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Title:
AN APPARATUS FOR FORMING AT LEAST A PART OF A PRODUCTION SYSTEM FOR A WELLBORE, AND A LINE FOR AN A METHOD OF PERFORMING AN OPERATION TO SET A CEMENT PLUG IN A WELLBORE
Document Type and Number:
WIPO Patent Application WO/2018/143825
Kind Code:
A1
Abstract:
There is described an apparatus (1) for forming at least a part of a production system for a wellbore (50), and a related passageway (300, 900) for transmitting cement, method of performing an operation to form a cement plug in a wellbore (50), and a body (2) for an apparatus (1) for forming at least part of a production system for a wellbore (50). In an embodiment, the apparatus (1) comprises: a main, first bore (100) comprising at least one tubing hanger profile (11) for suspending a casing from the main bore (100), the casing to be suspended in the wellbore (50) and to define an annulus (115, 125) in the wellbore (50); and a second bore (3) for communicating with the annulus (115, 125) for receiving cement from or supplying cement into the annulus (115, 125).

Inventors:
LØVOLL, Thor Andre (Aurikkelstien 2, 4022 STAVANGER, 4022, NO)
KROSSNES SCHMIDT, Bjørn (Rygjaveien 17c, 4020 STAVANGER, 4020, NO)
MADSEN, Sigbjørn (Raunen 19, 4158 Bru, 4158, NO)
Application Number:
NO2018/050033
Publication Date:
August 09, 2018
Filing Date:
February 06, 2018
Export Citation:
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Assignee:
NEW SUBSEA TECHNOLOGY AS (Professor Olav Hanssens Vei 7a, 4021 STAVANGER, 4021, NO)
International Classes:
E21B33/13; E21B33/035; E21B33/05
Attorney, Agent or Firm:
HÅMSØ PATENTBYRÅ AS (P.O. Box 171, 4301 Sandnes, 4301, NO)
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Claims:
C l a i m s

1 . An apparatus (1 ) for forming at least a part of a production system for a wellbore (50), the apparatus (1 ) comprising :

a main, first bore (100) comprising at least one tubing hanger profile (1 1 ) for suspending a casing from the main bore (1 00), the casing to be suspended in the wellbore (50) and to define an annulus (1 15, 125) in the wellbore (50); and

a second bore (3) for communicating with the annulus (1 15, 125) for receiving cement from or supplying cement into the annulus (1 15, 125).

2. The apparatus (1 ) according to claim 1 , wherein the main bore (1 00) comprises a throughbore through the apparatus (1 ), and the second bore (3) extends from the main bore (100) through a wall of the apparatus (1 ).

3. The apparatus (1 ) according to claim 1 or 2, wherein the second bore (3) extends substantially radially from the main bore (100) through the wall of the apparatus (1 ), with respect to the main bore (1 00).

4. The apparatus (1 ) according to any one of the preceding claims, wherein the apparatus (1 ) further comprises at least one tubing hanger profile (1 9), in the main bore (100), for suspending a production tubing from the tubing hanger profile (1 9), and wherein:

the second bore (3) extends through a wall of the apparatus (1 ) at a position in use below the tubing hanger profile (1 9) in the main bore (100); and

the tubing hanger profile (1 1 ) is arranged in use below the tubing hanger profile (19) in the main bore (1 00).

5. The apparatus (1 ) according to claim 4, wherein the apparatus (1 ) further comprises:

at least one further profile (12), in the main bore (100), for suspending a further casing from the further profile (12) ; and

a third bore (901 ), configured to allow cement to be transmitted through the third bore (901 ) during an operation to form a cement plug in the wellbore (50), and wherein: the further profile (12) is arranged in use below the tubing hanger profile (19) in the main bore (100); and

the third bore (901 ) extends through the wall of the apparatus (1 ) from a position in use below the tubing hanger profile (19) in the main bore (100).

6. The apparatus (1 ) according to claim 6, wherein the further profile (12) is a second casing hanger profile (1 1 ).

7. The apparatus (1 ) according to claim 6 or 7, wherein the third bore (901 ) extends substantially radially from the main bore (100) through a wall of the apparatus (1 ), with respect to the main bore (100).

8. The apparatus (1 ) according to any one of claims 6 to 8, wherein:

the third bore (901 extends through the wall of the apparatus (1 ) from a position in use below the tubing hanger profile (1 1 ) in the main bore (100); and

the further profile (12) is arranged in use below the tubing hanger profile (1 1 ) in the main bore (100).

9. The apparatus (1 ) according to any one of the preceding claims, wherein the second bore (3) is a bore for establishing a fluid path to an A annulus (1 15) of the subsea production system.

10. The apparatus (1 ) according to any one of claims 4 to 10, wherein the third bore (901 ) is a bore for establishing a fluid path to a B annulus (125) of the subsea production system.

1 1 . The apparatus (1 ) according to any one of the preceding claims, wherein a tubing is suspended from the tubing hanger profile (19) and a first casing is suspended from the tubing hanger profile (1 1 ).

12. The apparatus (1 ) according to any one of claims 4 to 12, wherein a further casing is suspended from the further profile (12).

13. The apparatus (1 ) according to any one of the preceding claims, wherein the apparatus (1 ) comprises a fourth bore (21 1 ) for transferring a produced fluid from the main bore (100) of the production system, and wherein the fourth bore (21 1 ):

extends substantially radially from the main bore (100) through a wall of the apparatus (1 ); and

is arranged in use above the tubing hanger profile (19) in the main bore (100).

14. The apparatus (1 ) according to claim 13, wherein the apparatus (1 ) comprises a body (2), made by forging, wherein the body (2) comprises all of the main bore (100), the second bore (3), the third bore (901 ), the fourth bore (21 1 ), the tubing hanger profile (19), the casing hanger profile (1 1 ) and the further profile (12).

15. A passageway (300, 900) for transmitting cement, the passageway (300, 900) being configured for receiving cement from or supplying cement into an annulus (1 1 5, 125) of a wellbore (50) which is provided with an apparatus (1 ) for forming at least a part of a production system for the wellbore (50), wherein the passageway (300, 900) comprises a bore (3, 901 ) extending substantially radially through a wall of the apparatus (1 ) with respect to a main bore (100) of the apparatus (1 ).

16. The passageway (300) according to claim 15, wherein the annulus (1 15) is an A annulus (1 15) of the wellbore (50).

17. The passageway (300) according to claim 15 or 16, wherein the bore extends from a position between a tubing hanger profile (19) and a tubing hanger profile (1 1 ) in the main bore (100).

18. The passageway (900) according to claim 15, wherein the annulus (125) is a B annulus (125) of the wellbore (50).

19. The passageway (300, 900) according to claim 16, wherein the bore extends from a position between a tubing hanger profile (1 1 ) and a further profile (12) for suspending a casing in the main bore (100).

20. The passageway (300, 900) according to any one of claims 15 to 19, wherein the passageway (300, 900) further comprises at least one device (14, 905) for obtaining data relating to a parameter of a fluid.

21 . The passageway (300, 900) according to claim 20, wherein the passageway (300, 900) comprises a first device (14, 905) for obtaining data on a temperature of a fluid and a second device (14, 905) for obtaining data on a pressure of the fluid.

22. The passageway (300, 900) according to any one of claims 15 to 21 , wherein the passageway (300, 900) further comprises at least one valve (15, 404, 902, 903) for blocking the passageway (300, 900).

23. The passageway (300, 900) according to any one of claims 15 to 22, wherein the passageway (300, 900) further comprises a connection means (301 , 904) for connecting to a device external of the apparatus (1 ) and the passageway (300, 900).

24. The passageway (300, 900) according to claim 23, wherein the connection means (301 , 904) comprises a connection means (301 , 904) for a hot-stab connection.

25. The passageway (300, 900) according to claim 24, wherein the connection means (301 , 904) comprises a valve.

26. The passageway (300, 900) according to any one claims 15 to 25, wherein the passageway (300, 900) is connected to a production flowline (200) of the apparatus (1 ).

27. A method of performing an operation to form a cement plug, e.g. during a Plug- and-Abandonment operation, in a wellbore (50) provided with an apparatus (1 ) according to any one of claims 1 to 13, the apparatus (1 ) comprising:

a main, first bore (100) comprising a production bore (1 95) and at least one annulus (1 15, 125), the first bore (100) being a throughbore through the apparatus (1 ); and a second bore (3) extending from the main bore (100) through a wall of a body (2) of the apparatus (1 ) ;

the method comprising the step of transmitting cement to or from an annulus (1 1 5, 125) of the wellbore (50) through the second bore (3).

28. The method according to claim 27, further comprising the step of establishing a flow path between the production bore (195) and the annulus (1 15, 125) of the wellbore (50) by creating an opening through a wall of a tubing (191 ) and/or a casing (1 1 1 , 121 ) of the wellbore (50).

29. The method according to claim 27 or 28, further comprising the step of circulating a fluid through a part of the wellbore (50) to clean the part of the wellbore (50), utilizing a flow path between the production bore (195) and an annulus (1 15, 125) of the wellbore (50) to circulate the fluid.

30. The method according to any one of claims 27 to 29, further comprising the step of forming a plug (1 97) in the wellbore (50) to isolate a reservoir.

31 . The method according to any one of claims 27 to 30, further comprising the step of collecting cement returns from the second bore (3).

32. The method according to any one of claims 27 to 31 , further comprising the step of analysing a quality of cement returns from the wellbore (50).

33. The method according to any one of claims 27 to 32, further comprising the step of substantially filling an annulus (1 15, 125) with cement to set an abandonment plug in the annulus (1 15, 125).

34. The method according to any one of claims 27 to 33, wherein the apparatus (1 ) further comprises a third bore (901 extending from the main bore (100) through a wall of a body (2) of the apparatus (1 ), the method further comprising the step of transmitting cement to or from a B annulus of the wellbore (50) through the third bore (901 ).

35. The method according to claim 34, further comprising the step of establishing a flow path between the production bore (195) and the B annulus (125) of the wellbore (50) by creating an opening between the production bore (195) and the B annulus (125) in the wellbore (50).

36. A body (2) for an apparatus (1 ) for forming at least part of a production system for a wellbore (50), wherein the body (2) comprises all of the main bore (100), the second bore (3), the third bore (901 ), the fourth bore (21 1 ), the tubing hanger profile (1 9), the casing hanger profile (1 1 ) and the further profile (12).

37. The body (2) according to claim 36, wherein the body (2) is made by forging.

38. The body (2) according to any one of claims 36 or 37, wherein the apparatus (1 ) is the apparatus (1 ) according to claim 1 .

Description:
AN APPARATUS FOR FORMING AT LEAST A PART OF A PRODUCTION SYSTEM FOR A WELLBORE, AND A LINE FOR AND A METHOD OF PERFORMING AN OPERATION TO SET A CEMENT PLUG IN A WELLBORE

The present invention relates in particular to an apparatus for forming at least a part of a production system for a wellbore. The invention further relates to a line for performing an operation to set a cement plug in a wellbore and a method of performing an operation to set a cement plug in a well- bore.

Using subsea systems is well known in the petroleum industry. With advancements in technology, it is becoming increasingly common to use such systems for exploring, developing and producing hydrocarbons from oil and/or gas fields. These subsea systems can replace systems that were previously typically placed on platforms, doing so in a reliable, safe and cost-efficient manner. Using subsea systems is particularly advantageous in deep waters and/or remote locations, but can also offer cost-efficient solutions elsewhere.

Conventionally, subsea well drilling and production systems consist of multiple mechanical components with specific design features with low level of integration and optimization both for manufacturing and installation. To install a conventional subsea drilling and production system, it is usually required to run multiple independent installation steps, where several independent components of the subsea system are installed individually throughout a well construction process. The systems are generally not optimized with respect to interfaces to allow for more efficient installation sequences and/or choices of installation methods.

As a subsea well drilling and production system is installed, and a wellbore is developed, cementing is an important part of the process. Casing and tubing strings are installed during the wellbore development. For each casing or tubing string installed, there is created an annulus between the string and either the prior string, or, if it is the first string installed, between a ground formation and the string. After the installation of a string, the resulting annulus is typically filled at least in part by cement, e.g. to avoid influx of fluid into the annulus.

Furthermore, cementing may be performed post installation, during the lifetime of a wellbore, to isolate certain zones, or as part of a decommission of a wellbore, as part of a plug-and-abandonment operation. Conventionally, cementing is performed through a production bore of a subsea system. Often, setting a plug that is according to the requirements, that covers a zone in one or more annul i, may be challenging. The operations may involve not only perforation of a casing, but cutting and removal of a casing and/or tubing of significant size. The inventions presented herein offers an advantageous apparatus for and method of performing an operation to set a cement plug in a wellbore. This text further describes an apparatus for performing at least one operation to construct a well subsea and a method for constructing a well.

When this text refers to a conventional subsea system, it refers to a typical subsea system known to a person skilled in the art of installing such systems.

A typical installation sequence for a conventional subsea system is as follows:

A foundation is installed. This is done by drilling a hole with a diameter of 36 inches, 60 to 80 meters deep, vertically from the seabed. A conductor with a diameter of 30 inches is run into the hole. The conductor has a length such that, when a first end of the conductor reaches the bottom of the hole, an opposite end extends approximately two meters above the seabed. The end portion extending above the seabed is arranged with a low-pressure wellhead housing. The low-pressure wellhead housing has typically been arranged to the conductor aboard the drilling rig or drilling vessel which is required for this foundation installation. To finalize the foundation, the conductor is cemented in place.

The next step is to install a surface casing and a high-pressure wellhead housing. A hole with a diameter of 26 inches is drilled, extending further downwards from the existing hole. A surface casing with a diameter of 20 inches is run into the hole. The surface casing has a length such that when a first end of the surface casing reaches the bottom of the hole the opposite end extends somewhat above the conductor. The surface casing has been arranged with the high-pressure wellhead housing which interfaces against the low-pressure wellhead housing. The high-pressure wellhead housing is typically arranged with the surface casing aboard a drilling vessel or drilling rig used for this part of the installation sequence. Finally, the surface casing is cemented in place in the well .

Then, a blowout preventer (BOP) is mounted onto the high-pressure wellhead housing, and a riser is attached to the subsea system.

Several casings are then installed. First, a hole with a diameter of 17.5 inches is drilled, extending further from the existing hole. A first casing is run into the hole, the first casing having a diameter of 13.375 inches. The first casing is suspended from a first casing hanger in the high-pressure wellhead housing. To complete the installation of the first casing, it is cemented in place.

A hole with a diameter of 12.25 inches is then drilled, extending further from the existing hole. A second casing, having a diameter of 9.625 inches, is run into the hole. The second casing is suspended from a second casing hanger in the high-pressure wellhead housing. Cementing is then performed to complete the installation of the second casing.

Finally, a hole with a diameter of 8.5 inches is drilled, extending from the existing hole. A lower completion is run into the hole, the lower completion being suspended from the lower part of the second casing. Then upper completion is performed.

To finalize the installation, the BOP is removed, and a production flow base and a Christmas tree is installed onto the high-pressure wellhead housing.

A problem with the conventional subsea system can be that it offers little flexibility. Details in the installation may vary, of course, such as the length of each size (diameter) of casing. However, whether the subsea system is to be used for a shallow well or a deep well, the components and the installation sequence are mainly the same.

The limitation of the conventional system is partly due to that it is designed for the sequential installation procedure described. Typically, the low-pressure wellhead housing needs to be installed with the conductor. The high-pressure housing typically needs to be installed with the surface casing. The two wellhead housings may then need to be arranged with means to connect to each other, and assembled together subsea as part of the installation procedure. Furthermore, later on in the installation process, the production flow base and the Christmas tree may need to be mounted on and connected to the high-pressure wellhead housing, and these components may too have to be arranged with means to connect to each other.

It is known to replace the conventional foundation of the system, the 60-80 meters long conductor, with a suction caisson. By doing so, it may be possible to perform the installation of the foundation using an anchor-handling vessel instead of a drilling rig. However, the system may still be less than ideal, over-dimensioned for shallow wells, and/or overly cumbersome to install.

The invention has for its object to remedy or to reduce at least one of the drawbacks of the prior art, or at least provide a useful alternative to prior art.

The object is achieved through features, which are specified in the description below and in the claims that follow.

According to a first aspect of the invention, there is provided an apparatus for forming at least a part of a production system for a wellbore, the apparatus comprising: a main, first bore comprising at least one casing hanger profile for suspending a casing from the main bore, the casing to be suspended in the wellbore and to define an annulus in the wellbore ; and a second bore for communicating with the annulus for receiving cement from or supplying cement into the annulus.

The apparatus may be advantageous in that the second bore, for communicating with the annulus, may be utilized for receiving cement from or supplying cement into the annulus, such as to facilitate improved cementing in a wellbore. The second bore may be particularly beneficial in an operation to cement a wellbore for a plug-and-abandonment operation, but may also advantageously be utilized for other operations to obtain a cement plug in a wellbore.

The main bore may comprise a throughbore through the apparatus, and the second bore may extend from the main bore through a wall of the apparatus. The second bore may extend substantially radially from the main bore through the wall of the apparatus, e.g. perpendicular to the main bore.

Furthermore, the apparatus may comprise at least one tubing hanger profile, in the main bore, for suspending a tubing, e.g. a production tubing, from the tubing hanger profile. The tubing may be the uppermost tubing of a string of tubing, which, when suspended from the tubing hanger profile, may define an annulus between the string of tubing and a string of casing in the wellbore, where the casing have a larger diameter than the tubing. The string of casing may be a string wherein the uppermost casing is suspended from the casing hanger profile.

The second bore may extend through the wall of the apparatus at a position in use below the tubing hanger profile in the main bore. The casing hanger profile may be arranged in use below the tubing hanger profile in the main bore.

In this text, when relative positions of features in the main bore are discussed, by use of terms such as "above" or "below", it is referred to how features are arranged relative to other features in the main bore when standing upright as it should when the apparatus is installed correctly, when the apparatus is in use.

The main bore of the apparatus may, in use, comprise at least a part of a production bore of the wellbore. Furthermore, the main bore of the apparatus may, in use, comprise at least a part of at least one annulus. When the apparatus is in use, a tubing string may be suspended from the tubing hanger profile in the main bore. The production bore may then typically be the bore inside the tubing. Furthermore, a casing string may be suspended from the casing hanger profile in the main bore. One annulus may then typically be defined between the outside of the tubing string and the inside of the casing string. An annulus defined between the outside of the tubing string and the inside of the casing string may typically be called an A annulus. At least a part of the A annulus may be comprised by the main bore of the apparatus.

The tubing hanger profile may define an upper end of the A annulus. By having the second bore extend through the wall of the apparatus at a position in use below the tubing hanger profile in the main bore, the second bore may typically extend from a position in an annulus of the main bore, thus allowing access to the annulus through the second bore.

The apparatus may further comprise at least one further profile, in the main bore, for suspending at least one further casing or tubing from the further profile. The further profile may typically be a profile for a casing or tubing hanger. Furthermore, the apparatus may further comprise a third bore, which may be configured to allow cement to be transmitted through the third bore during an operation to form a cement plug in the wellbore. The third bore may extend substantially radially from the main bore through the wall of the apparatus, with respect to the main bore.

The thid bore may extend through the wall of the apparatus from a position in use below the casing hanger profile in the main bore. The further profile may be arranged in use below the casing hanger profile in the main bore.

The casing hanger profile may typically define an upper end of an annulus of the wellbore, such as a B annulus. By having the third bore extend through the wall of the apparatus from a position in use below the casing hanger profile in the main bore, the third bore may extend from a B annulus and thus may provide access to the B annulus through the third bore.

The apparatus may include at least one tubing suspended from the tubing hanger profile and/or a first casing suspended from the casing hanger profile. The tubing may be an upper tubing of a tubing string suspended from the tubing hanger, and the first casing may be an upper casing of a first casing string suspended from the casing hanger profile. Furthermore, the apparatus may comprise a further casing suspended from the further profile. The further casing may be an upper casing of a further casing string suspended from the further profile.

The apparatus may further comprise a fourth bore for transferring a produced fluid from the main bore of the apparatus, e.g. a hydrocarbon fluid produced from a hydrocarbon reservoir in the earth's subsurface. The fourth bore may be a bore for a production flowline. Furthermore, the fourth bore may extend substantially radially from the main bore through a wall of the apparatus, and/or the fourth bore is arranged in use above the tubing hanger profile in the main bore.

The apparatus, in use, may typically have a tubing string suspended from the tubing hanger profile in the main bore. The tubing string may be suspended from the tubing hanger profile, and the tubing hanger profile may define an upper end of the tubing string. Produced fluid flowing through the tubing string may continue through an internal part of the apparatus above the tubing hanger profile, and further flow from the apparatus through the fourth bore. The fourth bore may be a bore for transmitting produced fluid, not a bore for transmitting cement.

The apparatus may comprise a body, which may be made by forging, e.g. made from a single piece of raw material. The body may be arranged with one of, some of, or all of: the main bore; the second bore; the third bore; the fourth bore; the tubing hanger profile; the casing hanger profile; and the further profile. The aforementioned may be arranged in the following order in the main bore, from bottom to top, when the body is in use: the further profile, the third bore, the casing hanger profile, the second bore, the tubing hanger profile, the fourth bore. Having all of the aforementioned features in one body may be advantageous for several reasons. The apparatus may be less complicated because it may consist of fewer parts, it may be easier to assemble, and may reduce the number of parts that needs to interface for assembling the apparatus so that less weight and less space may be needed for interface/connection means to put parts together.

According to a second aspect of the invention, there is provided a passageway for transmitting cement, the passageway being configured for receiving cement from or supplying cement into an annulus of a wellbore which is provided with an apparatus for forming at least a part of a production system for the wellbore, wherein the passageway comprises a bore extending substantially radially through a wall of the apparatus with respect to a main bore of the apparatus.

The passageway may be configured for receiving cement from or supplying cement into an A annulus of the wellbore.

The bore of the passageway may extend from a position between a first profile for suspending a tubing and a second profile for suspending a casing in the main bore.

The passageway may be configured for receiving cement from or supplying cement into a B annulus of the wellbore.

The bore may extend from a position between a casing hanger profile and a further profile for suspending a casing in the main bore.

The passageway may comprise at least one device for obtaining data relating to a parameter of a fluid. By including such a device, it may be possible to gather information on a fluid in an annulus of a wellbore. The passageway may comprise a first device for obtaining data on a temperature of a fluid and a second device for obtaining data on a pressure of the fluid. The device may be a temperature-sensing device, a pressure-sensing device, or any other device for obtaining data relating to a parameter of a fluid. It may be highly benefitial to monitor fluid conditions in an annulus of a wellbore, mainly for well control purposes.

The passageway may further comprise at least one valve for blocking the passageway.

The passageway may further comprise a connection means for connecting to a device external of the apparatus and the passageway. The connection means may comprise a means for a hot-stab connection. The connection means may comprise a valve.

The passageway may be connected to a production flowline of the apparatus.

The passageway may advantageously offer direct access to an annulus. It may offer direct access to a B annulus. It may allow for bleeding off pressure from an annulus through the passageway.

According to a third aspect of the invention, there is provided a method of performing an operation to form a cement plug, e.g. during a Plug-and-Abandonment operation, in a wellbore provided with an apparatus according to any one of claims 1 to 13, the apparatus comprising: a main, first bore comprising a production bore and at least one annulus, the first bore being a throughbore through the apparatus; and a second bore extending from the main bore through a wall of a body of the apparatus; and the method comprising the step of transmitting cement to or from an annulus of the wellbore through the second bore.

The method may further comprise the step of establishing a flow path between the production bore and the annulus of the wellbore by creating an opening through a wall of a tubing and/or a casing of the wellbore.

The method may further comprise the step of circulating a fluid through a part of the wellbore to clean the part of the wellbore, utilizing a flow path between the production bore and an annulus of the wellbore to circulate the fluid.

The method may further comprise the step of forming a plug in the wellbore to isolate a reservoir.

Furthermore, the method may further comprise the step of collecting cement returns from the second bore.

Further, the method may comprise the step of measuring a parameter of the cement from the bore. The measurements taken from the step may be used to analyse a quality of the cement. Based on the results of the analyses, it may be concluded whether a plug is of sufficient quality. The method may comprise the steps of analysing the quality of cement. The method may further comprise the step of evaluating the quality of the plug.

The method may further comprise the step of delivering cement into an annulus, such that a plug of cement is formed in the annulus. Prior to the delivering of cement into the annulus, the annulus may comprise a zone of empty space. The zone of empty space may extend from a bottom of the annulus to a top of the annulus. The bottom of the annulus may be defined by a subsurface formation or by a previously installed plug. The top of the annulus may be defined by a tubing hanger or casing hanger. The plug may, once formed, substantially occupy all of the previously empty space in the zone of empty space in the annulus.

The apparatus may comprise a third bore extending from the main bore through a wall of a body of the apparatus, and the method may further comprise the step of transmitting cement to or from a B annulus of the wellbore through the third bore.

The method may further comprise the step of establishing a flow path between the production bore and the B annulus of the wellbore by creating an opening between the production bore and the B annulus in the wellbore.

In a conventional subsea system, forming a plug in a wellbore, requires the use of a rig to perform the operation. A substantial part of a casing and/or a tubing needs to be removed from the well- bore, and a work string may typically be used to inject cement into the wellbore. Advantageously, that may not be needed for the method according to the invention. Instead, a smaller vessel, such as a light well intervention (LWI) vessel may be used, cement may be injected through a hose, and a tubing and/or casing may be perforated by use of a perforation tool on a wireline toolstring.

According to a fourth aspect of the invention, there is provided an apparatus for performing at least one operation to construct a well subsea, the apparatus comprising a plurality of valves such that the apparatus forms a flow control assembly for controlling fluid flow during production of hydrocarbons from the well, the apparatus being arranged with a through bore configured for allowing drilling and installation of casings and casing hangers to be performed through the bore.

The term "through the bore" includes both partly through the bore and fully through the bore. Typically, drilling will involve running a drill bit through the bore of the apparatus and into a formation below the apparatus for drilling a hole in the formation. Installation of casing hangers will typically involve moving a casing hanger into the bore, leading partly through the bore to a casing hanger latching profile, and latching the casing hanger onto the latching profile.

The apparatus may constitute a subsea system having an integrated flow control assembly, and it may provide all of or some of the functionality of a conventional subsea system, and it may provide additional functionality not normally provided by a conventional subsea system.

The Christmas tree in a conventional subsea system covers several important functions, such as controlling fluid flow during production, providing barriers and monitoring fluid flow. The flow control assembly that the apparatus forms is to be understood, herein, as a replacement for a conventional subsea Christmas tree. The flow control assembly may cover all of or a selection of the main functions covered by a Christmas tree in a conventional system, such as control of flow during injection into the well, pressure relief and monitoring functions such as sand detection and measurements of pressure, temperature, velocity of flow and more. In addition, the flow control assembly that the apparatus forms, may provide functionality not offered by a conventional flow control assembly such as a Christmas tree. Note that a less complex arrangement, e.g. comprising two valves to form barriers against blowouts or other accidents during well development does not constitute what is referred to herein as a "flow control assembly".

The flow control assembly may comprise all of or a combination of a master valve, a wing valve, a crossover valve and a choke valve required to perform the functions offered by a Christmas tree in a conventional subsea system. It may further comprise other valves and other equipment, such as one or more sensors, one or more fittings, one or more spools and/or one or more flanges required to perform the fluid control function offered by a Christmas tree in a conventional subsea system.

One of the limiting features in terms of flexibility of a conventional subsea system is the bore in the Christmas tree of the conventional subsea system. The Christmas tree typically has a bore with a diameter of up to approximately 8 inches, which means the Christmas tree cannot be installed until the majority of the drilling of the well is completed. After the installation of the Christmas tree, the bore in the Christmas tree is typically used for well intervention and other well manipulation tasks, not for further drilling.

The apparatus may have at least the flow control functionality of a conventional Christmas tree, while having a bore of a diameter large enough to allow drilling and installation of casings to be performed through the bore. This makes the apparatus advantageous, as it can allow for a simpler and more cost-efficient subsea well construction procedure, as it may be assembled onshore and subsequently installed on a seabed in one operation prior to drilling.

The apparatus may comprise a casing hanger landing profile. Preferably, the apparatus may comprise two casing hanger landing profiles, but it may also comprise more than two casing hanger landing profiles. A casing hanger landing profile offers a landing profile from which a casing may be suspended. The apparatus may further comprise a tubing hanger latching profile. The tubing hanger latching profile is a latching profile from which a tubing may be suspended. Furthermore, the apparatus may comprise a seal assembly latching profile. The seal assembly latching profile is a latching profile to which a seal assembly may be latched. Having a combination of such profiles will allow for hanging and/or latching a combination of one or more casings, tubings and/or seal assemblies. Having such features comprised by the apparatus is beneficial, particularly during well construction, as it means no external parts have to be connected to the apparatus to provide such features.

The apparatus may further comprise connection means for connecting to a riser and/or a blowout preventer (BOP). Having such connection means may be advantageous as it may become necessary to connect a BOP and/or a riser to the apparatus during well construction and/or production.

The apparatus may further comprise a flow-line connector for connecting to a flow-line. The flow- line may typically be a line of tubing or casing through which fluid may flow. It is advantageous for the apparatus to comprise a flow-line connector for connecting to a flow-line, as it will provide a route for flow from the apparatus to an external receiver.

The apparatus may further comprise a suction caisson for forming a well foundation. Installing a suction caisson as foundation requires no drilling, meaning an anchor-handling vessel or other types of light construction vessels may be used instead of a drilling rig or drilling vessel. This is a great advantage, particularly when several wells are to be drilled in a field, as it allows for more efficient use of resources in a field development project: An anchor-handling vessel or other types of light construction vessels are significantly cheaper in use than a drilling rig or vessel, and the installation process of a suction caisson as well foundation is significantly simplified compared to that of establishing a conventional foundation comprising a conductor and a low-pressure wellhead housing. The apparatus, comprising a suction caisson, will not need a pre-installed foundation to which to attach. Instead, the apparatus can simply be installed through suction, and form its own foundation.

The apparatus may use other forms of well foundations. It may use a conventional conductor foundation as a foundation, or it may use any other structure fit to act as a foundation.

Furthermore, the apparatus may comprise a full-bore isolation valve. The full-bore isolation valve may be used as a barrier, e.g. for periods when a well is to be temporarily abandoned, and may thus offer a very efficient alternative to setting a plug in a well, which is currently the conventional method of establishing a well barrier element. Setting a plug for temporary abandonment may typically take 12 hours, whereas closing a full-bore isolation valve takes very little time.

The apparatus may further comprise a protective structure, for protecting the apparatus against external forces, corrosion, pollution, or other unwanted effects. The seabed may be a harsh environment, and a protective structure may help preserve the integrity of the apparatus and increase its longevity. The protective structure may be assembled to the apparatus prior to installation subsea.

The apparatus may further comprise an ROV-receptacle. ROV is short for remotely operated vehicle. The ROV-receptacle may be for receiving a hose from an ROV, for injection or extraction of a fluid. Having an ROV-receptacle is advantageous as it allows an ROV to connect to and manipulate the apparatus or a well to which the apparatus belongs. The ROV receptacle may be a hot stab receptacle. A hot stab receptacle may be beneficial as it is designed for connecting or disconnecting under pressure while causing little to no spill.

Furthermore, the apparatus may comprise a bore protector and/or a wear bushing for preventing wear and/or blocking pollution from entering valves, profiles and/or latches during drilling or cementing. The bore protector may be placed in the bore of the apparatus prior to drilling, and removed after drilling. This may be done using a winch, or by use of any other means suitable for the purpose. It is highly advantageous to use a protective element such as a bore protector during drilling, to prevent mud, sand, rocks, cement and/or other unwanted objects from damaging the integrity of sensitive components of the system. The bore protector and/or the wear bushing may comprise an upper and a lower seal, for sealing a portion of the bore, for protection of sensitive equipment and/or for pressure testing to be performed in the sealed-off portion of the bore.

The apparatus may further comprise an interface spool for forming an interface between a main body of the apparatus and a well foundation. The foundation may be the suction caisson. The main function of the interface spool is to mate the main body with the foundation and to transfer structural loads onto the foundation. The interface spool may comprise an outlet for cement returns for routing cement onto a seabed for preventing cement returns from returning through the main body of the apparatus during cementation. Having an interface spool with such features decreases the risk of having cement returns pollute valves, latching profiles and other sensitive equipment in the apparatus. The interface spool solution thus eliminates potential problems related to performing a cementing operation through the apparatus. The interface spool may comprise a plurality of outlets for cement returns. It may comprise one, two, three, four, five, six, seven, eight, or more than eight outlets for cement returns.

The outlet for cement returns may be a pipe running from an annulus of a wellbore, through the foundation, to an opening towards a sea floor. The pipe may comprise a valve for blocking the outlet, for creating a barrier between the sea and the annulus. The pipe may comprise a plurality of valves for creating a plurality of barriers.

The interface spool may further comprise a casing latching system for latching a casing in place after installing the casing in a wellbore. This is advantageous as it prevents upward movement of a casing string.

The interface spool may comprise an interface spool extension. The interface spool extension may be a pipe having a first end arranged to a lower end of the interface spool. The pipe may extend from the lower end of the interface spool to a bottom end of a foundation, such as a suction caisson, and may be arranged via structural support to an exterior portion of the foundation.

The apparatus may further comprise an annulus line forming an inlet to and an outlet from the main bore in a position of the bore below the tubing hanger latching profile for providing access to an annulus of a well. The apparatus may further comprise an annulus master valve, and the annulus line may extend radially from the main bore through a body of the apparatus to the annulus master valve. The annulus line may typically be arranged in a position between a tubing hanger latching profile and a casing hanger latching profile. In embodiments of the system having a plurality of casing hanger latching profiles, the annulus line may typically be an inlet to and an outlet from a portion of the main bore between the uppermost casing hanger latching profile and the tubing hanger latching profile.

The apparatus may further comprise a crossover line, for providing a crossover line from an annulus of a well to the flow line of the apparatus. The crossover line may comprise the annulus line. The crossover line may further comprise a crossover valve, for forming a barrier to the flow line.

Furthermore, the apparatus may comprise an external circulation line for accessing an annulus and/or the flow line. The external circulation line may be used as a bleed line for bleeding off pressure from an annulus, as an injection line for injecting a fluid into the annulus, as a circulation line for improving circulation in a well, and/or as a cementation line for a cementation task e.g. during a well abandonment phase. The external circulation line may have further uses.

The external circulation line may be arranged with connection means for connecting to a fluid flow means, such as a hose, pipe, tubing, or any other type of means through which fluid may securely flow. The fluid flow means may be connected to the external circulation line by use of an ROV. This allows for efficient access to the external circulation line by use of the fluid flow means and an ROV, for injecting fluid into or extracting fluid from the external circulation line. The connection means may be a hot-stab connection. The hot-stab connection may comprise a valve that may act as a barrier. The hot-stab connection may herein be referred to as an ROV valve stab receptacle.

The external circulation line may comprise a tubular structure having the above-mentioned connection means arranged in a first end portion of the tubular structure. A second end of the tubular structure of the external circulation line may connect to the crossover line. Thus, the circulation line may access, through the crossover line, both the annulus line and the flow line. The external circulation line may typically connect to the crossover line in a position in the crossover line between a crossover valve and an annulus master valve.

The external circulation line may further comprise a second valve for forming a barrier between the crossover line of the apparatus and the connection means of the external circulation line. The second valve may be any type of valve suitable for forming a barrier.

It may be said that the external circulation line comprises at least a portion of the crossover line and/or the annulus line, to form a complete line from the connection means of the external circulation line to the flow line and/or the bore of the apparatus below the production hanger latching profile.

In a conventional subsea system, a significant portion of a circulation line may typically run within a wall of a body of the Christmas tree and/or the high-pressure wellhead. As the wall typically offers little space, this conventional design can limit the diameter of the circulation line. Except for radial penetration of the body of the apparatus, the external circulation line may run externally from any wall of the main body of the apparatus. The area where the external circulation line does penetrate the wall radially may be spacious. This means that the external circulation line of the apparatus may not have the same restrictions to its diameter as the circulation line of a conventional subsea system. This allows for a greater diameter of the external circulation line compared to that of a conventional circulation line. A greater diameter of the circulation line allows for greater fluid flow rates, which may be beneficial e.g. for well circulation jobs and for setting of cement plug during a well abandonment phase.

The external circulation line may form a line into the flow line and/or the main bore below the tubing hanger latching profile running separately from the crossover line and/or the annulus line. The external circulation line may comprise one or more valves for forming one or more barriers.

The apparatus may further comprise a radial bore through the body below a casing hanger latching profile for monitoring well parameters such as pressure and/or temperature. The bore may be arranged with a B annulus line for bleeding of pressure and/or for circulation.

The B annulus line may comprise a valve for providing a barrier. The B annulus line may comprise a plurality of valves. The B annulus line may be connected to the production line, to the crossover line and/or the external circulation line. The B annulus line may comprise one or more sensors, e.g. for monitoring pressure, temperature, flow rate or any other fluid characteristics that it may be beneficial to monitor. The B annulus line may be used e.g. for circulating drilling fluid, and/or for cementing during a well abandonment phase. The B annulus line may further comprise connection means for connecting to fluid flow means, such as a hot-stab connection. The fluid flow means may be any means through which fluid may flow, suitable for the purpose, such as a hose, a tubing and/or a pipe.

In an embodiment having more than one casing hanger latching profile, the apparatus may comprise further annulus lines, such as a C annulus line and/or a D annulus line, having one or more of the features of the B annulus line. The apparatus may typically have an annulus line above and below each casing hanger latching profile. In an example embodiment having a first and a second casing hanger latching profiles, and a tubing hanger latching profile, the apparatus may typically have the annulus line between the tubing hanger latching profile and the second casing hanger latching profile, the B annulus line between the second casing hanger latching profile and the first casing hanger latching profile, and the C annulus line below the first casing hanger latching profile.

The annulus lines may be greatly advantageous. Legislation is expected to be implemented as soon as reliable technology is available, requiring monitoring of the B-annulus. A direct access monitoring system, made possible by the B annulus line has the benefit that it may last for the lifetime of a well, something which remote systems powered by batteries may not be able to offer. Furthermore, the annulus lines may offer a direct flow path to an annulus, which may allow for more efficient cementation techniques.

The apparatus may further comprise one or more chokes, one or more sensors, one or more crossover valves, one or more of other types of valves, one or more flanges, one or more spools, and/or the apparatus may comprise other components that may increase the apparatus' functionality as a subsea drilling and production system or that may be beneficial for other reasons.

In some embodiments the apparatus may comprise all the necessary components for the apparatus to fulfil all requirements of a subsea drilling and production system, and to fulfil partly or completely the functionality of a conventional subsea system , including that of the low-pressure wellhead housing, the high-pressure wellhead housing, the production flow base and the Christmas tree. Furthermore, the apparatus may have functionality not typically offered by a conventional subsea system, such as some of the functionality offered by the B annulus line, the external circulation line and the interface spool. A great advantage of the apparatus may be that it can allow for onshore assembly of a far greater portion of a complete subsea system than does prior art. Only drilling, installation of casings and tubings, completion, and manipulation of the system may be necessary to construct and operate the well. All of or a selection of the following may be assembled as the apparatus onshore: a flow control assembly, a protective structure, a suction caisson, a flow line, an external circulation line, a plurality of annulus lines, an ROV receptacle, latching profiles, and more.

The apparatus in some embodiments may thus allow for a simpler, more efficient installation and well development procedure than a conventional subsea system. In an embodiment, a suction caisson may offer a simpler foundation establishment, as it may require no drilling. The suction caisson may form the foundation of the well. Secondly, the step of installing a surface casing and a high- pressure wellhead housing may be skipped, as the functionality of the high-pressure wellhead housing may be fulfilled by the subsea system according to the invention. Skipping the step of establishing the 26 inches hole and 20 inches surface casing may limit the size of the well, though, and is thus mainly a good option for a relatively shallow well. Finally, the last step of installing the Christmas tree may also be skipped, as the functionality of the Christmas tree is covered by the apparatus.

The apparatus may further comprise a concentric tubing hanger, having a concentric shape. The concentric tubing hanger may comprise circumferential upper and lower tubing hanger seals. The concentric tubing hanger may further comprise an internal isolation valve and/or profiles for crown plug. Ports for the isolation valve may be drilled into a body of the concentric tubing hanger. The concentric shape may be advantageous over conventional casing hanger solutions, as a conventional hanger typically requires orientation means to be implemented to allow orientation of the tubing hanger during installation. The concentric tubing hanger does not require such orientation, and therefore does not require orientation means. By not requiring orientation means to be installed, the concentric tubing hanger solution can be advantageous as it may require less space in the main bore than a conventional tubing hanger solution.

The apparatus may comprise a casing and/or casing string. The apparatus may further comprise a plurality of casings and/or casing strings. The apparatus may further comprise a production tubing, and/or it may comprise other forms of tubing. The apparatus may further comprise an annulus between a casing and a tubing, an annulus between a casing and another casing, an annulus between a casing and a formation and/or an annulus between a tubing and a formation. The apparatus may comprise a partly or fully developed hydrocarbon well. The apparatus may comprise any downhole equipment in the well.

Accordint to a fifth aspect of the inventino, there is provideda method for constructing a well, wherein the method comprises the step of: - drilling a hole into a formation for a subsequent installation of a casing, wherein the drilling is performed through a bore in an apparatus according to the first or fourth aspect of the invention.

A method wherein a hole is drilled into a formation through a bore in an apparatus comprising a flow control assembly may be beneficial as the flow control assembly may be installed prior to the step of drilling the hole.

The method may further comprise the step of installing a casing into the hole in the formation through the bore of the apparatus. Furthermore, the method may comprise the step of cementing the casing in place in the hole in the formation, wherein the cementing operation is performed through the bore. The method comprising the steps of installing a casing through the bore and cementing the casing in place through the bore means a subsea system may comprise a flow control assembly prior to the installation of a casing, which means that a subsea system with an integrated flow control assembly may be assembled onshore.

The method may further comprise the step of installing a production tubing in a well, wherein the operation is performed through the bore of the apparatus.

The hole drilled through the bore of the apparatus may be for the installation of a casing with a diameter greater than the diameter of a production tubing to be installed subsequently during the well construction process. The hole may have a diameter large enough for the installation of the largest casing to be installed during the construction of the well.

The diameter of the hole drilled through the bore may be at least 12.25 inches. The diameter of the hole drilled through the bore may be at least 1 5 inches. The diameter of the hole drilled through the bore may be at least 17.5 inches.

The method may further comprise the step of installing an apparatus comprising a flow control assembly on a seabed, wherein the bore through which the drilling is performed is a bore though the apparatus, and wherein the installation of the apparatus is performed prior to a step of drilling for a subsequent installation of a casing for the well. Installing the apparatus prior to drilling operations may be advantageous for reasons mentioned in the previous paragraph.

The step of installing the apparatus may comprise the step of establishing a foundation for a well. Thus, the foundation may be comprised by the apparatus, as in the case of an embodiment where the apparatus comprises a suction caisson. This may be particularly advantageous when developing an oil field with multiple wells to be constructed, as it allows for a smaller vessel, such as an anchor-handling vessel, to perform the task of installing the foundations of the wells, as drilling may not be necessary during the establishment of the foundations. Alternatively, the foundation may be a conventional conductor, wherein the conductor is configured for receiving the apparatus and wherein the apparatus is configured for having the conductor as a foundation. The method may further comprise the step of performing a cementing operation in a well, wherein the cementing operation is performed through the bore of the apparatus.

The step of performing a cementing operation in a well may comprise the step of releasing cement returns onto a seabed through an outlet for cement returns. The outlet for cement returns may be an outlet in an interface spool of the apparatus.

Furthermore, the method may comprise the step of inserting into the bore of the flow control assembly a bore protector for protecting the bore and other parts of the apparatus against wear and/or pollution from mud, sand, rocks, cement, and/or other unwanted objects.

The method for constructing a well can be advantageous, particularly in that it does not require a Christmas tree to be installed after completing the drilling process.

Furthermore, the method can be advantageous as the method does not require assembly of components of the system on the seabed. This stands in contrast to a conventional method of assembling a subsea system. A conventional system typically requires the low-pressure wellhead housing to connect to the high-pressure wellhead housing, and the high-pressure wellhead housing to connect to the production flow base and the Christmas tree. These are all typically installed at different stages of the well development process for a conventional system. Having to assemble the low- pressure wellhead housing, the high-pressure wellhead housing, the production flow base and the Christmas tree of a conventional subsea system together with each other subsea can be inefficient, and may necessitate that the components are designed for such subsea assembly, with connection- and interface means that may otherwise not be necessary in an apparatus assembled onshore.

According to a sixth aspect of the invention, there is provided an interface spool for acting as an interface between a main body of an apparatus for performing at least one operation to construct a well subsea and a well foundation. The well foundation may be a suction caisson, or it may be any other suitable foundation, such as a conductor. The main functions of the interface spool is to mate the main body with the foundation, and to transfer structural loads onto the suction caisson. The apparatus may be the apparatus according to the first aspect of the invention presented herein. The apparatus may comprise both the main body and the well foundation.

More specifically, there is described an interface spool for acting as an interface between the main body of the apparatus and the foundation, wherein the interface spool comprises an outlet for cement returns for routing cement onto a seabed outside of the foundation for preventing cement returns from returning through the main body of the apparatus during cementation when the apparatus is installed subsea. Having an interface spool with such features decreases the risk of having cement returns pollute valves, latching profiles and other sensitive equipment in the apparatus. The interface spool solution thus eliminates potential problems related to performing a cementing operation through an apparatus comprising a flow control assembly. The interface spool may comprise a plurality of outlets for cement returns. It may comprise one, two, three, four, five, six, seven, eight, or more than eight outlets for cement returns.

The outlet for cement returns may be a pipe running from an annulus of a wellbore, through the foundation, to an opening towards a sea floor. The pipe may comprise a valve for blocking the outlet, for creating a barrier between the sea and the annulus. The pipe may comprise a plurality of valves for creating a plurality of barriers.

The interface spool may further comprise a casing latching system for latching a casing in place after installing it in a wellbore. This is advantageous as it prevents upward movement of a casing string.

The interface spool may comprise an interface spool extension. The interface spool extension may be a pipe having a first end arranged to a lower end of the interface spool. The pipe may extend from the lower end of the interface spool to a bottom end of a foundation, such as a suction caisson, and may be arranged via a structural support to an exterior portion of the foundation.

The apparatus of any of the aspects herein may comprise the interface spool.

There is further described an apparatus according to the first aspect of the invention, wherein the apparatus comprises the interface spool.

According to a seventh aspect of the invention, there is provided a method for cementing a casing in place in a wellbore by substantially filling an annulus between the casing and a surrounding formation with cement, wherein the method comprises the steps of:

- providing cement into the wellbore through the casing;

- running cement from inside the casing to the annulus; and

- running return cement through an outlet for cement return onto a seabed, wherein the cement return is comprised by an interface spool, and the interface spool is comprised by a subsea system .

The subsea system may be the apparatus according to the first aspect of the invention.

The method may comprise the step of opening a valve to allow return cement to run from the annulus, through the outlet, to the seabed. The valve may be a valve in the outlet for cement return.

The method described above may be advantageous for use with an apparatus wherein a flow control assembly and/or other sensitive equipment is installed and/or integrated prior to performing a cementing operation. During cementing, return cement may, by use of this method, escape to the seabed prior to reaching sensitive equipment, such as valves, sensors or hanger profiles, thus limiting the risk of having the sensitive equipment polluted by the cement. According to an eighth aspect of the invention, there is provided an external circulation line for accessing an annulus and/or a flow line of an apparatus for performing at least one operation to construct a well subsea. The external circulation line may be used as a bleed line for bleeding off pressure from an annulus, as an injection line for injecting a fluid into the annulus and/or production bores, as a circulation line for improving circulation in a well, and/or as a cementation line for a cementation task in a well, e.g. during a well abandonment phase. The external circulation line may have further uses. The apparatus may be a subsea system. The subsea system may comprise a fully or partly developed hydrocarbon well.

The external circulation line may be arranged with connection means for connecting to a fluid flow means, such as a hose, pipe, tubing, or any other type of means through which fluid may securely flow. The fluid flow means may be connected to the external circulation line by use of an ROV. This allows for efficient access to the external circulation line by use of the fluid flow means and an ROV for injecting fluid into or extracting fluid from the external circulation line. The connection means may be a hot-stab connection. The hot-stab connection may comprise a valve that may act as a barrier. The hot-stab connection may be referred to as an ROV valve stab receptacle. The connection means may further be referred to as an ROV receptacle.

The external circulation line may comprise a tubular structure having the above-mentioned connection means arranged in a first end portion of the tubular structure. A second end of the tubular structure of the external circulation line may connect to another line of the apparatus, such as a crossover line, an annulus line, a flow line and/or a main bore. Thus, the circulation line may access, either directly or through other lines, both or either one of an annulus line and a flow line. The external circulation line may typically connect to a crossover line in a position in the crossover line between a crossover valve and an annulus master valve. The external circulation line may further comprise a second valve for forming a barrier between the crossover line of the apparatus and the connection means of the external circulation line. The second valve may be any type of valve suitable for forming a barrier. The external circulation line may connect to a flow line, either directly or indirectly, and to an annulus, either directly or indirectly.

The external circulation line may comprise at least a portion of a crossover line and/or an annulus line to form a complete line from the connection means of the external circulation line to the flow line and/or the bore of the apparatus below the production hanger latching profile.

In a conventional subsea system, a significant portion of a circulation line typically runs within a wall of a body of the Christmas tree and/or the high-pressure wellhead. As the wall typically offers little space, this conventional design limits the diameter of the circulation line. Except for radial penetration of a body of an apparatus, the external circulation line runs externally from any wall of the main body of the apparatus. The area where the external circulation line does penetrate the wall radially may be spacious. This means the external circulation line of the apparatus may not have the same restrictions to its diameter as the circulation line of a conventional subsea system. This allows for a greater diameter of the external circulation line compared to that of a conventional circulation line. A greater diameter of the circulation line allows for greater fluid flow rates, which may be beneficial e.g. for well circulation jobs and for setting of a cement plug during a well abandonment phase.

According to a ninth aspect of the invention, there is provided a method of setting a cement plug in a well, wherein the method comprises the step of injecting cement into the well through an external circulation line. The cement plug may be a well abandonment cement plug.

The apparatus according to any aspect of the invention herein may comprise said external circulation line. The apparatus may be for performing at least an operation to construct a well subsea.

According to a tenth aspect of the invention, there is provided a method of establishing a cement well abandonment plug, wherein the method comprises the step of providing cement into a well- bore through an external circulation line. Furthermore, the method of establishing the cement well abandonment plug may comprise the step of feeding cement into the annulus vent/injection through a hot stab connection. Further steps involved in the method for establishing the cement plug may be steps known to a skilled person.

According to an eleventh aspect of the invention, there is provided a subsea drilling system for drilling exploration wells, wherein the drilling system comprises a foundation, an interface spool and a high-pressure mandrel arranged to form an interface between the subsea system and a drilling blowout preventer and/or a Christmas tree.

The interface spool may be the aforementioned interface spool. The foundation may be a suction caisson, or any other foundation suitable for the purpose.

The foundation may form a low-pressure system for carrying loads such as vertical loads, horizontal loads and torque, the interface spool forms an interface between the foundation and the mandrel, and the high-pressure mandrel forms a high-pressure system for enduring pressure loads and forms an interface for further parts to be connected to the subsea system.

The subsea drilling system for drilling exploration wells is advantageous compared to prior art, as it allows for assembly of the drilling system to be performed onshore, and for the subsea system to be installed on a seabed in one operation. A conventional subsea system comprising a foundation, a low-pressure wellhead and a high-pressure wellhead typically needs several installation steps to be performed, as has been previously discussed.

According to a twelfth aspect of the invention, there is provided an apparatus for performing at least one operation to construct a well subsea comprising a B annulus line, wherein the B annulus line forms a flow path for monitoring fluid characteristics in an annulus of a subsea well. The B annulus line may comprise a bore through a wall of a body of the apparatus, below a casing hanger latching profile, for providing a flow path from an annulus on the outer side of a casing suspended from a casing hanger latched to the latching profile. The B annulus line may comprise a line of tubing for bleeding off pressure from the annulus and/or for circulation of fluid in the annulus. The B annulus line may comprise a valve for providing a barrier. The B annulus line may comprise a plurality of valves. The B annulus line may be connected to a production line, to a crossover line and/or a circulation line such as an external circulation line. The B annulus line may comprise one or more sensors, e.g. for monitoring pressure, temperature, flow rate or any other fluid characteristics that it may be beneficial to monitor. The B annulus line may be used for circulating drilling fluid and/or for cementing during a well abandonment phase, or for any other relevant tasks. The B annulus line may further comprise connection means for connecting to fluid flow means, such as a hot-stab connection. The fluid flow means may be any means through which fluid may flow, suitable for the purpose, such as a hose, a tubing and/or a pipe.

The apparatus may comprise further annulus lines, such as a C annulus line and/or a D annulus line, having one or more of the features of the B annulus line. The apparatus may typically be provided with an annulus line above and below each casing hanger latching profile. In an example embodiment having a first and a second casing hanger latching profiles, and a tubing hanger latching profile, the apparatus may typically have an annulus line between the tubing hanger latching profile and the second casing hanger latching profile, a B annulus line between the second casing hanger latching profile and the first casing hanger latching profile, and a C annulus line below the first casing hanger latching profile.

The annulus lines may be greatly advantageous. Legislation is expected to be implemented as soon as reliable technology is available, requiring monitoring of the B-annulus. A direct access monitoring system, made possible by the B annulus line can have the benefit that it may last for the lifetime of a well, something which remote systems powered by batteries may not be able to offer. Furthermore, the annulus lines may offer a direct flow path to an annulus, which may allow for more efficient cementation techniques.

According to a thirteenth aspect, there is provided a body for an apparatus for forming at least part of a production system for a wellbore, wherein the body comprises all of a main bore, a second bore, a third bore, a fourth bore, a tubing hanger profile, a casing hanger profile and a further profile. The body may be made from forging. The body may be made from a single piece of raw material.

The second bore, the third bore and/or the fourth bore may extend substantially radially with respect to the main bore from the main bore through a wall of the body. The profiles may be arranged in the main bore. The fourth bore may extend radially from the main bore from a position above all of the profiles in the main bore in use. The third bore may extend from a position below the tubing hanger profile and the casing hanger profile, but above the further profile in use. The second bore may extend from a position below the tubing hanger profile, but above the casing hanger profile and the further profile in use. The tubing hanger profile may be a profile from which to suspend a string of tubing. The casing hanger profile may be a profile from which to suspend a string of casing. The further profile may be a profile from which to suspend a string of casing. When in use, the second bore may be a bore facilitating access to an A annulus of the wellbore. The third bore may be a bore facilitating access to a B annulus of the wellbore. The fourth bore may be a bore for allowing produced fluid to flow from the apparatus.

The apparatus and/or the body may have further bores extending from the main bore, whereof one or more of the further bores may extend substantially radially with respect to the main bore from the main bore.

At least one of the second bore, the third bore, the fourth bore and the further bores may be a bore for communicating with an annulus and/or a production bore of the wellbore for receing cement from or supplying cement into the annulus and/or the production bore.

Having all of said features in one body of the apparatus may make an assembly of the apparatus easier, with fewer interface points and reduce the number of parts needed to be connected together during assembly. Having all the features in one body may thus reduce the number of connection means needed, and further therefor be more compact and of lower weight compared to an apparatus having the features spread over more than one body or part. It may also improve the structural integrity of the apparatus.

Any of the aspects described herein, in the claims, or elsewhere, may include one or more further features as defined in relation to any other aspect of the invention described herein.

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

Figure 1 illustrates an example of the apparatus for performing at least one operation to construct a well subsea;

Figure 2 shows a portion of the apparatus of Figure 1 , prior to insertion of a bore protector;

Figure 3 shows the portion of the apparatus of Figure 1 comprising the bore protector;

Figure 4 shows the portion of the apparatus of Figure 2 comprising a wear bushing ;

Figure 5 shows the apparatus comprising a suction caisson, an interface spool and a protective structure, as the apparatus is lowered to a seabed;

Figure 6 shows the apparatus installed in a seabed, with the suction caisson forming a foundation; Figure 7 shows the apparatus having been installed in the sea floor, with a hatch of the protective structure having been closed;

Figure 8 shows the apparatus in place in the seabed, with the protective structure opened;

Figure 9 shows the apparatus including a B annulus line;

Figure 10 shows a subsea drilling system for drilling exploration wells;

Figure 1 1 shows the apparatus in use prior to an operation to form a cement plug in a wellbore;

Figure 12 shows the apparatus in use after a plug has been set in a production bore in the well- bore;

Figure 13 shows the apparatus in use after cement has been injected into the production bore and an annulus of the wellbore;

Figure 14 shows a remaining part of the wellbore after the apparatus has been cut and removed from the sea floor;

Figure 15 shows the apparatus in use after cement has been injected into the production bore and two annuli of the wellbore; and

Figure 16 shows the remaining part of the wellbore, with cement in two annuli, after the apparatus has been cut and removed from the sea floor.

Figure 1 illustrates an example apparatus 1 for performing at least one operation to construct a well subsea.

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.

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 200 further comprises a flow line connector 206, for connecting to an external flow line (not shown). 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.

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.

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.

The apparatus 1 in this example further comprises an mandrel 9 which may be an 18 ¾" 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 1 00,

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.

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.

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.

The apparatus further comprises a concentric tubing hanger 19, for forming an interface between production outlet and production tubing, latching grooves 1 1 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 .

Figure 2 is included to show an example of the apparatus 1 , prior to insertion of a bore protector into the bore 100. Figure 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 Figure 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.

Figures 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 18 ¾" H4 mandrel with a H4 profile 9. Figure 5 further shows a wireline 70 connected to the lifting cap 25, for lowering the apparatus 1 onto a seabed 80.

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

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.

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

Figure 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 .

Figure 7 shows 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.

Figure 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.

Figure 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.

Figure 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 .

A plurality of the figures also illustrate the apparatus according to an embodiment of the first aspect of the invention and the passageway according to an embodiment of the second aspect of the invention. Looking again at Figure 1 , it shows the apparatus 1 , having a main, first bore 100, wherein the first bore 100 comprises a casing hanger profile 1 1 in the form of a latching grooves 1 1 , for suspending a casing from the main bore 100. It is further illustrated how the casing is suspended by use of a casing hanger 13, and how the casing defines an annulus between itself and a smaller diameter tubing. The apparatus further has a second bore 3 for communicating with the annulus for receiving cement from or supplying cement into the annulus.

The second bore 3, as shown, is part of a passageway 300 to the annulus, and is configured for receiving cement from or supplying cement into the annulus. The second bore 3 comprises a bore extending substantially radially through a wall of the apparatus 1 with respect to the main bore 100.

The passageway 300 in this embodiment is called an external circulation line 300, and comprises, as described above, an ROV valve stab receptacle 301 . Furthermore, the passageway comprises a pressure and temperature sensor 14 and a fail-safe annulus master valve 15. The passageway 300 shown in Figure 1 is a passageway to an A annulus, as the bore extends through the wall of the apparatus 1 from a position between a tubing hanger profile 19 and a casing hanger profile 1 1 in the main bore 100 of the apparatus. Furthermore, the passageway 300 is connected to a production flowline 200 of the apparatus 1 through a crossoverline 400 of the apparatus 1 .

In Figure 1 1 , the apparatus 1 has a further passageway 900 being configured for receiving cement from or supplying cement into an annulus 125 of a wellbore 50, wherein the passageway 900 comprises a bore 901 through a wall of the apparatus 1 . The further passageway 900 in this embodiment of the invention is called a B-annulus line 900, and the annulus 125 the passageway 900 is configured for receiving cement from or supplying cement into is a B annulus 125 of the wellbore 50. The further passageway 900 comprises, two valves 902, 903 and an ROV hot-stab receptacle 904.

The bore 901 is a third bore, and is configured to allow cement to be transmitted through the third bore during an operation to form a cement plug in the wellbore, of the apparatus 1 . In embodiments having the bore 901 , the apparatus 1 further has a further profile for suspending a casing 12. As can be seen, when installed, the further profile is placed lower in the main bore 100 of the apparatus 1 than the casing hanger profile 1 1 . The third bore 901 is then typically positioned between the casing hanger profile 1 1 and the further profile 12.

The apparatus 1 further has a fourth bore 21 1 . The fourth bore 21 1 is used for transferring a pro- duced fluid from the main bore 100 of the apparatus 1 , and is located above the tubing hanger profile 19.

Furthermore, the apparatus shown in Figure 1 1 comprises a body 2, which is made by forging. The body 2 includes the main, first bore 100, the second bore 3, the third bore 901 , the fourth bore 21 1 , the tubing hanger profile 19, the casing hanger profile 1 1 and the further profile 12. In other embodiments of the invention, the apparatus 1 may comprise a body 2 having some of, but not all of, the above mentioned features.

The body 2 may further comprise additional features, such as further bores 51 1 for a control line system 500.

The apparatus advantageously facilitates new methods for performing an operation to form a cement plug in a wellbore provided with the apparatus 1 .

Figures 1 1 -14 illustrates the wellbore 50 at different stages of a first variant of the method, and Figures 1 1 -13 and 15-16 illustrates the wellbore 50 at different stages of a second variant. Both methods described are methods related to plug-and-abandonment operations. The wellbore 50 is to be abandoned, but before doing so cementing is to be performed to plug it.

Figure 1 1 shows a wellbore 50 comprising the apparatus 1 , the apparatus 1 having a first, main bore 100, a second bore 3, a third bore 901 and a fourth bore 21 1 . A first casing string 1 1 1 is suspended from a casing hanger profile 1 1 , a second casing string 121 from a further profile 12, and a tubing string 191 from a tubing hanger profile 19. The main bore 100 comprises an A annulus 1 15, a B annulus 125, a C annulus 135 and a production bore 195.

The A annulus 1 1 5 is partly defined between the tubing string 191 and the first casing string 1 1 1 and partly between the tubing string 191 and a formation 85. The B annulus 125 is partly defined between the first casing string 1 1 1 and the second casing string 121 , and partly between the first casing string 1 1 1 and a formation 85. The production bore 195 is mainly defined by the tubing string 1 91 . The C annulus 135 is partly defined between the second casing string 121 and the main bore 100 of the apparatus 1 and partly between the second casing string 121 and the formation 85.

Deep in the wellbore 50, the tubing string 191 is perforated to enable an inflow of fluid from a reservoir 86 in the formation 85. A distance above the perforations, a production packer 1 16 is placed in the A annulus 1 15 to isolate a bottom zone of the A annulus 1 15. A bottom zone of each annulus 1 15, 125, 135 has been cemented as part of the wellbore 50 construction.

The method to perform an operation to form a cement plug in a wellbore 50 may be executed as described in the following:

A light well intervention (LWI) vessel is mobilized to the well. By use of methods known to a skilled person, the well is investigated, and various valves in the well are manipulated and set in correct positions to start the cementing operation. When a downhole safety valve (DHSV) (not shown), a tubing hanger valve (THV) (not shown), a production master valve (PMV) 203 and an annulus master valve (AMV) 1 5 are in closed positions, a high-pressure cap (HP cap) 25 is removed to expose a H4 mandrel 93 on the top of the apparatus 1 . A subsea lubricator (not shown) is then installed on the H4 mandrel. The integrity of the well is then tested.

Subsequently to the integrity test, the THV and the DHSV are opened, and a wireline toolstring with a mechanical plug 1 97 is run into the well. The plug 197, shown in Figure 12, is placed in a deep position in the wellbore 50, typically directly below the production packer 1 16. After installation of the plug 197, its integrity is confirmed. The plug 197 is installed to form a base for cement in the production bore 191 , and for isolating the reservoir 86 for the duration of the cementing operation.

A first hose (not shown) is deployed from the vessel and attached to the apparatus 1 to establish a fluid path from the vessel to the production bore 195. A second hose (not shown) is deployed from the vessel and attached to the hot-stab receptacle 301 of the passageway 300, to establish a fluid path from the vessel to the A annulus 1 15 through the second bore 3

A circulation path is the established in the wellbore 50 between the production bore 195 and the A annulus 1 15 by punching openings 199 through the tubing string 191 above the plug 197. This can be done using a perforation tool.

The wireline is then recovered, and the lubricator isolated from the well. The next step is then to clean the production bore 195 and the A annulus 1 1 5 by utilizing the circulation path offered by the pathway to the A annulus 1 15 by first circulating out borehole fluids followed by circulating a disper- sant (soap) to enable a good cement to steel bonding when cementing.

When the A annulus 1 1 5 and the production bore 195 has been cleaned, cement is pumped down the production bore 195 until cement returns are observerd at surface via the second hose. The cement passes out of the annulus 1 15 through the bore in the wall and into and through the hose before reaching the surface. The quality of the cement returns is then analysed, and cement displaced with water (or something else, suitable for the purpose), until desired internal tubing top of cement is achieved. This may e.g. be confirmed volumetrically and by assessing required pump pressure.

To divide the interface between the cement and the water or other displacement fluid, they are mechanically separated by use of one or several flexible interfaces (typically sponge balls). This flexible interface will also assist to clean the cement hose and the tubing from residue cement.

In Figure 13, the cement plug 53 can be seen in place in the wellbore 50. The cement plug 53 then substantially fills the A annulus 1 15, and partly fills the production bore 195, and forms a barrier, sealing a region above the cement plug from a region below. Once the cement plug 53 is in place in the wellbore 50, the hoses (not shown) and external equipment (not shown) are isolated from the well, and circulated clean. When the cement is hard, a top of cement in the production bore 195 is verified by running a WL tool-string and tagging the internal top of cement. If required, further integrity tests like pressure or inflow testing could then be done.

To provide a high-quality cement barrier between two tubulars, it is important that there is sufficient stand-off between them (i.e. the inner tubular is sufficiently centralized inside the outer one). Centralizes (not shown) may be used to achieve this, and may be installed as part of the original well construction.

With the barriers accepted, the subsea lubricator is then disconnected from the apparatus 1 and recovered to surface.

Following the disconnect of the subsea lubricator, a tubular cutting tool (not shown) is deployed from the vessel and engaged with the apparatus 1 . The cutting mechanism can be mechanical, abrasive or any other type of cutting mechanism able to cut one or multiple tubulars in the well. The cutting mechanism is then used to cut tubulars, such as the tubing string 1 91 , the first casing string 1 1 1 and the second casing string 121 , so that the apparatus 1 may be removed from the seabed. In embodiments wherein the apparatus 1 has a suction caisson, the tubulars will typically be cut at the base of the suction caisson. To remove the apparatus 1 afterwards, positive pressure may be applied inside the suction caisson by use of a ROV pump, to force the suction caisson out of the seabed. The apparatus 1 may then be recovered and placed on the vessel to return to shore.

Figure 14 shows the wellbore 50 after removal of the apparatus 1 .

In the second variant of the method, the procedure may be substantially similar to the procedure described for the first variant of the method, up to and including the step of substantially filling the A annulus 1 15 with cement.

After having substantially filled the A annulus 1 15 with cement, in the second variant of the method, the second hose is detached from the hot-stab receptacle 301 of the passageway 300, and instead connected to the hot-stab receptacle 904 of the further passageway 900, to establish a fluid path from the vessel to the B annulus 125. A wireline tool including a perforating tool is lowered into the wellbore 50, and used to perforate through the tubing string 1 91 , and the first casing string 1 1 1 , and the cement in the A annulus 1 15, to create a circulation path from the production bore 1 95 to the B annulus 125.

The wireline tool is then recovered and the lubricator isolated from the well. Then, fluids are circulated out of the the production bore 195, above the previously set cement plug, and the B annulus 125, and the production bore 195 and the B annulus 125 are cleaned by use of dispersants to enable good cement-to-steel bonding. Following the cleaning, cement is pumped into production bore 195 of the wellbore 50 until cement returns are observed at surface via the hose connected to the hot-stab receptacle 904 of the further passageway 900. The quality of the return cement from the bore in the wall is then tested, and water (or similar) used to displace cement in the production bore 1 95 until desired top of cement is reached in the production bore 1 95. Again, to separate the interface between the cement and the water, a sponge ball is used.

Once the cement plug is in place, the hoses and other external equipment is isolated from the well and cleaned. When the cement plug is hard, the internal tubing top of cement is verified by running a wireline toolstring down through the production bore 195 to tag the internal top of cement. Further integrity tests may be performed if deemed necessary.

Figure 15 shows the apparatus 1 and the wellbore 50 with the cement plug in place in the B annu- lus 125 and the production bore 195.

Then, similarly to the in the first variant of the method, the apparatus 1 is cut from the wellbore 50 and removed. Figure 16 shows how the wellbore 50 may look after removal of the apparatus 1 .

A skilled person will know that the abovementioned descriptions of the first and the second variants are examples of how the method may be performed, and that alternatives may be available for several of the actions mentioned as part of the described variants of the method.

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.

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.

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.