Hybrid-tieback seal assembly

A hybrid-tieback seal assembly and methods for tying a well back to the surface or subsea well head are disclosed. A method to tie a well back to the surface or subsea well head comprises running a hybrid-tieback seal assembly into a wellbore, the hybrid-tieback seal assembly comprising one or more anchoring bodies, one or more packer seal assemblies; and a device for creating a pressure differential in a tieback string, wherein the tieback string is coupled to the hybrid-tieback seal assembly. The method further comprises landing a casing hanger in a well head, increasing pressure in the tieback string, setting the anchoring bodies and one or more packer seal assemblies within at least one of a previously installed liner hanger system and a host casing above a previously installed hanger system, and testing the hybrid-tieback seal assembly down an annulus between the host casing and the tieback string.

BACKGROUND

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.

DETAILED DESCRIPTION

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.

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,FIGS. 1A-1Cdepict a Hybrid-Tieback Seal Assembly (HTSA), denoted generally with reference numeral100, and a downhole liner hanger system, denoted generally with reference numeral130, in accordance with an illustrative embodiment of the present disclosure.FIGS. 1A-1Cshow the HTSA100as it extends from one distal end to another.

In this illustrative embodiment, the liner hanger system130may be run and set in a wellbore (not shown). The liner hanger system130may be disposed within a host casing160. The liner hanger system130may 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 receptacle140. In certain implementations, the receptacle140may include, but is not limited to, a tieback receptacle (TBR) or polished bore receptacle (PBR). Although certain components of the liner hanger system130are 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 HTSA100may be set in the liner hanger system130. In other embodiments, the HTSA100may be set in the hosting casing160, positioned above the liner hanger system130. In the illustrative embodiment shown inFIGS. 1A-1C, the HTSA100is set in the host casing160, positioned above the liner hanger system130. The HTSA100may be coupled to a tieback string101. The HTSA100may comprise one or more anchoring bodies, which may be hydraulically or mechanically set. In certain embodiments in accordance with the present disclosure, the one or more anchoring bodies may include a hold up body111and a hold down body112, which may be hydraulically or mechanically set. The hold up and hold down bodies111,112may include a pusher sleeve113having an anti-backlash system to prevent movement and one or more single direction or bi-directional slips114, which may be independently set. The hold up and hold down bodies111,112also may include a locking device (not shown), such as a lock ring, snap ring, collet, wedge or segmented slip system, and a shear pin. The slips114may be one piece or multiple pieces. Although certain components of the anchoring bodies111,112are 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 or modified without departing from the scope of the present disclosure. The HTSA100may incorporate any suitable slip mechanisms including, but not limited to, slip mechanisms disclosed in U.S. Pat. No. 6,761,221, the entirety of which has been incorporated by reference into the present disclosure.

The HTSA100may also comprise one or more metal to metal packer seal assemblies117which may be hydraulically or mechanically set. The packer seal assembly117may include a packer seal118. 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 assembly117are 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 HTSA100may 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 HTSA100may also comprise a device for creating a pressure differential in the tieback string101. In the illustrative embodiment shown inFIGS. 1A-1C, the HTSA100comprises an inverted float collar150. The inverted float collar150may further comprise a valve155and a mule shoe or wireline entry guide157. The inverted float collar150may allow fluid to enter the tieback string101while the HTSA100is being run into the hole. The valve155in the inverted float collar150may close when the tieback string101is pressured down from the surface so that pressure may be increased in the tieback string101to set the anchoring bodies111,112and/or packer seal assembly117.

In certain embodiments in accordance with the present disclosure, the HTSA100may be run into the wellbore (not shown) and landed in the well head170and set above the receptacle140of the liner hanger system130, within the host casing160. In this manner, the HTSA100may protect the host casing160above the liner hanger system130and may provide zonal isolation up to the surface or subsea well head. The HTSA100also may protect the inner diameter of the tieback string101from pressure located between the tieback string101and the host casing160.

Operation of the HTSA100in accordance with the illustrative embodiment ofFIGS. 1A-1Cwill now be discussed in conjunction withFIG. 2.FIG. 2is a flowchart depicting illustrative method steps associated with a method to tie a well back to the surface or subsea well head using the HTSA100ofFIG. 1, in accordance with an illustrative embodiment of the present disclosure. Although a number of steps are depicted inFIG. 2, as would be appreciated by those of ordinary skill in the art, having the benefit of the present disclosure, one or more of the recited steps may be eliminated, modified, or added without departing from the scope of the present disclosure.

First, at step202, the HTSA100is run into a wellbore (not shown). At step204, the inverted float collar150allows fluid to enter the tieback string101while the HTSA100is being run into the wellbore (not shown). At step206, the casing hanger180is landed in the well head170. As a result of landing the casing hanger180in the well head170, the HTSA100is located within the host casing160, above the liner hanger system130. At step208, tieback string101is pressured down from the surface and the valve155in the inverted float collar150closes to increase the pressure in the tieback string101to set the slips114and packer seal assembly117. At step210, the anchoring bodies111,112of the HTSA100may be set within the host casing160, thus anchoring the HTSA100within the host casing160. The slips114of the anchoring bodies111,112may be used to isolate the HTSA100from movement. The locking device of the anchoring bodies111,112may retain the mechanical load applied to the slips114of the anchoring bodies111,112. At step212, the packer seal118may be mechanically or hydraulically set within the host casing160, above the liner hanger system130. In certain embodiments, the packer seal assembly117may be set last so the HTSA100may be fully anchored prior to setting. At step214, the HTSA100may be tested down the annulus between the host casing160and the tieback string101. At step216, casing hanger180may be fully set, locked, and tested.

FIGS. 3A-11depict a sequence of method steps associated with tying a well back to the surface or subsea well head using the HTSA100ofFIG. 1, in accordance with certain embodiments of the present disclosure.

FIGS. 3A-3Cillustrate how the liner hanger system130may be run into the host casing160below where the HTSA100is to be set. The host casing160may be run to desired depth and hung off in the well head170. The liner hanger system130may then be run and set in the host casing160.

Referring now toFIGS. 4A-4C,FIGS. 4A-4Cillustrate how the HTSA100may be run into the hole and positioned somewhere above the liner hanger system130as it is being landed into the well head170. The HTSA100may comprise an inverted float collar150, one or more anchoring bodies111,112comprising slips114, which are independently hydraulically set, and a metal to metal packer seal assembly117, which is hydraulically set. The inverted float collar150may allow fluid to enter the tieback string101while it is being run into the hole, but when pressuring down the tieback string101from the surface, the valve155in the inverted float collar150may close so pressure may be increased in the tieback string101to set the slips114and packer seal118of the packer seal assembly117. The tieback string101may be coupled to the HTSA100and run in hole. The casing hanger180may be coupled to a casing hanger running tool182. A drill pipe184may be coupled to the casing hanger running tool182and continue to be run in hole. Finally, the HTSA100may be positioned somewhere above the previously run liner hanger system130.

Referring now toFIGS. 5A-5C,FIGS. 5A-5Cillustrate how the hold up body111of the HTSA100may be set. The casing hanger180can be landed into the well head170. Weight from the tieback string101may then be slacked off onto the well head170. In this method, the casing hanger seal186may not be set and the casing hanger lock ring188may not be locked. The tieback string101can then be pressurized to a set pressure, for example 1000 psi, to set the slip114of the hold up body111. This sequence may keep the HTSA100from moving downhole.

Referring now toFIGS. 6A-6C,FIGS. 6A-6Cillustrate how the hold down body112may be set. The tieback string101may be pressurized to a set pressure, for example 2000 psi, to set the slip114of the hold down body112. This sequence may keep the tieback string101from moving up the hole.

Referring now toFIGS. 7A-7C,FIGS. 7A-7Cillustrate how the packer seal assembly117and packer seal118between the HTSA100and the host casing160may be set. The tieback string101may be pressurized to a set pressure, for example 3000 psi. This pressurization may start the packer setting process. The pressure may then be slowly increased to a final pressure, for example 5000 psi, to complete the packer setting process. The packer seal118of the packer seal assembly117is now set within the host casing160, above the liner hanger system130.

Referring now toFIG. 8,FIG. 8depicts the casing hanger running tool182and casing hanger180landed in the well head170. This is the same position before and after the HTSA100is set and sealed. The HTSA100seal may be tested at this time. The HTSA100may be tested down the annulus between the host casing160and the tieback string101. Although certain exemplary method steps are disclosed as suitable for testing the HTSA100, as would be appreciated by those of ordinary skill in the art having the benefit of the present disclosure, any other suitable methods may be used without departing from the scope of the present disclosure.

Referring now toFIGS. 9-11,FIGS. 9-11depict how the tieback may be completed by sealing, locking, and testing the casing hanger180and casing hanger seal186. The casing hanger lock ring188may be set and the casing hanger seal186may be set and tested. A drilling bottom hole assembly (not shown) may then be run in the hole to drill out the inverted float collar150.FIG. 9depicts how the casing hanger running tool182may be unlocked from the casing hanger180.FIG. 10depicts how the casing hanger seal186for the casing hanger180is mechanically loaded, but has not been fully set by pressure assist.FIG. 11depicts how pressure may be applied to fully set the casing hanger seal186and lock the seal into the well head170. The casing hanger seal186may then be tested. Although certain exemplary method steps are disclosed as suitable for setting, locking, and testing the casing hanger180, as would be appreciated by those of ordinary skill in the art having the benefit of the present disclosure, any other suitable methods may be used without departing from the scope of the present disclosure.

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 HTSA100and the liner hanger system130, the casing hanger180may be landed without any special considerations or allowances for the position of the HTSA100within the host casing160or the liner hanger system130. Specifically, the casing hanger180may be landed regardless of the position of the HTSA100within the host casing160or the liner hanger system130. The system further eliminates the need for slack off weight or slack off distance to set the HTSA100in part due to the ability to the set within the host casing160or the liner hanger system130and the utilization of a pressure differential created in the tieback string101to set the HTSA100.

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.