE ROTARY.

B. FILL PRIMARY BASE WITH CEMENT 17 AND/OR WEIGHT ED MATERIAL SO IT WILL HOLD ITS POSI- TION ON BOTTOM.

C. ATTACH GUIDE LINES 18 TO BASE.

D. LOWER PRIMARY BASE TO OCEAN FLOOR ON DRILL PIPE.

E. DISENGAGE .l" TOOL 14 FROM BASE BY TURN- ING DRILL PIPE 16 TO RIGHT. DRILL PIPE TO SUR- FACE.

F. RIG GUIDE LINES 18 TO TENSION WINCHES.

STAGE II A. MAKE UP PILOT BIT ON DRILL STRING.

B. INSTALL GUIDE FRAME, COMPLETE WITH DRILL STRING ADAPTER, ON GUIDE LINES.

C. LOWER DRILL STRING AND GUIDE FRAME, TO ENTER DRILL BIT THROUGH OPENING 19 IN PRIMARY BASE 12.

D. DRILL PILOT HOLE WITH RETURNS ONTO THE OCEAN FLOOR.

E. PULL DRILL STRING AND GUIDE FRAME.

F. PICK UP 36INCI-I HOLE OPENER, INSTALL GUIDE FRAME AND COMPLETE CONDUCTOR HOLE.

G. PICK UP AND TIE OFF THE CELLAR BASE 20 (FIG. 2) BELOW THE ROTARY; (MOON POOL OR SECOND DECK).

H. PICK UP BOTTOM SECTION OF CONDUCTOR PIPE 22 AND STAB THROUGH CELLAR BASE 20 (LOWER, UPWARDLY OPEN, HEMISPHERICAL SHELL BASE). INSTALL GUIDE FRAME, COMPLETE WITH CONDUC- TOR ADAPTER, ON GUIDE LINES. ATTACH RETRIEV- ING CABLE TO GUIDE FRAME. LOWER BOTTOM OF CONDUCTOR THROUGH PRIMARY BASE TO A POINT THAT WILL PRECLUDE ITS PULLED OUT WHEN MAK- ING A CONNECTION; THEN RETRIEVE GUIDE FRAME.

I. LOWER CONDUCTOR PIPE UNTIL THE 30 INCH HOUSING 24 HUB 26 REACHES THE CELLAR BASE. IN- STALL GRAYLOC CLAMP 28 AND TEST CONNECTION THROUGH TEST PORT. WITH THE RUNNING TOOL 30 ATTACHED TO THE CONDUCTOR HOUSING 32, THE CELLAR BASE AND CONDUCTOR PIPE ARE LOWERED TO THE SEAT 34 ON THE PRIMARY BASE 12.

.I. CEMENT 36 CONDUCTOR PIPE THROUGH DRILL PIPE. EXCESS CEMENT RETURNS TO OCEAN FLOOR AND PRIMARY BASE BENEATH THE CELLAR BASE.

K. WHEN PRESSURE CAN BE RELEASED, TURN DRILL STRING SIX TURNS TO RIGHT TO RELEASE RUNNING TOOL AND PULL TO SURFACE. NOTE:

IF WATER DEPTH IS SUCH THAT BOTTOM OF CON- DUCTOR PIPE HAS NOT ENTERED PRIMARY BASE BE- FORE THE INCH HOUSING AND CELLAR BASE IS ATTACHED TO THE TOP END OF THE CONDUCTOR PIPE; THEN A BREAK-AWAY GUIDE FRAME CAN BE USED THAT IS RELEASED BY TRIPPING A LATCH. ALSO, THE TWO GUIDE LINES 18 FROM THE PRIMARY BASE MAY BE RETRIEVED BY SHEARING THE PINS.

THE CELLAR BASE 20 HAS CARRIED DOWN WITH IT THE FOUR GUIDE POSTS 38 AND GUIDE LINES 40 THAT ARE TO BE USED FOR THE POSITIONING OF BLOWOUT PREVENTER STACKS THAT WILL BE USED IN FUTURE DRILLING OPERATIONS. TWO ADDI- TIONAL GUIDE LINES ARE PROVIDED IN THE EVENT T.V. CAMERAS ARE USED.

STAGE III WHILE DRILLING HOLE FOR, RUNNING AND CE- MENTING 20 INCH CASING; IT WILL BE NECESSARY TO KEEP MUD, CUTTINGS AND CEMENT FROM GETTING INTO THE CELLAR BASE. THEREFORE, WE EMPLOY A 30 INCH HYDRIL MUD DIVERTER 42 (FIG. 3) AND AN OVERFLOW NIPPLE 44 BELOW IT TO PUT THE RETURNS 46 OVER THE SIDE.

A. THE MUD DIVERTER, WITH A CONNECTOR 48 FOR ATTACHING TO THE 30 INCH CONDUCTOR HOUSING 32 IS SWUNG INTO POSITION BENEATH THE ROTARY.

B. THE GUIDE FRAME, WITH ADAPTER 50 TO FIT DIVERTER IS ATTACHED TO GUIDE LINES 40.

C. WITH THE RUNNING TOOL AND DRILL STRING ATTACHED, THE DIVERTER 42 IS LOWERED AND FASTENED TO THE CONDUCTOR HOUSING 32.

D. TURN DRILL STRING 6 TURNS TO RIGHT TO RELEASE RUNNING TOOL.

E. PULL TO SURFACE, INSTALL 26 INCH BIT 52 ON DRILL STRING 54.

F. INSTALL GUIDE FRAME WITH DRILL STRING ADAPTER TO GUIDE LINES.

G. LOWER DRILL 54 STRING UNTIL 26 INCH BIT 52 HAS ENTERED CONDUCTOR PIPE 22.

' H. ACTUATE PRESSURE TO CLOSE DIVERTER 42 ON DRILL STRING 54'.

I. CONTINUE TO BOTTOM AND DRILL 26 INCH HOLE.

J. WHEN HOLE IS COMPLETED, PULL BIT 52 UP TO DIVERTER 42. RELEASE PRESSURE TO OPEN DIVERTER 42 AND PULL DRILL STRING 54 TO SUR- FACE.

K. PICK UP BOTTOM SECTION OF 20 INCH CASING 56 (FIG. 4). INSTALL GUIDE FRAME 58 WITH ADAPTER TO 20 INCH CASING.

L. ATTACH RETRIEVING CABLE 60 TO GUIDE FRAME.

M. MAKE UP REMAINDER OF 20 INCH CASING AND ATTACH RUNNING TOOL AND DRILL STRING. LOWER 20 INCH CASING TO BOTTOM.

N. UNLATCH GUIDE FRAME AND PULL TO SUR- FACE.

O. CLOSEDIVERTER AND CEMENT THE 20 INCH CASING. RETURNS GOING OUTSIDE OF CELLAR BASE.

P. INSTALL DRILL STRING ADAPTER TO GUIDE FRAME AND LOWER TO BOTTOM.

Q. TURN DRILL STRING 6 TURNS TO RIGHT TO DIS- ENGAGE RUNNING TOOL.

R. AS SOON AS RELEASE HAS BEEN ACCOM- PLISHED, AND WITH DIVERTER STILL CLOSED, CIR- C ULATE THROUGH DRILL STRING TO WASH OUT EX- CESS CEMENT ABOVE 20 INCH HOUSING.

S. OPEN DIVERTER AND PULL DRILL STRING TO SURFACE.

T. MAKE UP DIVERTER RETRIEVING TOOL ON DRILL STRING. 5 U. ATTACH TO DIVERTER AND PULL TO SURFACE.

STAGE IV OPERATIONS FOR THE 13-% INCH CASING, IE,

10 DRILLING 17% INCH HOLE, RUNNING AND CEMENT- ING THE CASING STRING; WILL BE HANDLED THROUGH A 20 INCH BLOWOUT PREvENTER STACK 62 CONSISTING OF HYDRIL PREvENTER, PIPE RAMS 66, CHOKE AND KILL LINE CONNECTIONS 68, ETC.

A. THE 20 INCH 2,000 BLOWOUT PREvENTER STACK WITH 20 INCH CONNECTOR 70 ON BOTTOM, IS SWUNG INTO PLACE UNDER THE ROTARY. STRING GUIDE LINES THROUGH GUIDE FUNNELS AROUND STACK.

20 B. MAKE UP DRILL STRING ADAPTER TO TOP OF UPPER COLLET CONNECTOR 72 WITH ENOUGH TAIL- PIPE T EXTEND THROUGH DRILL PIPE RAMS AND LOWER CONNECTOR.

C. INSTALL HYDRAULIC CONTROL LINES TO PREvENTER STACK AND CONNECT SEPARATE HOSES TO LOCK AND UNLOCK THE UPPER COLLET CONNECTOR.

D. ATTACH THE UPPER COLLET CONNECTOR TO PREvENTER STACK AND LOCK WITH 1,500 PSI AND CLOSE RAMS ON DRILL STRING TAIL PIPE.

E. STRING GUIDE LINES THROUGH GUIDE FUNNELS ON PREvENTER STACK.

F. LOWER BLOWOUT PREvENTER STACK WITH DRILL STRING WHILE SLACKING OFF ON HYDRAULIC LINES.

G. LAND CONNECTOR AND BLOWOUT PREvENTER STACK ON 20 INCH HOUSING.

H. LOCK CONNECTOR WITH 1,500 PSI AND TEST LOWER CONNECTOR AND PIPE RAMS WITH PRES- SURE DOWN DRILL STRING. TEST PRESSURE SHOULD BE GOvERNED BY BURST ON 20 INCH CASING STRING.

I. RELEASE PRESSURE, OPEN RAMS, UNLOCK UPPER CONNECTOR AND PULL CONNECTOR AND DRILL STRING ADAPTER TO SURFACE.

J. MAKE UP BALL JOINT ON CONNECTOR AND STRING GUIDE LINES THROUGH GUIDE FUNNEL ON CONNECTOR.

50 K. MAKE UP CONNECTOR AND BALL JOINT ON RISER PIPE AND HAvE SEPARATE HYDRAULIC LINES ATTACHED TO UPPER CONNECTOR.

L. INSTALL CHOKE AND KILL LINE GUIDE FUNNELS ON RISER PIPE AS IT IS RUN. MAKE UP SLIP JOINT ON TOP OF RISER PIPE.

M. LAND AND LOCK CONNECTOR WITH 1,500 PSI ON TOP OF BLOWOUT PREvENTER STACK.

N. SUSPEND TOP OF SLIP JOINT IN SLINGS.

O. RUN CHOKE AND KILL LINES THROUGH GUIDE FUNNELS ON RISER.

P. STAB AND MAKE UP CHOKE AND KILL LINES INTO CONNECTORS IN PREvENTER STACK 62.

O. HANG OFF CHOKE AND KILL LINES ON SLIP JOINT AND CONNECT TO MANIFOLD.

R. DRILL l7-%INCI-I HOLE 74.

STAGE V A. RUN 13-%INCH CASING 76 (FIG. 5); INSTALL I3- %INCH HOUSING 78 WHEN POINT IS REACHED.

B. MAKE UP RUNNING TOOL ON DRILL STRING AND ATTACH TO HOUSING BY TURNING SIX TURNS TO LEFT.

C. ATTACH GUIDE FRAME, WITH ADAPTER FOR 13- INCH CASING, TO GUIDE LINES.

D. LOWER 13-% INCH CASING WITH RUNNING STRING TO ITS SEAT IN THE 20 INCH HOUSING. CE- MENT CASING STRING, WITH RETURNS COMING TO SURFACE.

E. WHEN PRESSURE CAN BE RELEASED, TURN RUNNING STRING TO RIGHT SIX TURNS TO DISEN- GAGE RUNNING TOOL. CIRCULATE, PULL DRILL STRING.

F. RELEASE LOWER COLLET CONNECTOR WITH 1,500 PSI AND PULL RISER SYSTEM, BLOWOUT PREVENTER STACK AND CONNECTOR.

EMERGENCY OPERATION IF 13-% INCH CASING SHOULD BECOME STUCK BE- FORE IT CAN BE LANDED IN THE 20 INCH HOUSING, USE FOLLOWING PROCEDURE.

A. PULL PRIMARY CEMENT JOB. LET SET.

B. TAKE STRAIN ON 13-% INCH CASING AND MEA- SURE STRETCH.

C. MEASURE A JOINT OF CASING TO BE RUN BETWEEN BROWN OIL TOOL CASING PATCH TOOL AND 13% INCH HANGER.

D. RUN AN INSIDE 13-% INCH CASING CUTTER ON DRILL PIPE.

E. SPACE OUT TO CUT THE 13-% INCH CASING 2' BELOW THE HANGING SEAT OF THE 20 INCH HOUS- ING, PLUS THE LENGTH OF THE JOINT MEASURED IN STEP E, AND LESS THE STRETCH MEASURED IN STEP B AND LESS LENGTH OF BROWN PATCH TOOL.

F. CUT AND REMOVE 13% INCH CASING.

G. MAKE UP BROWN CASING PATCH TOOL ON BOT- TOM OF JOINT OF CASING MEASURED IN STEP C AND MAKE UP I3-% INCH HOUSING ON TOP OF THE JOINT.

H. MAKE UP RUNNING TOOL ON RUNNING STRING AND ATTACH TO 13-% INCH HOUSING.

I. LOWER CASING PATCH TOOL OVER 13-% INCH FISH AND LAND 13-% INCH HOUSING IN 20 INCH HOUSING.

J. RETRIEVE RUNNING TOOL AND MAKE UP CAS- ING SPEAR ON DRILL PIPE.

K. RUN IN HOLE AND LATCH IN CASING FISH.

L. PULL UP ON SPEAR TO PROPER WEIGHT TO SET CASING PATCH PACK OFF.

M. SLACK OFF ON DRILL PIPE; RELEASE AND RETRIEVE SPEAR.

N. TEST CASING AND PATCH TO DESIRED TEST PRESSURE OF 13-% INCH CASING STRING.

O. RETRIEVE RUNNING STRING AND RESUME NOR- MAL OPERATIONS. AT THIS POINT, WE GO TO A 5,000# MSP B.O.P. STACK 80 (FIG.- 5) FOR REMAINING OPERA- TIONS, I.E., DRILLING 12% INCH HOLE, RUNNING 9-% INCH CASING: DRILLING 8- /2 INCH HOLE, RUNNING 7 INCH CASING AND THE TUBING.

STAGE VI PICK UP AND SWING THE 13-% !INCH 5,000 PSI B.O.P. STACK 80 BENEATH THE ROTARY. THE STACK WILL CONSIST OF AT LEAST FOUR SETS OF RAM TYPE 82 AND ONE BAG TYPE 84 PREVENTER, AS WELL AS THE LOWER COLLET CONNECTOR 86 AND THE CHOKE AND KILL LINE MANIFOLD.

A. MAKE UP COLLET CONNECTOR ADAPTER IN RUNNING STRING WITH TAIL PIPE EXTENDING BELOW ADAPTER.

B. ATTACH ADAPTER TO TOP CONNECTOR WITH TAIL PIPE EXTENDING THROUGH CONNECTOR AND BOP STACK.

C. INSTALL HYDRAULIC CONTROL LINES 88 TO PREVENTER STACK WITH SEPARATE HOSES CON- NECTED TO LOCK AND UNLOCK PORTS ON UPPER COLLET CONNECTOR.

D. LOCK THE COLLET CONNECTOR TO THE HUB ON PREVENTER STACK WITH 1,500 PSI AND CLOSE PIPE RAMS ON DRILL PIPE STINGER.

E. STRING GUIDE LINES 60 THROUGH GUIDE FUN- NELS 90 AND UPPER COLLET CONNECTOR.

F. LOWER BOP STACK ON DRILL PIPE WHILE SLACKING OFF HYDRAULIC LINES.

G. LAND CONNECTOR AND BOP STACK ON 13-% INCH HOUSING.

H. LOCK LOWER COLLET CONNECTOR WITH 1,500 PSI THEN TEST LOWER CONNECTOR AND PREVEN- TERS WITH DESIRED PRESSURE DOWN DRILL PIPE.

I. RELEASE PRESSURE, OPEN DRILL PIPE RAMS, UN- LOCK UPPER CONNECTOR AND PULL DRILL STRING AND CONNECTOR TO SURFACE.

J. MAKE UP 13-% INCH COLLET CONNECTOR AND 13-% INCH BALL JOINT.

K. STRING GUIDE LINES THROUGH GUIDE F UNNELS ON CONNECTOR AND BALL JOINT.

L. MAKE UP AND RUN COLLET CONNECTOR AND BALL JOINT ON RISER PIPE 92 WITH SEPARATE HYDRAULIC LINES CONNECTED TO UPPER COLLET CONNECTOR.

M. INSTALL CHOKE AND KILL GUIDE FUNNELS ON RISER PIPE AS IT IS RUN.

N. MAKE UP SLIP JOINT ON TOP OF RISER PIPE.

0. LAND AND LOCK CONNECTOR WITH 1,500 PSI ONTO HUB OF PREVENTER STACK.

P. SUSPEND TOP OF SLIP JOINT IN SLINGS.

Q. RUN CHOKE AND KILL LINES THROUGH GUIDE FUNNELS ON RISER.

R. STAB AND MAKE UP CHOKE AND KILL LINES INTO CONNECTORS ON PREVENTER STACK.

S. HANG OFF CHOKE AND KILL LINES ON SLIP JOINT AND TIE TO MANIFOLD. PREPARING TO DRILL 12-% INCH HOLE AND RUN 9-% INCH CASING A. MAKE UP TEST PLUG ON DRILL STRING AND LOWER TO SEAT IN 13-% INCH HOUSING.

B. CLOSE PIPE RAMS ON DRILL PIPE AND TEST PREVENTERS AND CONNECTOR TO 5,000 PSI DOWN THE KILL LINE.

C. RELEASE PRESSURE, OPEN RAMS, RETRIEVE TEST PLUG.

D. INSTALL 12 INCH WEAR SLEEVE RUNNING TOOL ON DRILL PIPE.

E. MAKE UP RUNNING TOOL IN 12 INCH WEAR SLEEVE WITH FOUR TURNS TO RIGHT BUT DO NOT TIGHTEN.

F. LOWER AND LAND WEAR SLEEVE IN 13-% INCH HOUSING.

G. DISENGAGE RUNNING TOOL FROM WEAR SLEEVE WITH FOUR TURNS TO LEFT; RETRIEVE RUNNING TOOL AND DRILL STRING.

H. DRILL 12-/4 INCH HOLE.

I. BEFORE RUNNING 9-% INCH CASING 94, MAKE UP WEAR SLEEVE RUNNING TOOL ON DRILL PIPE.

J. RETRIEVE WEAR SLEEVE BY TURNING DRILL PIPE FOUR TURNS TO RIGHT.

K. PULL WEAR SLEEVE TO SURFACE.

STAGE VII A. RUN 9-% INCH CASING; MAKING UP SEAL AS- SEMBLY AND 9-% INCH HOUSING WHEN SETTING DEPTH IS REACHED.

B. MAKE UP RUNNING TOOL ON CASING LANDING STRING.

C. ATTACH RUNNING TOOL TO 9-% INCH HOUSING AND SEALING DEVICE WITH EIGHT TURNS TO RIGHT.

D. LOWER AND LAND 9-% INCH CASING HOUSING 96 IN I3-% INCH HOUSING AND CEMENT.

E. WHEN PRESSURE CAN BE RELEASED, TURN LANDING STRING I0 TURNS TO RIGHT. THIS WILL AC- TUATE PACKING BETWEEN THE 133$ INCH X 9-% INCH ANNULUS.

F. CONTINUED RIGHT HAND ROTATION WILL DIS- ENGAGE SEALING DEVICE FROM 9-% INCH HOUSING.

G. CLOSE RAMS ON CASING LANDING STRING AND TEST TO REQUIRED PRESSURE ON 9-% INCH CASING.

H. RELEASE PRESSURE, OPEN RAMS AND PULL LANDING STRING AND TOOLS TO SURFACE.

PREPARE TO DRILL 8-V2 INCH HOLE AND RUN 7 INCH CASING A. INSTALL INCH WEAR SLEEVE RUNNING TOOL ON RUNNING STRING.

B. MAKE UP RUNNING TOOL IN 10 INCH WEAR SLEEVE WITH FOUR TURNS TO RIGHT BUT DO NOT TIGHTEN.

C. LOWER AND LAND WEAR SLEEVE IN 9-% INCH HOUSING.

D. DISENGAGE RUNNING TOOL FROM WEAR SLEEVE BY TURNING FOUR TURNS TO LEFI'. RETRIEVE RUNNING TOOL AND DRILL STRING.

E. DRILL 8% INCH HOLE.

F. BEFORE RUNNING 7 INCH CASING 98, MAKE UP WEAR SLEEVE RUNNING TOOL ON DRILL STRING.

G. RETRIEVE WEAR SLEEVE BY TURNING FOUR TURNS TO RIGHT AND PULL TO SURFACE.

STAGE VIII A. RUN 7 INCH CASING 98, MAKING UP SEAL AS- SEMBLY AND 7 INCH HOUSING WHEN SETTING DEPTH IS REACHED.

B. MAKE UP RUNNING TOOL ON CASING LANDING STRING.

C. ATTACH RUNNING TOOL TO 7 INCH HOUSING AND SEALING DEVICE WITH EIGHT TURNS TO RIGHT.

D. LOWER AND LAND 7 INCH CASING HOUSING IN 9-% INCH HOUSING AND CEMENT.

E. WHEN PRESSURE CAN BE RELEASED, TURN LANDING STRING TO RIGHT. THIS WILL ACTUATE PACKING BETWEEN THE 9-% INCH X 7 INCH ANNU- LUS.

G. CLOSE RAMS ON CASING LANDING STRING AND TEST TO REQUIRED TEST PRESSURE ON 7 INCH CAS- ING.

H. RELEASE PRESSURE, OPEN RAMS AND PULL LANDING STRING AND TOOLS TO SURFACE.

WELL COMPLETION PROCEDURE One of the advantages of the wellhead hemisphere and work chamber concept is that the christmas tree or flow manifold portion of the wellhead assembly can be less sophisticated than those usually associated with a sub-sea completion in deep water.

We offer a simple on land" type flow manifold that would have two master valves, crown valve, wing valve and choke. These components would have actuators controlled from the control center on the storage vessel.

Since we will be set up for certain wire line operations within the work chamber, the T.F.L. loop and diverter could be omitted. By the same token, one string of tubing could be used for a single completion while two strings could be reserved for dual completion.

It is realized that methods of completing a well do vary from operator to operator and also from well to well; most of which are individual and must be handled as such.

Let us then examine methods best suited for our sub-sea system:

A. PERFORATE AND TEST IN A GREAT NUMBER OF CASES, THE OPERATOR WILL WISH TO PERFORATE AND TEST THE PRODUC- ING HORIZON BEFORE GOING THROUGH THE AC- Ill TUAL COMPLETION SEQUENCE. THIS TEST WOULD CONFIRM THE INTEGRITY OF THE CEMENT JOB AND VERIFY EXPECTED FLOW CHARACTERISTICS OF THE OIL OR GAS BEARING SAND. IF BLOCK SQUEEZING MUST BE DONE, NOW WOULD BE THE BEST TIME FOR IT.

B. RUN PACKER WITH TUBING THE HYDROSET PACKER Is BEsT FOR THE TYPE OPERATION. WHEN SETTING DEPTH IS REACHED, THE TUBING HANGER, wHIcH HAs A sEcoND PoRT FOR CIRCULATING, IS MADE UP IN THE TUBING STRING.

c. THE TUBING Is LANDED WITH AN OTIS HYDRAU- LIC OPERATED DUAL vALvE ATTACHED TO THE TUBING HANGER AND LANDING TOOL.

D. WITH HYDRAULIC PRESSURE ON THE BALL VALVES TO KEEP THEM oPEN, WE DISPLACE THE TUBING.

E. wHEN TUBING IS DIsPLAcED, THE SETTING BALL IS LANDED IN THE RECEIVER AND PRESSURE APPLIED TO THE TUBING To sET PACKER.

F. HYDRAULIC PRESSURE Is RELEASED To CLOSE BALL vALvEs.

G. PUMP DowN TUBING sTRING TO TEST BALL vALvEs.

H. RELEASE LANDING TOOL AND PULL RUNNING STRING.

TUBING GUN'PERFORATING METHOD IN THE EVENT THE OPERATOR WISHES TO PER- FORATE THE PRODUCING ZONE AFTER RUNNING TUBING AND SETTING PACKERS; THE PROCEDURE IS AS FOLLOWS:

A. RUN TUBING; PLACING HYDROSET PACKET TO FALL AT PROPER INTERVAL.

B. WHEN LANDING POINT IS REACHED, MAKE UP TUBING HANGER, OTIS HYDRAULIC DUAL VALVES AND RUNNING TOOL.

C. LOWER TUBING HANGER TO ITS SEAT IN THE 7 INCH BOWL.

D. ACTUATE HYDRAULIC PRESSURE TO OPEN BALL VALVES.

E. DISPLACE TUBING, TAKING RETURNS THROUGH TUBING HANGER PORT AND INTO RISER PIPE TO SUR- FACE.

F. LAND PACKER SETTING BALL IN RECEIVER AND APPLY PRESSURE TO TUBING STRING TO SET PACKER. I

G. RIG UP LUBRICATOR AT SURFACE ON EX- TENDED TUBING STRING TO ACCOMMODATE PER- FORATING GUN.

H. LOWER GUN TO PROPER INTERVAL, PER- FORATE.

I. PULL GUN TO A POINT ABOVE HYDRAULIC BALL VALVES AT WELLHEAD.

J. RELEASE HYDRAULIC PRESSURE TO CLOSE BALL VALVES.

K. RETRIEVE GUN, RIG DOWN LUBRICATOR.

L. PUMP DOWN TUBING STRING TO TEST BALL VALVES.

M. RELEASE LANDING TOOL AND PULL LANDING STRING. THE WELL IS NOW READY FOR PRODUCTION BUT CLOSED IN WITH THE OTIS HYDRAULIC BALL VALVES. WE ARE NOW READY TO DISMANTLE THE 13-% INCH B.O.P. STACK AND RELEASE THE DRILL SHIP (FIG. 6).

OPERATIONS CONTINUE AT THE WELLHEAD WHEN THE WORK CHAMBER (FIG. 7) HAS BEEN LOWERED AND FASTENED TO THE HEMISPHERE 20 AND AN ATMOSPHERIC CONDITION PREVAILS.

A. THE TUBING PLUGGING TOOL 102 (FIG. 10) IS RIGGED UP ON THE OTIS BALL VALVE ABOVE TUB- ING STRING.

B. A COVER PLUG MADE UP ON THE ANNULUS PORT OF BALL VALVE.

C. HYDRAULIC PRESSURE IS APPLIED TO OPEN BALL VALVES.

D. TUBING PLUG IS SET IN TUBING HANGER.

E. PLUGGING TOOL IS REMOVED TO ANNULUS PORT AND PROCEDURE CONTINUED TO SET BACK PRESSURE VALVE IN PLACE.

F. OTIS BALL VALVES REMOVED.

G. INSTALL PERMANENT WELLHEAD MASTER VALVE ASSEMBLY AND TEST CONNECTION.

H. REMOVE TUBING PLUGS THROUGH MASTER VALVES. WHEN FLOW LINES HAVE BEEN IN- STALLED, MAKE CONNECTION TO CHOKE AS- SEMBLY. CONNECT MASTER VALVE AND CHOKE AC- TUATOR LINES FOR REMOTE CONTROL OF THE WELLHEAD ASSEMBLY.

Referring to FIG. 7, the well is shown completed to a point where the conductor bore has been drilled through drilling template and 26 inch casing run with the guide base lower hemisphere 20 connected to and run with the last joint of casing. The integrity of the connection seal is tested prior to lowering. The lower hemisphere 20 contains a plurality, for instance, four standard guide posts 38 and latches plus a plurality, for instance, three to 12 flow line and access line connector mechanisms 104 (FIG. 12).

As may be seen, cementing has been completed and the original drilling template guide lines 18 (FIG. 1) have been removed.

The underwater work chamber 100 which has been pulled down from a floating bell tender using a self-contained wire line which is shown having made contact with the lower hemisphere, orienting itself on the guide posts. (Note that the guide lines have been removed prior to lowering the work chamber.) Also, all casing, tubing and hangers have been run set and/or cemented. Tubing plugs run with the tubing afford pressure protection while running and nipple up. In addition, the riser and B.O.P. stack have been removed during the stage of FIG. 6.

Guide lines may be lowered with the work chamber to facilitate the eventual installation of the flow and access lines.

Turning now to FIG. 10, the work chamber 100 has been positioned on the hemisphere and the

inflatable seals

104, 106 have been actuated. The entrapped water, having been displaced using a suction pump on the work chamber having an inlet hose which protrudes below the floor of the work chamber to adjacent the bottom of the hemispherical member, the work area being the space below the floor and within the hemisphere, is charged with one atmosphere of a breathable gas mixture.

Note that the hydraulic cylinders 108 (FIG. 11) serve as position latches between the work chamber and the lower sphere.

FIG. depicts the completion of the installation of the production tree with the upper portion of the flow loop 110.

The flow lines and manifold have been lowered on the guide cables outside the chamber into their clevis and a standard tubing plugging tool 102 has been attached to the gate valve 114. This is preparatory to the actuation of the flow line bridge sleeve 118 and to remove the flow line tubing plugs.

After rotating the bridge sleeve into place and testing the seals, the tubing plugs may be removed. It remains only to install the missing segment (dashed line 120, FIG. 10) of flow loop 110.

In FIG. 10, the 3% inch 9.3 plug 102 installed at the surface serves to prevent entrance of sea water while the Gray Gate Valve 114 (or equivalent) is installed by the crew.

The 2% inch 6.5 plug lowered in place, with the flow line, prevents the entrance of sea water into the flow line and later serves as a test plug for the bridge sleeve.

Upon opening the gate valve 114, a special tool with a collapsible key arrangement is pushed through the valve to engage and screw the bridging sleeve into place. The linear motion is achieved through a system of screw threads contained in the plug tool and is operated by rotary effort applied to the crank.

After the bridging sleeve is screwed into place and the hydraulic packing seal is tested, the collapsible keyed tool 102 is withdrawn and the gate valve closed.

The placement of the bridging sleeve 118 serves a twofold purpose: (1) to effect a positive seal between the flow line manifold and the flow' line connector; (2) although the bridging sleeve is illustrated as being actuated mechanically through the use of a thread system, a hydraulic piston system could be utilized, eliminating the need for the threads. The nose 122 of the bridging sleeve also provides a structural link between flow line and connector, preventing accidental vertical motion between flow line and flow line connector.

Completing the setting and testing of the bridge sleeve, the collapsible key tool is removed and replaced by a plug retrieving tool which is pushed through the gate valve whereupon it contacts, seizes and unscrews the 3% inch 9.3 it plug.

Having removed the 3% inch 9.3 i plug, the plug tool and retrieving attachment may next be employed for the removal of the 2% inch 6.5 plug, following which the flow line itself may be tested.

As a quantity of these flow line connectors and landing clevises may be installed in the wall of the receptacle, the orientation of the receptacle 20 as it is landed on the ocean floor is of small concern; i.e., a flow line(s) 116 may be attached and dispersed in virtually any direction.

As an added safety feature, a plastic injection seal system is provided on each flow line connector and should a leak occur in the CWC type seal, a quantity of a viscous plastic preparation may be injected into the seal areas.

Subsequent to the stage depicted in FIG. 10, the flow system may be completed and wire line lubricator may be assembled atop the production tree with which tubing plugs may be removed and divertors installed. Any other wire line operations may be performed.

A contamination separator may be placed immediately 0 above the wire line B.O.P.s to prevent undesirable hydrocarbons from entering the work area during wire line operations.

After the well has been completed and turned into the gathering system, the crew may return to the personnel quarters 130 in the upper end of the chamber 100 above its floor and the floor hatch closed 132. The pressure in the work area 134 is then allowed to equalize with outside hydrostatic pressures, and the hold-down latches 108 are released, thus permitting the work chamber to surface.

The pictorial view in FIG. 12 shows the work chamber 100 as it would appear leaving a new well site or returning to work over an old one.

The two

inflatable seals

104, 106 provided in accordance with the invention preferably consist of identical assemblies welded to the exterior of the work chamber near its lower exterior. The seal assemblies are slightly axially spaced from one another to provide for test and hydraulic supply ports (FIG. 11) between them, through the permanent, lower and submersible upper members side walls as shown in FIG. 11.

The two inflatable seal assemblies each include a tubular plate 142 to which two axially spaced seal confining elements 144 are welded. Each seal consists of a tubular rubber inner member 146, an intennediate tubular layer of overlapping steel braids 148 and an outer covering of rubber 150.

Each

seal assembly

104, 106, although much larger in size, for instance, being 16 feet in outer diameter when uninflated, is of the same material as the rubbers of the packers shown on pages 3,00l3,020, and especially on pages 3,002 and 3,015, of the Composite Catalog of Oil Field Equipment and Services, 1968-1969 Edition, Gulf Publishing Company, Houston, Texas. At this size, the radial clearance between the seals when uninflated and the inner peripheral surface of the lower hemispherical member 20 is, for instance, 1% inches.

Lines 152 for inflating the seals may be connected to hydraulic pressure pumps within the work chamber.

It should now be apparent that the underwater completion system as described hereinabove possesses each of the attributes set forth in the specification under the heading Summary of the Invention hereinbefore. Because the underwater completion system of the invention can be modified to some extent without departing from the principles of the invention as they have been outlined and explained in this specification, the present invention should be understood and accepted as encompassing all such modifications as are within the spirit and scope of the following claims.

What is claimed is:

1. An underwater well completion system including:

a lower upwardly opening hemispherical shell base permanently mounted on an underwater well so as to surround the wellhead adjacent the underwater bottom;

a plurality of angularly spaced flow line connectors protruding through the hemispherical shell base;

a submersible work chamber having a lower end receivable into the upper end of the hemispherical shell base with substantial clearance;

at least two axially spaced inflatable seal assemblies exteriorly mounted on said submersible work chamber near said lower end to be received into said hemispherical shell base;

opening means through said submersible work chamber into each said inflatable seal assembly for inflating each into circumferential sealing contact with said hemispherical shell base;

at least one upwardly protruding guide post on said hemispherical shell base; at least one guide sleeve on said submersible work chamber adapted to slide down over said guide post; means defining a detent in said guide post and means defining a latch on said submersible work chamber, actuable to enter said detent means to lock said submersible work said hemispherical shell base.

2. An underwater well completion system including:

at least two axially spaced inflatable seal assemblies exteriorly mounted on said submersible work chamber near said lower end to be received into said hemispherical shell base; 7

opening means through said submersible work chamber into each said inflatable seal assembly for inflating each into circumferential sealing contact with said hemispherical shell base; port means through said hemispherical shell base between the locations of said inflatable seals for providing access to the region between said seals for pressure testing and fluid removal.

3. An underwater well completion system including:

a submersible work chamber having a lower end receivable into the upper end of the hemispherical shell base with.

substantial clearance;

' opening means through said submersible work chamber into each said inflatable seal assembly for inflating each into circumferential sealing contact with said hemispherical shell base; each seal assembly ll'lClUdll'lg a tubular stationary base provided at each axial end with a stationary seal confining element, and a tubular seal received between said confining elements and comprising an inner layer of flexible rubber, an intermediate layer of overlapped steel braiding and an outer layer of rubber; and means defining a seal inflation port through each tubular steel base.

Claims

1. An underwater well completion system including: a lower upwardly opening hemispherical shell base permanently mounted on an underwater well so as to surround the wellhead adjacent the underwater bottom; a plurality of angularly spaced flow line connectors protruding through the hemispherical shell base; a submersible work chamber having a lower end receivable into the upper end of the hemispherical shell base with substantial clearance; at least two axially spaced inflatable seal assemblies exteriorly mounted on said submersible work chamber near said lower end to be received into said hemispherical shell base; opening means through said submersible work chamber into each said inflatable seal assembly for inflating each into circumferential sealing contact with said hemispherical shell base; at least one upwardly protruding guide post on said hemispherical shell base; at least one guide sleeve on said submersible work chamber adapted to slide down over said guide post; means defining a detent in said guide post and means defining a latch on said submersible work chamber, actuable to enter said detent means to lock said submersible work chamber to said hemispherical shell base.

2. An underwater well completion system including: a lower upwardly opening hemispherical shell base permanently mounted on an underwater well so as to surround the wellhead adjacent the underwater bottom; a plurality of angularly spaced flow line connectors protruding through the hemispherical shell base; a submersible work chamber having a lower end receivable into the upper end of the hemispherical shell base with substantial clearance; at least two axially spaced inflatable seal assemblies exteriorly mounted on said submersible work chamber near said lower end to be received into said hemispherical shell base; opening means through said submersible work chamber into each said inflatable seal assembly for inflating each into circumferential sealing contact with said hemispherical shell base; porT means through said hemispherical shell base between the locations of said inflatable seals for providing access to the region between said seals for pressure testing and fluid removal.

3. An underwater well completion system including: a lower upwardly opening hemispherical shell base permanently mounted on an underwater well so as to surround the wellhead adjacent the underwater bottom; a plurality of angularly spaced flow line connectors protruding through the hemispherical shell base; a submersible work chamber having a lower end receivable into the upper end of the hemispherical shell base with substantial clearance; at least two axially spaced inflatable seal assemblies exteriorly mounted on said submersible work chamber near said lower end to be received into said hemispherical shell base; opening means through said submersible work chamber into each said inflatable seal assembly for inflating each into circumferential sealing contact with said hemispherical shell base; each seal assembly including a tubular stationary base provided at each axial end with a stationary seal confining element, and a tubular seal received between said confining elements and comprising an inner layer of flexible rubber, an intermediate layer of overlapped steel braiding and an outer layer of rubber; and means defining a seal inflation port through each tubular steel base.