Subsea Wellhead Completion Systems

Abstract

This describes a system for use in performing workover operations on oil and gas wells drilled at marine locations. When wells are drilled in deep water, e.g., 300 or more feet, it is usually desirable to have what is known as a bottom or sea floor well completion. In such completions, the production flow line is connected into the wellhead. In this invention the wellhead is provided with a removable cap. When it is desired to work over the well, the cap is removed and a riser pipe, supported from a vessel or buoy on the surface, is lowered into sealing engagement with the wellhead; the riser pipe being vertically aligned with the well. Operations are then conducted through the riser pipe and the wellhead. Various configurations or modifications of the interior of the wellhead are made, including modifications useful for TFL (through the flow line) tools.

Description

This invention relates to completion and workover systems of wells completed on the floor of a body of water.

BACKGROUND OF INVENTION

In recent years the search for oil and gas has extended into water-covered areas. At first this search was in relatively shallow waters, e.g., 50-100 feet. In water of this depth, either an island or a platform was built over the proposed well site and the well was drilled from the island using dry land techniques. The islands were formed, for example, by dredging up large amounts of gravel until the islands extended above the surface of the water. Platforms were ordinarily formed by driving piling or long columns of steel into the ocean floor and attaching a deck to the ends of the pilings which extended above the surface of the body of water. If a commercial well was obtained, the wellhead was on the platform or the top of the island similarly as on dry land wells. More recently, the search for oil and gas has extended into deeper water, for example, up to depths of 400-600 feet or more and in a few instances even in excess of 1,000 feet. At these depths it is seldom feasible to build up an island or platform. Consequently, wells from this depth are drilled from floating vessels. This drilling technique has advanced quite rapidly, and although there are still many problems associated therewith, this practice has been fairly successful. If production of oil is found in paying quantities, there must be some satisfactory way of completing the well. This way of completion of the well must provide means for satisfactory workover operations. Workover operations ordinarily means any major work performed on a completed well, such as shooting, acidizing, plugging back, squeeze cementing, repairing casing or tubing, Hydrafrac treating etc.

BRIEF DESCRIPTION OF THE INVENTION

Broadly speaking, this invention concerns a novel subsea wellhead and means associated therewith for performing workover operations. The well includes the usual tubing hung below a tubing hanger in the wellhead. A removable mandrel is connected to the tubing and extends upwardly through a packer set in the bore of the wellhead assembly which includes blowout preventers. The upper end of the mandrel is closed. The wellhead assembly includes an outlet spool having a lateral outlet for connection to a production line. Means are provided to provide communication between the interior of the mandrel and such outlet. The wellhead contains a cover and plug combination which is removed and then a riser pipe is connected to the wellhead and communicates the wellhead to the surface. Workover operations are then conducted from the surface through the riser pipe. The tubing mandrel extension can be removed and the tubing string pulled if needed.

Various objects and a better understanding of the invention can be had with the following description taken in conjunction with the drawings in which:

FIG. 1 illustrates one embodiment of a subsea well head completion;

FIG. 2 illustrates a tool useful for finding the well head of FIG. 1 and in removing the cap therefrom;

FIG. 3 illustrates the embodiment of FIG. 1 after the cop has been removed and a riser pipe connected to the wellhead;

FIG. 4 is a section taken along the line 4--4 of FIG. 3;

FIG. 5 is a section taken along the line 5-5 of FIG. 4;

FIG. 6 is another embodiment of the wellhead completion;

FIG. 7 is another embodiment of the wellhead completion useful for through the flow line-type completions;

FIG. 8 illustrates downhole equipment for use with the embodiment of FIG. 7;

FIG. 9 illustrates the riser pipe supported by a spar buoy;

FIG. 10 illustrates downhole equipment for use with the embodiment of FIG. 1.

Attention is first directed to FIG. 1 which shows one embodiment of a subsea wellhead completion. Shown thereon is a casing 10. Casing 10 is set in the well in a usual manner and is connected to an ocean floor anchor base, not shown, in any conventional manner. Rigidly connected to and immediately above casing 10 is a lower blowout preventer 12, then an outlet spool 14, an upper blowout preventer 16 and blind rams 18. Above blind rams 18 is a utility stub 20. A bore 22 extends vertically through elements 12, 14, 16, 18 and 20. This bore has a diameter at least as large as that of casing 10. In utility stub 20, bore 22 is stepped to accommodate cap 26.

A wellhead tubing hanger assembly 28 is provided in casing 10 and tubing 30 is suspended therefrom. Tubing hanger assembly 28 rests on shoulder 27 in casing 10. A tubing extension mandrel 32 is connected to tubing 30 at the surface and run as a unit with tubing 30 and tubing hanger 28. The upper end of tubing extension mandrel 32 extends through packer 34 which is latched to the wall of the bore 22 to prevent upward movement. Suitable packers are commercially available. Brown Oil Tools, Inc., Houston, Texas, offers a Model H--1SP mechanical set packer which illustrates a principle of retrievable packers. Retractable latch projections of packers 28 and 32 are indicated by reference numerals 28C and 32C, respectively. A splined leakproof slip joint 39 is provided in tubing extension 32. This can be similar to that utilized in the fishing bumper sub sold by Bowen Tool, Inc., Houston, Texas. This slip joint is used when retrieving packers 28 and 32. The upper end of tubing extension mandrel 32 is connected to coupling 36 above an "S" nipple 35 which contains a blanking plug which can be removed by wire line in a known manner.

Attention will now be directed toward that portion of the completion system for producing the oil under operating conditions. Outlet spool 14 has an outlet connection 37 which is connected to a conduit having remote operated control valve 38. The outlet of 38 goes to connecting conduit 40 which goes to some gathering system. Tubing extension mandrel 32 is provided with a wire-line operated valve 42 having ports 44. In an ordinary operations, oil flows upwardly through tubing 30 out ports 44 and into bore 22 and out outlet 37 of outlet spool 14. Valve 44 can be a type "S" remote controlled subsurface valve manufactured by Otis Engineering Corporation, Dallas, Texas.

Attention will next be directed toward that part of the embodiment which closes the upper end of bore 22. Plug 26 is latched to utility stub 20 by latching means 48. Latching means 48 can be spring biased outwardly into latching slot 49. Levers 48B extend into bore 56 and when forced downward, unlatch latching means 48. A seal 50 is provided between plug 26 and upwardly facing internal shoulder of stub 20. Orienting key 52 is provided on cap 26 to mate with an orienting slot 51 in an enlarged portion 54 of utility stub 20. As will be seen, this slot is useful in orienting the riser pipe when it is lowered. Cover 26 is provided with an internal bore 56 having internal latching groove 58. This groove 58 is used for latching onto the plug when removing it.

A guide cone 60 is permanently attached to the top of utility stub 20. A semicylindrical member 62 is formed at the top of cone 60. Part of cone 60 is cut away at 64. This forms an open area or target that is useful for stabbing in the riser pipe or other equipment. Element 62 is thus used as a "stopper" or fence.

Blowout preventers 12, 16 and rams 18 have control lines 66,68 and 70, respectively. These terminate and engage corresponding conduits in the utility stub 20 which in turn mate with conduits in the wall of the riser pipe. (As shown in FIG. 4 and discussed more completely later.) Slot 51 assures proper alignment of the control conduits.

Attention is next directed to FIG. 2 which illustrates an apparatus to be connected to the lower end of a drill string for finding and removing the cover or cap 26. The upper end of the device contains threads 74 which can be connected directly into the box end of a drill pipe or tubing tool joint. The device includes an upper housing 76, a lower housing section 78 and a jar section 80 between the two sections. External expandable latches 82 are provided near the lower end of lower section 78. These are the type which can be remotely actuated from the surface. Latches 82 can be merely spring-loaded outwardly extending dogs with a sloping underside. Jar section 80 is of the type which is commercially available and is modified to include a flow passage 84 therethrough. Jar section 80 can be "set" in a conventional manner. A bullnose plug 86 having outlets 88 is provided at the lower end of housing 78.

The walls of upper housing section 76 are provided with upper single port 94 and a plurality of radially spaced lower ports 96, an internal sleeve 98 having lower ports 96A which when sleeve 98 is in its lower position register with ports 96. When sleeve 98 is in its lower position, jet port 94 is open. Sleeve 98 is biased upwardly by springs 100 and in its upper position sleeve 98 closes both ports 94 and 96. Shoulders 93 on the inside of upper section 76, limits the upward movement of sleeve 98.

The purpose of port 94 is to provide directing jet for moving the lower end of the tool in a selected reference to the water. The direction of the port 94 is obtained by rotating the drill pipe at the surface in the opposite direction from which it is desired to move the pipe. A plug 102, having extension 104, is provided for use in the tool. Plug 102 has a lower shoulder which can seal with the upper end of sleeve 98. Plug 102 can be dropped into the drill pipe. Then when it is desired to have a jet from ports 94, fluid under pressure is pumped down the drill pipe. This contacts the upper side of plug 102 which forces it downwardly as shoulder 106 of plug 102 contacts the upper end of sleeve valve 98. This forces the plug and the sleeve valve 98 downwardly collapsing springs 100. Port 94 is thus opened. This permits the circulating fluid to jet out ports 94 driving the lower end of the drill pipe in the desired lateral direction. At the same time that the jet is in operation scanning ports 96 and 96A are open. This permits sonar unit 108 to operate. Sonar unit 108 is in or a part of the lower end of the plug extension 104 and suitable lines 110 extend to the surface. Sonar unit 108 can be a Model 274 High Resolution Scanning Sonar System, offered by Edo Western Corporation. This sonar unit has sufficient resolution to locate the wellhead of the apparatus of FIG. 1 so that the device of FIG. 2 can be directed toward it.

By using the sonar unit as described above and the jet 94, the bullnose plug 86 is rapidly directed into guide cone 60 and into cavity 56 of plug 26 of the wellhead shown in FIG. 1. Quite frequently cavity 56 will be filled with sand, mud or other debris. When this occurs, fluid is circulated down through the tool and out ports 88 of the bullnose plug. This is accomplished by removing plug 102 so that sleeve 98 is pushed to its upper position. Thus jets 94 and 96 are closed and all the drilling fluid is circulated out ports 88. This cleans out the sand, etc., of cavity 56 until expandable latches 82 can engage groove 58 of plug 26. Latches 48 of plug 26 of FIG. 1 are released by the downward force of plug 86 on latch releasing lever 48B. Then an upward pull is made on the drill pipe which is transmitted through the device of FIG. 2 to the cap 26. If a reasonable pull does not remove the plug, jar section 80 is set to aid in removing the plug from its stuck position. Once the plug is unstuck and unlatched, it is removed to the surface.

After the plug has been removed to the surface by the operation of the drill pipe, a riser pipe is lowered into position. This can conveniently be accomplished by using the device of FIG. 2 to again locate the wellhead. Then the riser pipe such as 112 shown in FIG. 3 is stripped down over the drill string in a known manner.

Attention is now directed to FIG. 3 which shows the riser pipe 112 in place so that subsequent workover operations can be performed. As shown in FIG. 3, riser pipe 112 is locked with latch 48A into slot 49 similarly as was latch 48 in FIG. 1. Means of actuating and retracting latches 48A are well known. For example, latches 48A can be hydraulically operated from conduits, not specifically shown, in the walls of the riser itself. Seals 50A seal similarly as seals 50 in FIG. 1. The wall of riser 112 contains conduits 70A, 68A and 66A as shown in FIG. 4. These have outward extensions or ports 70B, 68B, and 66B which mate with control conduits 70, 68 and 66, respectively. This mating is assured by key 52 and orienting slot 51. Then at the surface it is readily seen which conduit controls which blowout preventer or ram. By proper designation, one can also determine which conduit at the surface opens and which one closes a particular blowout preventer, for example. Greater details of this are not given here as it would be obvious to one skilled in the art.

FIG. 5 illustrates one means of establishing fluidtight communication between the conduits 70A, for example, in the riser and conduits 70B. This includes a stepped piston 200 having seals 202 and 204. An axial conduit 210 extends through the piston. A spring 206 urges the piston 200 toward stops 208. In operation, hydraulic control fluid is injected down conduit 70A. The pressure on the larger head of the piston forces it toward the opening of conduit 70B, and compresses spring 206 in the process. Thus a fluidtight connection is made between conduits 70A and 70B. Then control operations of the valves, etc., can be effected. When pressure of the control fluid is released, the spring 206 forces the piston completely back into conduit 70A toward stops 208.

FIG. 10 illustrates a downhole completion embodiment useful with the device shown in FIG. 1. Tubing 30 extends below annular packer 140 which is set between the tubing and the casing above perforations 142 in the wall of casing 10. A wire-line operated valve 144 is placed in tubing 30 just above packer 140. A suitable valve 144 is an Otis sliding side door, page 3820 in Composite Catalogue of 1966-67 and published by World Oil, Houston, Texas.

FIG. 9 illustrates a spar buoy arrangement for use in supporting a riser pipe to conduct the workover operations described elsewhere. This includes a large diameter main buoy section 170 having a neck 172 which extends above the surface of the water 174. A work deck 176 having crane 178 is supported by neck 172. Main ballast tank 170 has a series of internal compartments, now shown, and each is provided with an inlet means 180 and an outlet pump means 182. These are used to change or control the ballast as desired. If desired, when pulling tubing, the pulled joints can be hung in neck 172 on racks, not shown, similarly as in a derrick on land operations. Riser pipe 112 extends downwardly from ballast tank 170 to the wellhead such as shown, for example, in FIG. 3.

Before discussing other embodiments, it is well to discuss how workover operations take place with the device of FIG. 3 which is really FIG. 1 with the plug 26 removed and replaced by riser 112 which extends to a ship or floating structure at the surface. We will next consider the operational procedures of FIG. 1 for procedure for wire-line workover. The following steps are normally taken in the sequence given.

PROCEDURE 1

1. A floating support or platform is positioned over the approximate location of the subsea wellhead.

2. Remove the wellhead protective cap 26 using the tool of FIG. 2 as described above.

3. Lower the riser pipe 112 by stripping it over the drill string having the sonar system of FIG. 2. Latch the riser pipe onto utility stub 20. (Remove the drill string and device of FIG. 2 if the riser pipe were stripped over the drill string.)

4. Tension riser pipe 112 by modifying the ballast in the spar buoy of FIG. 9. If a floating vessel or a large ship is used, tensioning can be obtained by the same means as tensioning riser pipe during drilling operations.

5. Using control line 70, open blind rams 18.

6. Check the pressure in bore 22 above packer 34 to insure that leaks do not exist.

7. Run tubing string 49 and connect to fitting 36.

8. Remove blanking plug from "S" nipple 35.

9. Close ports 44 of valve 42.

10. The well is now ready for the performance of wire-line work in conventional manner.

Attention is next directed to FIG. 6 which shows a modification of the tubing extension mandrel section of FIG. 1. In FIG. 6, tubing extension mandrel 32A having valve 42A with ports 44A and a slip joint 39A (similar to slip joint 39 of FIG. 1) is provided between packers 34A and tubing hanger 28A similarly as in FIG. 1. However, a second tubing extension 114 having a slip joint 39B extends from above packer 34A to tubing hanger 28A. This extension 114 has no valve or port in it but rather is simply a piece of tubing with "S" nipple 117A and receptacle 36B at the upper end above packer 34A.

The embodiment of FIG. 6 is used in a slightly different manner from that of FIG. 1. When one wishes to use or perform wire-line workover in the apparatus of FIG. 5, first perform steps 1 through 6 described above under procedure I, then we continue with the following Procedure II.

PROCEDURE II

7. Run dual tubing strings and latch onto tubing string receptacles 36A and 36B. The well is now connected for performance or wire-line work.

We shall now consider operational procedures for performing tubing pulling operations of the arrangement of FIG. 6.

PROCEDURE III

First perform operations 1 through 6 described in Procedure I.

7 Run dual tubing strings and connect into tubing strings below blind ram 18.

8. Through the tubing string connected through tubing extension 114 to the annulus, run wire-line tools to open this string to the annulus 115 as by removing the blanking plug from "S" nipple 117A.

9. Through the well tubing string, run tools to close off flow ports 44A in valve 42A and then run suitable tools to open the tubing annulus valve 144 above downhole packer 140.

10. Pump heavy drilling fluid or mud down the tubing string and out through ports 145 with the returns up annulus 115 and up annulus tubing string 117. This will kill the well.

11. Retrieve annulus tubing string 117.

12. With wire-line tools unlatch tubing hanger 28A and release packer 34A and begin pulling the tubing string. Means for pulling the tubing string are located in a nonwater environment connected to the upper end of the riser pipe. Such location is preferably the work deck 176 supported above the body of water.

Attention is next directed to FIG. 7. One way of performing some downhole operations is to pump certain tools down various flow lines to the well and then return them with a back pressure. This requires a minimum of two lines and also requires certain limitations on the bending radius. Various through-the-flowline tools, commonly called TFL tools, are commercially available. The embodiment of FIG. 7 is suitable for use with such TFL tools and also provides means whereby the tubing strings can be pulled or wire line equipment used in the event the TFL tools do not succeed. The primary modification of FIG. 7 from FIG. 1 is between blind ram 18 and tubing hanger 28B. Bore 22A extends between ram 18 and tubing hanger 28B. Mandrel 126 has a first opening 120 and a second opening or port 122. These two ports are closely spaced apart vertically. Port 120 is aligned with conduit 124, likewise port 122 is aligned with conduit 125.

A mandrel 126 having a first vertical conduit 128 and a second vertical conduit 130 is locked into position in bore 22A. This is accomplished by sealing and connecting the lower end of mandrel 126 to tubing hanger 28B. Conduit 130 of mandrel 126 is in fluid communication with production tubing string 132 and conduit 128 is in fluid communication with tubing string 134. One of the bores 128 or 130 is preferably made of sufficient size so that tubing strings 132 or 134, or both, can be run through their respective bore after packer assembly 28B is set. This facilitates running of the equipment into the assembly.

Ports 120 and 122 are aligned respectively with openings of conduits 124 and 125, respectively. This is insured by orienting keys 136. Vertically spaced seals 138, 140, 142 are provided to prevent communication between ports 122 and 120.

FIG. 8 illustrates a downhole tubing arrangement useful for use with the embodiments of FIG. 7. This includes the lower portions of tubing strings 132 and 134; a "Y" joint 146 with its upwardly facing members connecting into tubing 132 and 134. Lower section 148 extends downwardly through downhole annulus packer 150. A landing nipple 147 is provided in section 148 for receiving and positioning a TFL tool. "Y" extension 148 extends down to about the level of perforations 152 in the casing. Tubing string leg 132 has a lower wire-line operated valve 154 which is placed just above "Y" 146 and an upper wire-ine operated valve 156 which is positioned near the surface just below wellhead tubing hanger 28B.

Sometimes it is desirable to perform wire-line workover on wells completed with the system of FIG. 7. This is accomplished by the following operational procedure.

PROCEDURE IV

Perform steps 1 through 6 of Procedure I.

7. Run dual tubing strings and latch onto tubing receptacles 160 and 160A.

8. Remove the blanking plugs from "S"nipples 162 and 162A. Deflector means 164 and 164A are attached to the blanking plugs 163 and 163A and thus are removed when the blanking plugs are removed. As the tubing strings are then free to the surface, conventional wireline operations can be connected therethrough.

Sometimes it is required to work over the tubing which necessitates pulling the strings of tubing. When the well is completed as illustrated in FIG. 7, this can be accomplished by following the following procedure.

PROCEDURE V

Perform steps 1 through 7 described in Procedure IV.

8. Remove the blanking plugs from "S" nipples 162 and 162A. Deflector means 164 and 164A are attached to the blanking plugs 163 and 163A and thus are removed when the blanking plugs are removed.

9. Referring now to FIG. 8, open valve 154 which is just above packer 150 and open valve 156 which is just below the tubing hanger to the annulus. This can be accomplished with either (a) the pumping down of TFL tools in a known manner or (b) first removing blanking plugs and deflectors 164 and 164A.

10. Pump drilling fluid down one string 134. This permits killing the well in a known manner.

11. Unlatch the wellhead mandrel 126 and tubing hanger 28B and begin pulling tubing.

After the workover operations are completed, the riser pipe 112 is removed and cap 26 replaced.

While the above embodiments have been shown with a considerable detail, it is possible to produce other embodiments and modifications thereof without departing from the spirit and scope of the invention.

Claims

We claim:

1. A subsea wellhead completion assembly for mounting on a casing set in a well which comprises:

a tubing hanger means anchored with respect to said casing;

a tubing string suspended in the well from said tubing hanger means;

a wellhead control assembly extending above said tubing hanger and forming a vertical bore therein;

a tubing extension member extending upwardly from said tubing hanger and in fluid communication with said string of tubing;

means sealing the annular space between the upper end of said tubing extension and the inner wall of said bore;

lateral outlet means on said wellhead control assembly;

valve means in said tubing extension for establishing fluid communication between the interior thereof and said outlet means;

closure means for the top of said wellhead assembly, said closure means includes:

a utility stub placed on the top of said wellhead assembly;

a cap means sealingly fitted within said utility stub, said cap having an internal bore with internal latching grooves therein;

latching means for releasably latching said cap to said utility stub; the top of said tubing extension being provided with means for connecting into a tubing string.

2. An apparatus as defined in claim 1 in which said tubing extension includes a removable valve in the upper end thereof.

3. An apparatus as defined in claim 1 including a removable wire-line operable valve in the upper end of said tubing extension member.

4. A subsea wellhead completion apparatus in which casing has been set in the earth beneath a body of water which comprises:

a first blowout preventer means connected to the upper end of said casing;

an outlet spool having a lateral outlet and connected to the top of said first blowout preventer;

a second blowout preventer means connected to the upper side of said outlet spool;

a utility stub connected above said second blowout preventer means, there being formed a vertical bore through said first blowout preventer means, said outlet spool, said second blowout preventer means, and said utility stub;

a tubing hanger in said casing and having a string of tubing extending downwardly therefrom;

a tubing extension means extending from said tubing hanger upwardly in said bore, said tubing extension having a valve therein which can be opened from the surface, the upper end of said tubing extension having a receptacle for tubing connection, said receptacle being below said second blowout preventer means;

sealing means just below said receptacle of said tubing extension means and sealing the annular space between the tubing extension and the wall of said bore;

removable cap means in the upper end of said utility stub;

and means on the upper end of said utility stub for aiding in guiding a member into said stub.

5. A subsea wellhead completion assembly for mounting on casing set in a well which comprises:

a vertical housing means having a vertical bore therethrough and aligned with said casing;

upper remotely operated valve means for closing the said vertical bore;

a tubing hanger means anchored with respect to said casing;

a tubing string suspended in the well from said tubing hanger means;

a tubing extension mandrel means extending upwardly from said tubing hanger into said vertical bore, said mandrel means including means sealing the mandrel means with the wall of said bore below said upper closure means;

lateral outlet means on said housing means and including means establishing fluid communication with the interior of said tubular extension mandrel means;

removable means closing the upper end of said tubing extension mandrel means;

cap means closing the upper end of said vertical bore above said upper remotely operated valve means.

6. An assembly as defined in claim 5 in which said tubing extension mandrel has two vertical bores therethrough said lateral outlet means includes two outlets communicating independently with said vertical conduits of said tubing extension mandrel, said outlets being curved to accommodate through-the-flowline tools.

7. A subsea wellhead assembly as defined in claim 5 including a riser pipe in sealed fluid communication with the bore of said housing, said riser pipe extending to a nonwater environment so that well operations can be conducted through said riser pipe.

8. A method of working over a subsea well having a vertical housing closed at the top and having a lateral outlet therein and tubing suspended within the well bore and connected to said lateral outlet, the method which comprises:

opening the top of said housing;

directing one end of a riser pipe to the top of said housing;

connecting said riser pipe to the top of said housing;

connecting said tubing to a nonwater environment through a conduit in said riser pipe;

closing said lateral outlet;

thereafter removing said tubing from said well through said riser pipe.

9. A method as defined in claim 8 including the step of killing the said well by pumping a killing fluid from said nonwater environment through said tubing to said well.

10. A subsea wellhead completion assembly for mounting on casing set in a well which comprises:

a vertical housing means having a vertical bore therethrough and aligned with said casing;

upper closure means for closing the said vertical bore;

a tubing hanger means anchored with respect to said casing;

a tubing string suspended in the well from said tubing hanger means;

a tubing extension mandrel means extending upwardly from said tubing hanger into said vertical bore, said mandrel means including means sealing the mandrel means with the wall of said bore below said upper closure means;

lateral outlet means on said housing means and including means establishing fluid communication with the interior of said tubular extension mandrel means;

removable means closing the upper end of said tubing extension mandrel means;

a first blowout preventer positioned just above the tubing hanger and a second blowout preventer means positioned above said tubing extension mandrel.

11. An assembly as defined in claim 10 in which said housing means includes at its upper end

a utility stub;

a cap means having an internal bore with an internal groove therein releasably latched to the upper end of said utility stub;

said assembly further including;

fluid control conduits in the wall of said stub which include extensions from such conduits to said first and second blowout control means;

a riser pipe extending from said utility stub to a nonwater environment, the wall of said riser pipe having control conduits for mating with the control conduits of said utility stub;

orienting means on said riser pipe and said utility stub for securing proper alignment between the control fluid conduits of said riser pipe and those of said utility stub.

12. A method of working over a subsea well having a vertical housing closed at the top and having a lateral outlet therein and tubing suspended within the well bore and connected to said lateral outlet, the method which comprises:

opening the top of said housing;

directing one end of a riser pipe to the top of said housing;

connecting the upper end of said riser pipe to a spar buoy and adjusting the ballast in said buoy to place said riser pipe in tension; and

performing workover operations from a nonwater environment through said riser pipe and said tubing.