The present invention relates generally to tieback assemblies and, more particularly, to hybrid-tieback seal assemblies and associated methods of tying a well back to the surface or subsea well head.
Current methods used to tie a well back to the surface or subsea well head from an existing downhole liner hanger employ running a tieback string into the well. These tieback strings typically have seals at their bottom end that stab into a tieback receptacle or polished bore receptacle of an existing downhole liner hanger. This typical approach may be problematic due to the small space out window (i.e., length of space available to stab into the tieback receptacle), which is typically dictated by the length of the tieback receptacle. This typical approach may also be problematic in applications where the existing liner hanger is one that is very thin and as a result has a very low collapse value. When attempting typical tieback methods with thin liner hanger systems, there is a risk of collapsing the tieback receptacle, liner top, and/or tieback string. These thin liner hanger systems typically include, but are not limited to, the following sizes: 7⅝×9⅝, 9⅝×11¾, 11¾×13⅝, and 13⅝×16. As a result, a new and improved method of tying a well back to the surface or subsea well head is desirable.
Some specific exemplary embodiments of the disclosure may be understood by referring, in part, to the following description and the accompanying drawings.
While embodiments of this disclosure have been depicted and described and are defined by reference to exemplary embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure.
The present invention relates generally to tieback assemblies and, more particularly, to hybrid-tieback seal assemblies and associated methods of tying a well back to the surface or subsea well head.
The terms “couple” or “couples” as used herein are intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect mechanical or electrical connection via other devices and connections. Similarly, the term “fluidically coupled” as used herein is intended to mean that there is either a direct or an indirect fluid flow path between two components. The term “uphole” as used herein means along the drillstring or the hole from the distal end towards the surface, and “downhole” as used herein means along the drillstring or the hole from the surface towards the distal end.
The present disclosure is directed to a system where a tieback string is set and sealed in an existing downhole liner hanger system, or into the host casing above the downhole liner hanger system. Setting and sealing the tieback string in the host casing above the liner hanger system may allow for the tieback receptacle or liner top of the liner hanger system to be isolated so it remains pressure balanced and has no risk of collapse. This system may incorporate the slips, sealing technologies, and other disclosures found in U.S. Pat. Nos. 6,761,221 and 6,666,276, the entireties of which are hereby incorporated by reference. This system may also be used with any well head system.
Illustrative embodiments of the present invention are described in detail herein. In the interest of clarity, not all features of an actual implementation may be described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the specific implementation goals, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure.
To facilitate a better understanding of the present invention, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the invention. Embodiments of the present disclosure may be used with any well head system. Embodiments of the present disclosure may be applicable to horizontal, vertical, deviated, or otherwise nonlinear wellbores in any type of subterranean formation. Embodiments may be applicable to injection wells as well as production wells, including hydrocarbon wells.
In certain embodiments, the present disclosure provides a method to tie a well back to the surface or subsea well head using a Hybrid-Tieback Seal Assembly (HTSA). In one embodiment, the tieback string is allowed to fill with fluid while running into the hole. In another embodiment, the present disclosure provides a method where pressure is allowed to build from the surface in the tieback string to actuate downhole devices. In certain embodiments, a device may be used to create a pressure differential in the tieback string. In one illustrative embodiment, the use of an inverted float collar may allow for fluid to enter the tieback string while being run into the hole. Once the tieback string is pressurized, the valve in the collar may close so that pressure may be increased in the tieback string to set slips and seals. In other embodiments, a downhole ball seat in the tieback string may be used and a ball may be dropped from the surface when it is desirable to set the HTSA. In this embodiment, when the ball is dropped from the surface and lands on the ball seat, it may act as a pressure barrier providing a pressure differential. Although certain exemplary devices are disclosed as suitable for use in creating a pressure differential in the tieback string, as would be appreciated by those of ordinary skill in the art having the benefit of the present disclosure, any other suitable device (e.g., plugs) may be used to create a pressure differential in the tieback string without departing from the scope of the present disclosure.
In certain embodiments, the methods discussed herein may incorporate slips that are independently hydraulically set and locked. These slips may be used to lock the tieback string from any movement up or down that could damage the seal between the tieback string and the host casing. In certain embodiments, the slips may be one piece or multiple pieces. In other embodiments, the methods discussed herein may incorporate the use of a metal to metal packer seal which may be hydraulically set.
Referring now to the Figures,
In this illustrative embodiment, the liner hanger system 130 may be run and set in a wellbore (not shown). The liner hanger system 130 may be disposed within a host casing 160. The liner hanger system 130 may comprise, but is not limited to, a packer seal, a running adapter, a hanger body, a slip, a packer cone, a pusher sleeve, a lock ring, a liner top and/or a receptacle 140. In certain implementations, the receptacle 140 may include, but is not limited to, a tieback receptacle (TBR) or polished bore receptacle (PBR). Although certain components of the liner hanger system 130 are discussed for illustrative purposes, it would be appreciated by those of ordinary skill in the art, having the benefit of the present disclosure, that one or more components may be removed, modified, or added without departing from the scope of the present disclosure.
In certain embodiments in accordance with the present disclosures, the HTSA 100 may be set in the liner hanger system 130. In other embodiments, the HTSA 100 may be set in the hosting casing 160, positioned above the liner hanger system 130. In the illustrative embodiment shown in
The HTSA 100 may also comprise one or more metal to metal packer seal assemblies 117 which may be hydraulically or mechanically set. The packer seal assembly 117 may include a packer seal 118. The packer seal assembly may also include, but is not limited to, a packer body, a pusher sleeve, a lock ring, a shear pin, a locking assembly, and/or a lock body. Although certain components of the packer seal assembly 117 are discussed for illustrative purposes, it would be appreciated by those of ordinary skill in the art, having the benefit of the present disclosure, that one or more components may be removed, modified, or added without departing from the scope of the present disclosure. The HTSA 100 may incorporate sealing technology disclosed in U.S. Pat. No. 6,666,276, the entirety of which has been incorporated by reference into the present disclosure.
In certain embodiments, the HTSA 100 may also comprise a device for creating a pressure differential in the tieback string 101. In the illustrative embodiment shown in
In certain embodiments in accordance with the present disclosure, the HTSA 100 may be run into the wellbore (not shown) and landed in the well head 170 and set above the receptacle 140 of the liner hanger system 130, within the host casing 160. In this manner, the HTSA 100 may protect the host casing 160 above the liner hanger system 130 and may provide zonal isolation up to the surface or subsea well head. The HTSA 100 also may protect the inner diameter of the tieback string 101 from pressure located between the tieback string 101 and the host casing 160.
Operation of the HTSA 100 in accordance with the illustrative embodiment of
First, at step 202, the HTSA 100 is run into a wellbore (not shown). At step 204, the inverted float collar 150 allows fluid to enter the tieback string 101 while the HTSA 100 is being run into the wellbore (not shown). At step 206, the casing hanger 180 is landed in the well head 170. As a result of landing the casing hanger 180 in the well head 170, the HTSA 100 is located within the host casing 160, above the liner hanger system 130. At step 208, tieback string 101 is pressured down from the surface and the valve 155 in the inverted float collar 150 closes to increase the pressure in the tieback string 101 to set the slips 114 and packer seal assembly 117. At step 210, the anchoring bodies 111, 112 of the HTSA 100 may be set within the host casing 160, thus anchoring the HTSA 100 within the host casing 160. The slips 114 of the anchoring bodies 111, 112 may be used to isolate the HTSA 100 from movement. The locking device of the anchoring bodies 111, 112 may retain the mechanical load applied to the slips 114 of the anchoring bodies 111, 112. At step 212, the packer seal 118 may be mechanically or hydraulically set within the host casing 160, above the liner hanger system 130. In certain embodiments, the packer seal assembly 117 may be set last so the HTSA 100 may be fully anchored prior to setting. At step 214, the HTSA 100 may be tested down the annulus between the host casing 160 and the tieback string 101. At step 216, casing hanger 180 may be fully set, locked, and tested.
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As would be appreciated by those of ordinary skill in the art, with the benefit of this disclosure, in certain implementations, due to the configuration of the HTSA 100 and the liner hanger system 130, the casing hanger 180 may be landed without any special considerations or allowances for the position of the HTSA 100 within the host casing 160 or the liner hanger system 130. Specifically, the casing hanger 180 may be landed regardless of the position of the HTSA 100 within the host casing 160 or the liner hanger system 130. The system further eliminates the need for slack off weight or slack off distance to set the HTSA 100 in part due to the ability to the set within the host casing 160 or the liner hanger system 130 and the utilization of a pressure differential created in the tieback string 101 to set the HTSA 100.
Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. The indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces.
This application claims priority to U.S. Provisional Patent Application Ser. No. 61/644,168 filed May 8, 2012, which is incorporated herein by reference.
Number | Name | Date | Kind |
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7861789 | Nelson | Jan 2011 | B2 |
20120222861 | Eriksen | Sep 2012 | A1 |
Number | Date | Country |
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0515742 | Dec 1992 | EP |
Entry |
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Search Report issued in corresponding Great Britain Patent Application No. GB1308172.4, mailed Oct. 25, 2013, 3 pages. |
Number | Date | Country | |
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20130299176 A1 | Nov 2013 | US |
Number | Date | Country | |
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61644168 | May 2012 | US |