Apparatus and Method of Connecting Tubular Members In Multi-Lateral Wellbores
A method of casing connection in a multilateral well. A tieback tubular component is located in a wellbore below the casing window. A lateral completion tubular component is installed in the casing window. Tubular members can then be located in the tieback tubular component and the lateral completion component which are expanded by internal pressure to form a seal.
The present invention relates to apparatus and methods of connecting tubular members in a wellbore which is provided with at least one lateral well bore.
Oil and gas wells are completed by forming a borehole in the earth and then lining the borehole with a steel casing to form a wellbore. Typically, a number of sections of casing are used. A first section of casing is lowered into the wellbore and hung from the surface after the well has been drilled to a first designated depth. Cement is then circulated in the annulus between the outer wall of the casing and the borehole. The well is then drilled to a second designated depth and a second section of casing, having a smaller diameter, is run into the well. The second section may either be “hung off” in a well head at a surface or is set at a depth such that the upper portion of the second section overlaps the lower portion of the first section casing. If, in this second example, the casing does not extend to the surface, then the casing is referred to as a liner. The liner section is then fixed to the first section, such as by using a liner hanger. The second casing section of liner is then cemented. This process is typically repeated with additional casing sections of increasing diameter until the well has been drilled to the total required depth.
In some well completion schemes it may be necessary to connect the liner string back to the surface, or at a point higher up in the well. A string of tubing is then connected to the top of the liner section and, in this manner, the casing section is sealingly “tied back” to the surface or a point higher in the well.
Known methods for connecting a string of tubing into a downhole liner section typically involve the use of a polished bore receptacle (PBR) tool which is screwed to the top of the liner section. The PBR has a smooth cylindrical inner bore configured to receive the lower end of the tieback tubing which is provided with seals on its outer diameter to seal within the PBR when the two are brought into communication with one another. However, thermal expansion and contraction of the liner, during which time the seals can move up and down within the PBR leads to seal wear and ultimately seal failure.
An alternative system for connecting a string of tubing to a lower section of liner involves the creation of metal to metal seals between the two tubular members using a tool which applies radial outward pressure at an overlap section where the first tubular is inserted into a second tubular. The outward pressure applied is sufficient to urge the inner tubular member into contact with the outer tubular member by elastically, then plastically deforming. Such a method of tubular member connection is described in GB2474692 the entire disclosure of which is incorporated herein by reference. Metal to metal seals formed in this manner have resistance to thermally generated axial loads meaning there is little or no movement which thus reduces wear on the joint.
Whilst such a system has increased utility for insertion of tieback, or reconnect, systems to aid in maximization of extraction from a zone, in practice it is often useful for lateral wellbores to be added to existing wellbores. Lateral wellbores enable easier and cheaper oil and gas extraction for large or closely grouped multiple production zones. Creating and casing laterals and connecting these to an existing wellbore can be a complex and expensive process.
It is therefore an object of at least one embodiment of the present invention to provide a coupling system between tubulars which can facilitate the creating and casing of lateral wellbores which mitigates at least one of the disadvantages of the prior art.
According to a first aspect of the invention there is provided a method of connecting a first tubular member arrangement to a second tubular member located in a wellbore below a window to a wellbore lateral and to a third tubular member located in the wellbore lateral, wherein the first tubular member is provided with a tubing diverter having a lateral tubular diverter component, and a lower end portion, the second tubular member includes an upper end portion which has a greater diameter than the diameter of the first tubular member lower end portion, and the third tubular member includes an upper end portion which has a greater diameter than the diameter of the lateral tubular diverter component, the method comprising:
lowering the lower end portion of the first tubular member into the wellbore until the lower end portion is located at least within the bore of the upper end portion of the second tubular member; aligning the tubing diverter with the wellbore lateral;
actuating the tubing diverter until the lateral tubular diverter component is located at least within the bore of the upper end portion of the third tubular member;
expanding the lower end portion until the lower end portion is resiliently connected to the second tubular member, and expanding the lateral tubular diverter component until the lateral tubular component is resiliently connected to the third tubular member.
By resiliently connecting a first tubular component to a tubular component within a wellbore as well as to a tubular component within an associated lateral enhanced production from a zone can be easily implemented.
The method may further include the step of running the first tubular component from a surface location to the second tubular member and third tubular member. By running the first tubular component from the surface, production from each of the wellbore and wellbore lateral can be transferred to the surface via one surface exit point.
The method may include providing the upper end portion of the second tubular member with a tieback component to which the first tubular member is resiliently connected. Provision of a tieback component at the second tubular member enables production from the wellbore to continue in conjunction with, or on an alternating basis, with any production from the lateral wellbore.
The method may include the step of applying internal fluid pressure to the tubing diverter to actuate the diverter to an operational status such that the lateral tubular diverter component is inserted into the lateral wellbore. The lateral tubular diverter component may be a tubular member. The use of applying internal fluid pressure to the tubular diverter encourages a junction within the tubular diverter to open and encourages the diverter component to be directed into the lateral wellbore.
Each tubular member may be formed of a metal based material. The use of metal based materials in each of the tubular members ensures that during the application of pressure to create the resilient seal, a metal to metal seal is formed.
The tubular member inserted into the lateral wellbore may be secured using a mechanism which also forms a wellbore formation zonal barrier. Such a securing mechanism, for example a hydraulically morphed tubular sleeve or the like will act both to secure the tubular member whilst providing a barrier between formation zones thus preventing cross contamination.
According to another aspect of the invention there is provided a method of forming and connecting a wellbore lateral to an existing wellbore, the method comprising the steps of:
inserting from a surface location a tieback tubular component into a wellbore casing;
mill a casing window in the casing at a location between the surface and the tieback component;
install a lateral completion tubular component in the casing window;
insert a first tubular member into the wellbore, the first tubular member being provided with a lower end portion having a diameter which is less than a bore diameter of the tieback component and a tubular diverter portion having a lateral tubular component with a diameter which is less than a bore diameter of the lateral completion component;
align the first tubular member with the wellbore lateral;
locate the lower end portion at least within the bore of the tieback component;
actuate the tubing diverter until the lateral tubular component is located at least within the bore of the lateral completion component;
expand the lower end portion until the lower end portion is resiliently connected to the second tubular member, and
expand the lateral tubular component until the lateral tubular component is resiliently connected to the third tubular member.
Such a method provides for lateral to be formed in an existing wellbore and resilient seals being implemented between the existing wellbore tubular and a first tubular as well as the new lateral tubular and the first tubular at the time for lateral formation such that production from each of the wellbore and lateral can be achieved.
The method may include the step of applying internal fluid pressure to the tubing diverter to actuate the diverter to an operational status such that the lateral tubular diverter component is inserted into the lateral wellbore. The lateral tubular diverter component may be a tubular member. The use of applying internal fluid pressure to the tubular diverter encourages a junction within the tubular diverter to open and encourages the diverter component to be directed into the lateral wellbore.
Each tubular component may be formed of a metal based material. The use of metal base materials in each of the tubular members ensures that during the application of pressure to create the resilient seal, a metal to metal seal is formed.
Further features are embodied in the description.
In the description that follows, the drawings are not necessarily to scale. Certain features of the invention may be shown to be exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce the desired results.
Accordingly, the drawings and descriptions are to be regarded as illustrative in nature, and not as restrictive. Furthermore, the terminology and phraseology used herein is solely used for descriptive purposes and should not be construed as limiting in scope. Language such as “including,” “comprising,” “having,” “containing,” or “involving,” and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited, and is not intended to exclude other additives, components, integers or steps. Likewise, the term “comprising” is considered synonymous with the terms “including” or “containing” for applicable legal purposes.
All numerical values in this disclosure are understood as being modified by “about”. All singular forms of elements, or any other components described herein including (without limitations) components of the apparatus are understood to include plural forms thereof. All positional terms such as ‘up’ and ‘down’, ‘left’ and ‘right’ are relative and apply equally in opposite and in any direction.
Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings in which:
The method of the present invention relates to the provision of a formation and casing connection system for multilateral wells. Referring initially to
A connection member, shown as a tieback receptacle 18, is secured within the casing 12 using a known method such as by use of a securing collar 20, which secures receptacle 18 to the internal surface 22 of the wall 23 of casing 12.
The tieback receptacle 18 is substantially cylindrical in form having a bore 19 therethrough and upper opening 24 of receptacle 18 is of a first diameter. The tieback receptacle 18 is of metal construction. The internal surface 26 of receptacle 18 is provided with metal protrusions 28 which annularly run around the circumference of internal wall surface 26.
A lateral wellbore 30 is then provided, as is shown in
The lateral borehole can then be completed as necessary either as an open hole or cased completion or with well treatment or prosecution production equipment being inserted with a lateral receptacle 38 being positioned with its upper opening 40 adjacent casing window 32 as is shown in
The lateral receptacle 38 is substantially cylindrical in form having a bore 39 therethrough and upper opening 40 of receptacle 38 is of a second diameter which may or may not be the same as the first diameter of receptacle 18. The lateral receptacle 38 is of metal construction. The internal surface 42 of receptacle 38 is provided with metal protrusions 44 which annularly run around the circumference of internal wall surface 42.
Subsequently, an upper completion tubular 50, such as is shown in
The lateral wellbore tubing 53 is formed of metal, has a substantially cylindrical form with a bore therethrough, and has lower end tubular portion 54 of a third diameter which is less than the second diameter of receptacle 38.
The lower completion tubing string 51 is similarly formed of metal, is substantially cylindrical in form having a bore therethrough and with a lower tubular portion 55 which is of a forth diameter which is less than the first diameter of receptacle 18.
When the completion tubular 50 is being inserted into casing 12, standard alignment techniques, which are also well known in the art, can be implemented to ensure the completion tubular 50 is aligned appropriately with the well bore 12 and lateral 30. The mechanism of the diverter component 52 has then fluid pressure, or morph pressure, applied by a tool (not shown) which causes the diverter mechanism to open, or latch advancing tubing strings 51 and 53. The opening of the latch mechanism using fluid pressure causes the advancing of the lower end tubular portion 54 which is then encouraged, by way of the fluid pressure being applied to the diverter 52, to find and move into the lateral wellbore 30. The fluid pressure may be applied in any suitable manner, for example by using a hydraulic tool (not shown), or by the application of fluid pressure at the surface of the wellbore (not shown).
Advancing tubular strings 51 and 53 continue until end 55 of string 51 is received in receptacle 18 and end 54 of string 53 is received in receptacle 38 as is shown in
A metal to metal seal is then created between receptacle 18 and tubular string 51 by force being applied to the inner surface of tubular string 51 at the end portion 55 where overlap with receptacle 18 occurs. The seal may be created by use of a hydraulic tool 60 which is inserted into the tubular string 51 as is shown in
A detailed description of the operation of such a hydraulic tool is described in GB2398132 in relation to the packer tool 112 of
The tool 60 is inserted into the tubular string 51 and receptacle 18 overlap within the bore of tubular string 51. Elastomeric seals 62, 64 are arranged on the tool are then energised to that they expand radially outwardly and create a seal between the outer surface of the tool body and the inner surface bore of the tubular string 51. A bounded chamber is thus created between the seals 62, 64 and hydraulic fluid is then pumped through the tool body so that it enters the chamber. Once the chamber is filled, continued pumping forces the outer surface of the tubular string end portion 55 to move radially outwards by the use of fluid pressure acting directly on the inner surface between the seals 62, 64. Sufficient hydraulic fluid pressure is applied to cause the tubular member to morph itself around projections 28 onto the inner surface 26 of the receptacle 18. During the morphing process, the tubular string end 55 will undergo elastic expansion and continued expansion will cause the tubular string end 55 to undergo plastic deformation, conforming at least partially to the projections 28 and inner surface 26. Sufficient pressure may be applied to also cause the receptacle 18 to undergo elastic deformation and expand by a small amount as contact is made. Pumping of the hydraulic fluid is then stopped. As the pressure is released the receptacle 18 returns to its original dimensions and creates a metal to metal seal against the deformed end 55 of tubular string 51. The tool 60 can then be removed from string 51.
The tool 60 can then be inserted into tubular string 53 as illustrated in
It will be appreciated to one skilled in the art that if the second diameter of tubular 51 and fourth diameter of tubular 53 differ, the size of tool 60 deployed to apply hydraulic morphing pressure and create the metal to metal seal required between tubular 51 and receptacle 18, and tubular 53 and receptacle 38 respectively will differ as necessary to achieve the necessary result.
The method of casing connection for laterals has been illustrated with respect to one lateral wellbore 30. However, it will be appreciated that any number of lateral wellbores may have casing connections formed using the method detailed above.
A principle advantage of the present invention is that it provides a method which facilitates the simple formation, casing and connection of a lateral wellbore to an existing wellbore.
A further advantage of the present invention is that is provides a method of casing connection in a multilateral well which utilises a metal to metal seal between members without requiring a screw thread.
It will be appreciated by those skilled in the art that modifications may be made to the invention herein described without departing from the scope thereof. For example, tubular members and receptacle units have been described as metal structures, however, only the end portions need to have metal construction to form the metal to metal seal required and thus the tubular members may be of composite form with metal ends. In addition, whilst illustrative examples of whipstock systems, diverter joints and morph tools have been described, any suitable system may be substituted.
Claims
1. A method of connecting a first tubular member arrangement to a second tubular member located in a wellbore below a window to a wellbore lateral and to a third tubular member located in the wellbore lateral, wherein the first tubular member is provided with a tubing diverter having a lateral tubular diverter component, and a lower end portion, the second tubular member includes an upper end portion which has a greater diameter than the diameter of the first tubular member lower end portion, and the third tubular member includes an upper end portion which has a greater diameter than the diameter of the lateral tubular diverter component, the method comprising:
- lowering the lower end portion of the first tubular member into the wellbore until the lower end portion is located at least within the bore of the upper end portion of the second tubular member;
- aligning the tubing diverter with the wellbore lateral;
- actuating the tubing diverter until the lateral tubular diverter component is located at least within the bore of the upper end portion of the third tubular member;
- expanding the lower end portion until the lower end portion is resiliently connected to the second tubular member, and
- expanding the lateral tubular diverter component until the lateral tubular component is resiliently connected to the third tubular member.
2. A method according to claim 1 wherein the method further includes the step of running the first tubular component from a surface location to the second tubular member and third tubular member.
3. A method according to claim 1 wherein the method includes providing the upper end portion of the second tubular member with a tieback component to which the first tubular member is resiliently connected.
4. A method according to claim 1 wherein the method includes the step of applying internal fluid pressure to the tubing diverter to actuate the diverter to an operational status such that the lateral tubular diverter component is inserted into the lateral wellbore.
5. A method according to claim 1 wherein the lateral tubular diverter component is a tubular member.
6. A method according to claim 1 wherein each tubular member is formed of a metal based material.
7. A method according to claim 1 wherein the tubular member inserted into the lateral wellbore is secured using a mechanism which also forms a wellbore formation zonal barrier.
8. A method according to claim 7 wherein the mechanism is via a hydraulically morphed tubular sleeve.
9. A method of forming and connecting a wellbore lateral to an existing wellbore, the method comprising the steps of:
- inserting from a surface location a tieback tubular component into a wellbore casing;
- mill a casing window in the casing at a location between the surface and the tieback component;
- install a lateral completion tubular component in the casing window;
- insert a first tubular member into the wellbore, the first tubular member being provided with a lower end portion having a diameter which is less than a bore diameter of the tieback component and a tubular diverter portion having a lateral tubular component with a diameter which is less than a bore diameter of the lateral completion component;
- align the first tubular member with the wellbore lateral;
- locate the lower end portion at least within the bore of the tieback component;
- actuate the tubing diverter until the lateral tubular component is located at least within the bore of the lateral completion component;
- expand the lower end portion until the lower end portion is resiliently connected to the tieback component, and
- expand the lateral tubular component until the lateral tubular component is resiliently connected to the lateral completion component.
10. A method according to claim 9 wherein the method includes the step of applying internal fluid pressure to the tubing diverter to actuate the diverter to an operational status such that the lateral tubular diverter component is inserted into the lateral wellbore.
11. A method according to claim 9 wherein the lateral tubular diverter component is a tubular member.
12. A method according to claim 9 wherein each tubular component is formed of a metal based material.
Type: Application
Filed: Aug 6, 2015
Publication Date: Feb 18, 2016
Inventor: David Glen Martin (Keith)
Application Number: 14/820,014
