Particular relating to subsea well construction

Abstract

A method is for constructing a subsea well and an associated unit. The method may include: providing a unit having at least one component of a flow control assembly, the flow control assembly to be operable for controlling a flow of injection or production fluid during operation of the well after the well has been constructed; lowering the unit through sea toward a seabed; receiving part of the unit in a subsurface of the seabed to anchor the unit in place, part of the unit projecting above the seabed, whereby the component of the flow control assembly is positioned in the projecting part; and performing at least one well construction operation through a bore in the unit.

Claims

1. A method of constructing a subsea well, the method comprising the steps of: providing a unit comprising: at least one component of a flow control assembly, the flow control assembly to be operable for controlling a flow of injection or production fluid during operation of the well after the well has been constructed; a suction caisson or anchor; and end-to-end connected first and second tubular bodies, the first tubular body having an aperture in a wall for transmitting the injection or production fluid between a flow line section and an inside of the first tubular body during operation of the well after the well has been constructed, and the first tubular body further having at least one casing or liner hanger profile for hanging casing or liner from the first tubular body, the second tubular body being connected to the suction caisson or anchor; lowering the unit through sea toward a seabed; receiving the suction caisson or anchor in a subsurface of the seabed to anchor the unit in place, part of the unit projecting above the seabed, whereby said component of the flow control assembly is positioned in the projecting part; and performing at least one well construction operation through a bore in the unit.

2. The method as claimed in claim 1, wherein providing the unit includes flange-to-flange connecting between the first and second tubular bodies.

3. The method as claimed in claim 1, wherein the second tubular body comprises at least one of a spool body and spool body extension which extends vertically from an upper end of the suction caisson or anchor upon anchoring the unit in place.

4. The method as claimed in claim 1, wherein the component of the flow control assembly comprises the flow line section for transmitting production or injection fluid away from or into a wellbore of the well.

5. The method as claimed in claim 1, wherein the component of the flow control assembly comprises at least one valve or part thereof.

6. The method as claimed in claim 1, wherein the component of the flow control assembly comprises a master inner valve and a master outer valve disposed on the flow line section, the flow line section extending radially outwardly from an exterior of the first tubular body.

7. The method as claimed in claim 1, wherein the component of the flow control assembly comprises at least one of: a choke valve; a crossover valve; a crossover line; an external circulation line; and an annulus master valve.

8. The method as claimed in claim 1, wherein the component of the flow control assembly includes the flow line section, and the flow line section includes a temperature sensor or a pressure sensor.

9. The method as claimed in claim 1, wherein the bore through which the well construction is to be performed is a first, main bore and the first tubular body further includes a second bore through the wall of the first tubular body for obtaining communication with an annulus in a wellbore of the subsea well.

10. The method as claimed in claim 1, which further comprises connecting the following to the unit: at least one isolation valve to selectively open or close the bore above the first tubular body or above the aperture; and a mandrel to be positioned above the isolation valve for connecting a blowout preventer or a riser to an upper end of the mandrel.

11. The method as claimed in claim 10, wherein the mandrel is an 18¾ inch mandrel.

12. The method as claimed in claim 1, which further comprises anchoring the unit in place by securing the suction caisson or anchor received in the subsurface by applying suction.

13. The method as claimed in claim 1, wherein the step of performing the well construction operation comprises: running at least one casing or liner through the bore in the unit; and hanging the casing or liner from the casing or liner hanger profile.

14. The method as claimed in claim 1, wherein the first tubular body of the unit further comprises at least one tubing hanger profile, and the method further comprises: running at least one tubing through the bore in the unit; and hanging the tubing from the tubing hanger profile.

15. The method as claimed in claim 1, wherein performing the well construction operation comprises running a drill string through the bore in the unit and drilling a section of a wellbore of the well using the drill string.

16. The method as claimed in claim 15, wherein the drilling is performed to drill a hole in the subsurface with a diameter of 17.5 inches or more.

17. The method as claimed in claim 1, wherein performing the well construction operation comprises running a section of casing or liner into the subsurface through the bore in the unit.

18. The method as claimed in claim 16, which further comprises cementing the section of casing or liner by delivering cement or curable mass into the subsurface through the bore in the unit.

19. The method as claimed in claim 1, wherein the unit further comprises a tubular protector or wear bushing which is removably inserted to line the bore in the unit, and the method further comprises removing the protector or wear bushing to allow the flow control assembly to be operated in the production or injection phase of the constructed well.

20. A unit for constructing and operating a subsea well, the unit comprising: at least one component of a flow control assembly, the flow control assembly to be operable for controlling a flow of injection or production fluid in a flow line during operation of the well after the well has been constructed; at least one part configured to be received in a subsurface of the seabed for anchoring the unit in place, comprising a suction caisson or anchor; a stack of assembled parts comprising end-to-end connected first and second tubular bodies, the first tubular body comprising a tubular main body having an aperture in a wall of the body for transmitting injection or production fluid between a flow line of the flow control assembly and an inside of the main body, and at least one casing or liner hanger profile for hanging casing or liner, the second body being connected to the suction caisson or anchor; and a bore through which at least one well construction operation can be performed, the bore extending through the stack; wherein the unit is configured so that it can be lowered in a single package toward the seabed and anchored in place through receiving said part of the unit in the subsurface.

21. The unit as claimed in claim 20, wherein the stack of assembled parts includes at least one of: a wear bushing located inside the bore to line the bore; at least one isolation valve to selectively open or close the bore above the main body or above the aperature; and a mandrel to be positioned above the isolation valve for connecting a blow out preventer or a riser to an upper end of the connector mandrel.

22. The unit as claimed in claim 21, wherein the second tubular body comprises a tubular interface spool.

23. The unit as claimed in claim 21, which includes a flange-to-flange connection between the first and second tubular bodies.

24. The unit as claimed in claim 21, wherein the component of the flow control assembly comprises a flow line section, a master inner valve, and a master outer valve disposed on the flow line section, the flow line section extending radially outwardly from an exterior of the first tubular body.

25. A method of providing a unit to be deployed for constructing and operating a subsea well, the unit comprising: at least one component of a flow control assembly, the flow control assembly to be operable for controlling a flow of injection or production fluid in a flow line during operation of the well after the well has been constructed; at least one part configured to be received in a subsurface of the seabed for anchoring the unit in place, comprising a suction caisson or anchor; a stack of assembled parts comprising end-to-end connected first and second tubular bodies, the first tubular body comprising a tubular main body having an aperture in a wall of the body for transmitting injection or production fluid between a flow line of the flow control assembly and an inside of the main body, and at least one casing or liner hanger profile for hanging casing or liner, the second body being connected to the suction caisson or anchor; and a bore through which at least one well construction operation can be performed, the bore extending through the stack; wherein the unit is configured so that it can be lowered in a single package toward the seabed and anchored in place through receiving said part of the unit in the subsurface; the method comprising: prior to deployment, assembling parts together to form the unit.

26. A method of constructing a subsea well, the method comprising: running a section of casing into the subsurface through a bore in a subsea unit for constructing and operating a subsea well, the unit comprising: at least one component of a flow control assembly, the flow control assembly to be operable for controlling a flow of injection or production fluid in a flow line during operation of the well after the well has been constructed; at least one part configured to be received in a subsurface of the seabed for anchoring the unit in place, comprising a suction caisson or anchor; a stack of assembled parts comprising end-to-end connected first and second tubular bodies, the first tubular body comprising a tubular main body having an aperture in a wall of the body for transmitting injection or production fluid between a flow line of the flow control assembly and an inside of the main body, and at least one casing or liner hanger profile for hanging casing or liner, the second body being connected to the suction caisson or anchor; and a bore through which at least one well construction operation can be performed, the bore extending through the stack; wherein the unit is configured so that it can be lowered in a single package toward the seabed and anchored in place through receiving said part of the unit in the subsurface; and the flow control assembly to be operable for controlling a flow of injection or production fluid in a flow line during operation of the well after the well has been constructed.

27. A method as claimed in claim 26, which further comprises running a drill string through the bore and drilling at least one section of a wellbore of the well using the drill string.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) In the following there will be described, by way of example only, embodiments of the invention with reference to the accompanying drawings, in which:

(2) FIG. 1 illustrates an apparatus for performing at least one operation to construct a well subsea;

(3) FIG. 2 shows a portion of the apparatus of FIG. 1, prior to insertion of a bore protector;

(4) FIG. 3 shows the portion of the apparatus of FIG. 1 comprising the bore protector;

(5) FIG. 4 shows the portion of the apparatus of FIG. 2 comprising a wear bushing;

(6) FIG. 5 shows the apparatus comprising a suction caisson, an interface spool and a protective structure, as the apparatus is lowered to a seabed;

(7) FIG. 6 shows the apparatus installed in a seabed, with the suction caisson forming a foundation;

(8) FIG. 7 shows the apparatus having been installed in the sea floor, with a hatch of the protective structure having been closed;

(9) FIG. 8 shows the apparatus in place in the seabed, with the protective structure opened;

(10) FIG. 9 shows the apparatus including a B annulus line;

(11) FIG. 10 shows a subsea drilling system for drilling exploration wells; and

(12) FIG. 11 is a flow diagram showing a method of constructing and operating a well according to an embodiment of the invention.

DETAILED DESCRIPTION OF THE DRAWINGS

(13) FIG. 1 illustrates an example apparatus 1 for performing at least one operation to construct a well subsea.

(14) The apparatus 1 is arranged with a bore 100, a flow line 200, an external circulation line 300, and a crossover line 400. The flow line 200, the external circulation line 300 and the crossover line 400 all form flow paths from the bore 100.

(15) The flow line 200 comprises a production master inner valve 203 and a production wing valve 204, which are both fail-safe valves. Furthermore, the flow line 200 comprises a production bore pressure and temperature sensor 205, enabling reading of pressure and temperature between the production master inner valve 203 and the production wing valve 204. The flow line further comprises a flow line connector 206, for connecting to an external flow line. The flow line 200 is connected to the main bore of the apparatus 1, such that a flow path is formed from the main bore 100 to and from the flow line 200.

(16) The external circulation line 300 and the crossover line 400 shares a fail-safe annulus master valve 15 and an annulus bore pressure and temperature sensor 14, enabling reading of pressure and temperature in the lines 300, 400. The line shared by the external circulation line 300 and the crossover line 400 may be referred to as an annulus line. The annulus line comprises a bore 3 through a wall of a body 2 of the apparatus 1. Through the bore 3 through the body 2 of the apparatus 1, the annulus line connects to the main bore 100 of the apparatus 1. The crossover line 400 further comprises a crossover valve 404.

(17) The external circulation line 300 comprises an ROV valve stab receptacle 301 comprising a male hot-stab receiver 303 and a female hot-stab receiver 302. As there may be a need for a double barrier between the end of the external circulation line 300 leading into the bore 100 and the end of the external circulation line 300 adapted to receive an ROV, this example comprises a not shown failsafe barrier valve comprised by the ROV valve stab receptacle 303.

(18) The apparatus 1 in this example further comprises an mandrel 9 which may be an 18¾″ mandrel with H4 profile, for forming an interface to a drilling BOP or a Cap connector or other equipment and a full-bore isolation valve 10 for isolating the main bore 100,

(19) Furthermore, the apparatus 1 comprises a control line system 500 comprising an ROV valve stab receptacle 501, a male hot-stab receiver 503 and a female hot-stab receiver 502, three control lines 507 and three tubing hanger down hole line seals 510 for sealing off down hole tubing hanger ports.

(20) The apparatus 1 further comprises an inductive downhole line pressure sensor system 600, for reading pressure on downhole sensors. The system comprises means for inductive communication for sending power to and sending and/or receiving signals from a not shown downhole gauge system.

(21) Furthermore, the apparatus comprises an upper tubing hanger seal 5 and a lower tubing hanger seal 6, providing a sealing system for sealing off the flow line 200.

(22) The apparatus further comprises a concentric tubing hanger 19, for forming an interface between production outlet and production tubing, latching grooves 11 for enabling casing hanger latching rings to lock casings to the apparatus 1, an upper casing hanger 13 and a lower casing hanger 12, and two casing hanger seal and lock assemblies 18 for enabling hangers to be locked and sealed to the apparatus 1.

(23) FIG. 2 is included to show an example of the apparatus 1, prior to insertion of a bore protector into the bore 100. FIG. 3 shows the same example of the apparatus 1, wherein the apparatus 1 comprises the bore protector 101. The bore protector 101 may be inserted into the bore 100 to protect it and particularly sensitive equipment connected to the bore 100 from being polluted or otherwise damaged by drilling or cementing operations being performed through the bore 100. The bore protector 101 may be a wear bushing 102, as illustrated in FIG. 4. A wear bushing 102 is a type of bore protector 101 having a slightly smaller diameter than the bore protector 101. Wear bushings 102 are typically chosen to fit the size of drill bit to be used or casing or tubing to be installed through the bore 100.

(24) FIG. 5 shows an example of the apparatus 1 comprising a suction caisson 31, an interface spool 700, a protective structure 800 and a lifting cap 25. The lifting cap 25 is fitted onto the 18¾″ H4 mandrel with a H4 profile 9. FIG. 5 further shows a wireline 70 connected to the lifting cap 25, for lowering the apparatus 1 onto a seabed 80.

(25) The protective structure 800 comprises a hatch 801 that can be open or closed. In the scenario illustrated in FIG. 5 it is open for allowing the wireline 70 to be connected to the lifting cap 25.

(26) The interface spool 700 mates a main body 2 of the apparatus 1 to the suction caisson 31. The suction caisson 31 is arranged to form a foundation for the apparatus 1, and to carry structural loads such as vertical loads, horizontal loads and torque, and the interface spool 700 is arranged to transfer such loads from the main body 2 of the apparatus 1 to the suction caisson 31 foundation. The interface spool comprises two pipes forming two outlets 701 for cement returns for routing cement onto the seabed 80 during cementing operations. The outlets 701 allow cement returns to flow onto the seabed 80 instead of returning into the apparatus 1, which may be beneficial e.g. to avoid pollution of the bore and sensitive equipment comprised by the apparatus 1, such as valves and latches.

(27) The protective structure 800 forms a protective shield for the apparatus against the subsea environment.

(28) FIG. 6 shows the apparatus 1 when installed in the seabed 80. The suction caisson 31 has sucked into the seabed 80 and created a foundation for the apparatus 1.

(29) FIG. 7 shows an example of the apparatus 1 installed in the seabed 80, wherein the wireline has been disconnected from the apparatus and the hatch 801 of the protective structure 800 has been closed.

(30) FIG. 8 illustrates the protective structure 800 that may be opened more completely than just by opening a hatch. The protective structure 800 is pivotally connected to the suction caisson 31, and may pivot so that it opens up for a more complete access to the apparatus 1 for external equipment, for maintenance, for manipulation of the system, or for other reasons.

(31) FIG. 9 shows the apparatus 1 comprising a B annulus line 900 for monitoring fluid characteristics in and/or bleeding off pressure from and/or circulating fluid in and/or for injecting cement into an annulus in a well. The annulus line 900 comprises a bore 901 through a wall of a body 2 of the apparatus 1. Furthermore, the annulus line comprises a pressure and temperature sensor 905 between two valves 902, 903, and an ROV hot-stab receptacle 904.

(32) FIG. 10 shows a subsea drilling system 1000 for drilling exploration wells, wherein the drilling system comprises a suction caisson 31, an interface spool 700 and a high-pressure mandrel 1001 arranged to form an interface between the subsea system and a not shown drilling blowout preventer and/or a not shown Christmas tree. The interface spool 700 comprises cement outlets 701.

(33) With reference to FIG. 11, steps of a method 2000 of constructing a subsea well are denoted S1 to S5.

(34) At S1, a unit is provided by assembling parts as necessary. The unit has a component of a flow control assembly, e.g. a valve for controlling a flow of fluid in a flow line transmitting injection fluid or production fluid. Conveniently also, the unit has part such as a suction caisson or other member which is arranged to be inserted into the subsurface to anchor the unit in place.

(35) At S2, once the unit is assembled and ready to be installed, it is deployed into the sea. The unit is lowered through the sea toward the seabed.

(36) At S3, part of the unit, e.g. the suction caisson or other member that penetrates into the seabed, is received in the subsurface below the seabed and the unit is anchored in position. When anchored in position, part of the unit projects upward, and the component of the flow assembly is supported and located in the part projecting above the seabed. The anchoring may be facilitated by applying suction to the suction caisson and/or cementing the suction caisson or other member that penetrates the seabed in place.

(37) Embodiments of the apparatus as exemplified in FIGS. 5 to 9 may constitute a unit of the kind referred to in relation to FIG. 11. The term “unit” here is used to indicate its unitary nature as a whole particuary in relation to the installation phase, in the sense that although it may have a collection of discrete or interconnected constituent parts, the unit is capable of being deployed, lowered and brought to the seabed in a single package or object that is to be anchored in place. Thus, the apparatus 1 of FIGS. 5 to 9, or any other apparatus of the various aspects of the invention described herein, may alternatively be termed a “unit” in this same sense.

(38) This approach of providing and making use of the unit such as in the example of FIG. 11 or FIGS. 5 to 9 can advantageously allow components both for operation of the well in an injection or production phase of the well and for constructing the well to be installed simultanesously. This can provide benefits in time saving and process optimisation.

(39) At S4, a well construction operation is performed through a bore in the unit once anchored. This operation can be for example running drill string through the bore and drilling a section of a wellbore of the well, running casing through the bore, hanging casing on a hanger profile in the bore, and cementing the casing in place by delivering cement through the bore in the unit. The operations may be repeated section-by-section to advance the borehole into the subsurface and line a wall of the wellbore.

(40) At S5, the well is completed e.g. once the wellbore has been drilled and cased to the desired depth. The completion includes running in production or injection pipe into a target section of the wellbore. Furthermore, production or injection tubing is run in through the bore in the unit into the wellbore. The tubing is hung from a tubing hanger profile in the bore, e.g. in a tubular body of the unit. The tubing fluidly connects with the flow line of the flow control assembly through the aperture in the wall of the tubular main body of the unit in the part of the unit which projects above the seabed.

(41) At S6, once the well has been constructed and completed, the well is operated. In order to do so, a wear bushing or other removable sheath may be removed from the bore in the unit to allow communication through a wall of the bore of the unit with a flow line for transmitting injection fluid or production fluid, depending on whether the well is a production well or an injection well. Various valves in the unit may be operated to configure a flow path connecting the flow line with the tubing wellbore. The flow control assembly is used to control the flow in the flow line to operate the well. In the case of production, the tubing conveys production fluid toward surface and out of the wellbore for onward processing via the flow line. In the case of the well being an injection well, the tubing conveys injection fluid from the flow line downhole into the well where it is injected into the formation.

(42) In order to provide the unit in step S1, various parts may be assembled together to form the unit, typically onshore, on a rig or platform above seasurface, or other convenient location. In particular, the assembly step includes connecting a first tubular bore section, e.g. that extending through the main body, and a second tubular bore section end-to-end to obtain the bore in the unit through which the well construction operation is to be performed. By way of the connection the first tubular bore section may be connected to the part of the unit, e.g. the suction caisson or other member, which is to be received in the subsurface to anchor the unit in place. The end to end connection may be formed by making up a flanged joint between the sections.

(43) Note that the drawings are shown highly simplified and schematic and the various features therein are not necessarily drawn to scale. Identical reference numerals refer to identical or similar features in the drawings.

(44) It should further be noted that the above-mentioned embodiments illustrate rather than limit the invention, and that those skilled in the art will be able to design many alternative embodiments without departing from the scope of the appended claims. In the claims, any reference signs placed between parentheses shall not be construed as limiting the claim. Use of the verb “comprise” and its conjugations does not exclude the presence of elements or steps other than those stated in a claim. The article “a” or “an” preceding an element does not exclude the presence of a plurality of such elements.

(45) The mere fact that certain measures are recited in mutually different dependent claims does not indicate that a combination of these measures cannot be used to advantage.

(46) Although certain parts of the description above refers to a production well and a flow line for transmitting hydrocarbon production fluid away from wellbore, in other variants the constructed well may be an injection well and the flow assembly may be used to control the flow of injection fluid into the wellbore through the flow line. Features referring to “production” may therefore in the case of an injection well be taken to be referring to “injection”.