PERFORMING A WELLBORE TIEBACK OPERATION

Abstract

A wellbore tieback system that includes a liner, a tieback string, and a seal system. The liner is disposed within a wellbore and defines an annulus between an external surface of the liner and a wall of the wellbore. The tieback string has a receptacle end that defines an inner diameter larger than an outer diameter of the liner such that the receptacle end can be disposed within the annulus to receive a portion of the liner. The seal system is coupled to an internal surface of the receptacle end. The seal system has at last one annular seal that swells inwardly to form, with the portion of the liner inserted within the receptacle end, a seal with the external surface of the liner. The tieback string is fluidly coupled, with the seal formed, to the liner to receive production fluid from the liner.

Description

FIELD OF THE DISCLOSURE

This disclosure relates to wellbore equipment, and more particularly to equipment for wellbore drilling and completion.

BACKGROUND OF THE DISCLOSURE

Wells can be used for hydrocarbon production or other purposes such as for well stimulation or fluid injection. In the case of production wells, a wellbore can be drilled into a hydrocarbon-rich geological formation to extract hydrocarbons from the formation. Before beginning production, a completion system is installed to prepare the wellbore for production or injection. The completion system can include one or more casings or liners cemented in the wellbore to help control the well and maintain well integrity. Methods and equipment for operating and maintaining cased wellbores are sought.

SUMMARY

Implementations of the present disclosure include a wellbore tieback system that includes a liner, a tieback string, and a seal system. The liner is disposed within a wellbore and defines an annulus between an external surface of the liner and a wall of the wellbore. The tieback string has a receptacle end that defines an inner diameter larger than an outer diameter of the liner such that the receptacle end can be disposed within the annulus to receive a portion of the liner. The seal system is coupled to an internal surface of the receptacle end. The seal system has at last one annular seal that swells inwardly to form, with the portion of the liner inserted within the receptacle end, a seal with the external surface of the liner. The tieback string is fluidly coupled, with the seal formed, to the liner to receive production fluid from the liner.

In some implementations, the tieback string includes a tubular body extending from or near a terranean surface of the wellbore to the receptacle end. The tubular body defines an inner diameter substantially equal to or greater than an inner diameter of the liner.

In some implementations, the seal system includes three or more seals distributed along a length of the receptacle end. The annular seals include swellable seals configured to swell upon exposure to a wellbore fluid to form the seal. The wellbore fluid can be a water-based fluid (e.g., treated water, fresh water, brine, water based mud, or seawater) that activates swellable seal systems. In some implementations, the wellbore fluid is at a temperature of between 150 and 350 degrees Fahrenheit when the fluid touches the swellable seals. In some implementations, the swellable seals include an elastomer configured to absorb fluid to swell over a period of time.

In some implementations, the liner is partially cemented in the wellbore. The annulus extends from an uphole inlet of the liner to a liner hanger or cement disposed between the liner and a wall of the wellbore.

In some implementations, the seal fluidly isolates the annulus from a bore of the tieback string and a bore of the liner.

In some implementations, the liner includes a monobore completion liner, and the portion of the liner includes an uphole fluid inlet formed upon cutting the liner and retrieving a second portion of the liner uphole of the portion of the liner.

Implementations of the present disclosure include a wellbore assembly that includes a casing pipe configured to be disposed within a wellbore. The casing pipe defines, with the casing pipe set on the wellbore, an annulus between an external surface of the casing pipe and a wall of the wellbore. The wellbore string is disposed within the wellbore. The wellbore string includes a downhole end defining an inner diameter larger than an outer diameter of an uphole end of the casing pipe. The downhole end includes at least one internal, annular seal configured to swell to form, with the uphole end of the casing pipe inserted within the downhole end of the wellbore string, a seal with the external surface of the casing pipe. The wellbore string is fluidly coupled, with the seal formed, to the casing pipe to flow fluid between the wellbore string and the casing pipe.

In some implementations, the wellbore string includes a tubular body extending from or near a terranean surface of the wellbore to the downhole end. The tubular body defines an inner diameter equal to or greater than an inner diameter of the casing pipe.

In some implementations, the downhole end includes three or more seals distributed along a length of the downhole end. The annular seals are swellable seals configured to swell upon exposure to a wellbore fluid to form the seal. In some implementations, the wellbore fluid is at a temperature of between 150 and 350 degrees Fahrenheit when the fluid touches the swellable seals. In some implementations, the swellable seals include an elastomer configured to absorb fluid to swell over a time period of, for example, 3 to 5 days until the seals contact the liner and form the seal. In some implementations, each swellable seal is disposed within a respective internal groove of the downhole end. Each swellable seal including a compliant external surface configured to swell from the groove toward the external surface of the casing pipe.

In some implementations, the casing pipe is partially cemented in the wellbore. The annulus extends from an uphole inlet of the casing pipe to a casing pipe hanger or packer or cement disposed between the casing pipe and a wall of the wellbore.

In some implementations, the seal fluidly isolates the annulus from a bore of the wellbore string and a bore of the casing pipe.

In some implementations, the casing pipe includes a monobore completion casing pipe, and the portion of the casing pipe includes an uphole fluid inlet formed upon cutting the casing pipe and retrieving a second portion of the casing pipe uphole of the portion of the casing pipe.

Implementations of the present disclosure include a method that includes running a tieback string within a wellbore including a liner defining an annulus between an external surface of the liner and a wall of the wellbore. The tieback string includes a receptacle end that has an inner diameter larger than an outer diameter of the liner. The receptacle end includes at least one annular seal configured to swell inwardly to form, with the portion of the liner inserted within the receptacle end, a seal with the external surface of the liner. The method also includes positioning the receptacle end around a portion of the liner. The method also includes activating the at least one annular seal to form, with the external surface of the liner, a seal. The tieback string is fluidly coupled, with the seal formed, to the liner to receive production fluid from the liner.

In some implementations, the method also includes, before running the tieback string within the wellbore, cutting the liner and retrieving an upper portion of the liner to form the portion of the liner.

In some implementations, activating the annular seal includes flowing, from a terranean surface of the wellbore and through the tieback string, a fluid configured to reach the at least one annular seal at a temperature of between 150 and 350 degrees Fahrenheit.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic view, partially cross-sectional, of a wellbore assembly disposed within a wellbore according to an implementation of the present disclosure.

FIGS. 2-3 are front schematic views, partially cross-sectional, of sequential steps of installing a tieback string.

FIGS. 3-5 are front schematic views, partially cross-sectional, of sequential steps of forming a seal with the tieback string in FIGS. 2-3.

FIG. 6 is a flow chart of a method of setting a tieback string.

DETAILED DESCRIPTION OF THE DISCLOSURE

The present disclosure relates to methods and equipment for providing a tieback string in a wellbore without reducing the internal diameter of the completion system and while reducing the complexity of installing a tieback string. A tieback string (e.g., a tie-back liner or a drilling tie-back) is a piping string that extends from a terranean surface of the wellbore to a liner to fluidly connect the liner to the surface. A tieback string can be used to provide the necessary pressure capacity during a flow-test period or for special treatments, and is typically not cemented in place. In some cases, a tieback string can be installed as a remedial solution when the integrity of the intermediate casing string is in doubt. For example, the wellbore casing (or other tubulars) can be exposed to extreme corrosive and abrasive conditions that adversely affect the casing and well integrity by reducing the wall thickness or otherwise damaging the casing. The tieback string can be installed to flow the wellbore fluids without exposing the damaged casing to the wellbore fluids.

The tieback string of the present disclosure includes a piping string and a receptacle end with internal seals. The internal seals expand or swell to form a seal with an external surface of the liner. The internal seals can be swellable seals that are expand upon coming into contact with a hot fluid flow from the surface or from the formation to the surface.

Particular implementations of the subject matter described in this specification can be implemented so as to realize one or more of the following advantages. For example, the tieback system of the present disclosure can provide a tieback string without reducing the internal diameter of the production (or injection) tubing, and thus maintaining or increasing the flow rate of the wellbore and providing full wellbore accessibility. The tieback system of the present disclosure can also reduce operational complexity by providing a seal with rough or uneven surfaces, and eliminate the need of additional scraper runs to clean casing surfaces especially during re-completion operations. Additionally, the tieback system of the present disclosure may not require any axial or rotational movement or force to set and expand the sealing elements. Additionally, the tieback system of the present disclosure may not require hydraulic pressure or pumping any fluids to activate the sealing elements. Such features can help minimize the number of trips needed for re-completion or otherwise attaching a tieback string to a liner.

FIG. 1 illustrates a wellbore assembly 100 that includes a production string 110 or liner disposed within a wellbore 102. The wellbore 102 is formed in a geologic formation 101. The geologic formation 101 includes a hydrocarbon reservoir 105 from which production fluid “F” (e.g., hydrocarbons) can be extracted. The wellbore 102 extends from a surface 111 (e.g., a terranean surface) to a downhole end 109 of the wellbore 102. The wellbore 102 can include a casing 107 disposed within the wellbore 102 and extending from the surface 111 to a casing shoe of the casing. The casing 107 is cemented on the wellbore 102.

The wellbore 102 is shown as a vertical wellbore, however, the concepts of the present disclosure are applicable to other different configurations of wells, including horizontal wellbores, slanted wellbores (or otherwise deviated wellbores), wellbores with partially cemented monobore tubing, wellbores with longstring casing, or wellbores with partially cemented monobore casing. The wellbore 102 extends from surface equipment 112 such as a wellhead or a rig.

The liner 110 can be installed within the wellbore 102 during completion of the wellbore 102. The liner 110 is partially cemented with a cement layer “C.” For example, the liner 110 has an upper or uphole portion 115 exposed to form, with the wall 113 (e.g., the casing wall) of the wellbore 102, an empty annulus “A.” The liner 110 can be attached to the casing 107 and cemented below the casing, or (as shown in FIG. 1) the liner 110 can be detached from the casing and retained by the cement “C” in an open hole section of the wellbore 102. The cement “C” extends around a portion of the casing 110. For example, the cement “C” can extend from the downhole end 109 of the wellbore 102 to a top of cement 106.

The liner 110 can extend from the surface 111 to the production area to form a monobore completion (e.g., with the liner 110 arranged as a monobore completion with cemented liner). For example, the liner 110 extends from the surface 111 of the wellbore 102 to the target zone or reservoir 105 to flow the production fluid “F” to the surface. The liner 110 can have one or more defects 117 (e.g., corrosion, erosion, pinhole, micro-cracks, fractured pipe, tubular wall thickness reduction, overtorque joint, collapsed pipe, burst pipe, or any obstruction or internal diameter reduction) at the uphole portion. The defect can serve as a point of reference for the location of the cut (the cut being below the lowest defect) to remove the defective liner section that extends from the cut to the surface 111 of the wellbore.

FIGS. 2 and 3 show sequential steps for installing a tieback liner in the monobore completion shown in FIG. 1. Referring to FIG. 2, the liner 110 is shown after cutting the liner 110 above the cement “C.” The portion of the liner 110 that extended from the cut to the surface 111 is retrieved to allow the tieback string to be lowered within the wellbore 102. The liner 110 has an uphole fluid inlet 120 that is formed upon cutting the liner 110 and retrieving the portion of the liner that was uphole of the cemented liner section. For example, the fluid inlet 120 can be formed by an annular cutting that detaches the upper portion from the lower portion of the liner 110. The upper portion can be the damaged portion of the liner 110.

Referring now to FIG. 3, the wellbore assembly 100 includes a tieback system 103 that includes a tieback string 130 and the partially cemented liner 110. After the upper portion of the liner is removed from the wellbore 102, the tieback string 130 is disposed within the wellbore 102 and the tieback string 130 is ran to the liner 110. The open end of the tieback string 130 moves along the annulus 114 around the upper portion of the liner 110 to engage the liner 110. With the seal formed between the tieback string 130 and the liner 110, a fluid pathway is formed from the liner 110 to the surface 111 and the fluid pathway is isolated from the annulus 114.

FIGS. 4 and 5 show sequential steps for engaging the liner 110 with the tieback string 130. As shown in FIG. 4, the tieback string 130 has an inverted receptacle end 108 (e.g., a widened and tapered downhole end) that has an inner diameter “d” larger than an outer diameter “D” of the liner 110. The inner diameter “d” of the receptacle end 108 is large enough to allow the receptacle end 108 to receive at least a section of the upper portion 122 of the liner 110, with at least a portion of the receptacle end 108 disposed within the annulus 114. In some implementations, the tieback string 130 can be used to engage another tubular other than a liner such as a portion of a casing partially cemented, or another tubular within the wellbore.

The receptacle end 108 has a seal system 124 that is coupled to an internal surface of the receptacle end 108. As shown in FIG. 5, the seal system 124 has at least one annular seal 206 that swells inwardly to form, with the portion 122 of the liner 110 inserted within the receptacle end 108, a seal (e.g., a fluid-tight seal) with the external surface of the liner 110. With the seal formed, the tieback string 130 is fluidly coupled to the liner 110 to receive production fluid from the liner 110. The seal fluidly isolates the annulus 114 from the bore of the tieback string 130 and the bore of the liner 110.

As shown in FIGS. 4 and 5, the receptacle end 108 includes a wide, tubular portion extending from tubular body 132 that has a smaller inner and outer diameter than the tubular portion of the receptacle end 108. The seal system 124 can include three or more seals 206 distributed along the length of the receptacle end 108. The annular seals can be swellable seals that swell upon exposure to a wellbore fluid to form the seal. For example, the swellable seals can be activated (e.g., swell over time, such as over 3 to 5 days) upon coming in contact with a fluid at a predetermined temperature (e.g., between 150 and 350 degrees Fahrenheit). For example, the swellable seals can be made of an elastomer that absorbs the completion fluid and expands, reducing the inner diameter of the seals. The fluid can be flown from the surface of the wellbore through the tieback string or can be the production fluid in the wellbore 102.

Swellable sealing systems can be robust sealing systems that swell and establish proper sealing with rough surfaces. In some cases, swellable seals can seal open hole rough surfaces. The seals swell to adapt to the uneven or deformed cross-section of the liner and form a fluid-tight seal even when the liner is deformed. Additionally, the swellable seals do not require any slack off, compression, tension, slip mechanism, or thread systems to activate or form the seal. Additionally, the tieback system does not require hydraulic pressure or pumping any fluids to activate the sealing elements. Moreover, the swellable seals are robust and can establish proper sealing with rough surfaces of the pipe. In other words, the swellable seal system does not required polished surfaces for proper sealing. Such features can help minimize the number of trips needed for re-completion or for attaching a tieback string to a liner.

The seal system 124 can provide an immediate seal or a seal that is formed over time as the seals 206 swell slowly. The swellable seals 206 can be activated or reactivated after a shrinking or other deterioration of the swellable seal. The swellable seals 206 can swell in response to an activation fluid with water base fluids (e.g., treated water, fresh water, brine, water-based mud, seawater) or brine by contacting the swellable seal or seals, for example, at any point during the life of a well.

In some implementations, each swellable seal 206 is disposed within a respective internal groove “g” of the receptacle end 108. For example, the internal surface or bore of the receptacle end 108 has annular grooves “g” that house each annular seal 206. Each swellable seal 206 has a compliant external surface that swells or expands from the groove “g” toward the external surface of the liner 110 to form the seal.

The tubular body 132 of the tieback string 130 can extend from or near the surface of the wellbore 102 to the receptacle end 108. The tubular body 132 has an inner diameter “d1” substantially equal to or greater than an inner diameter “d2” of the liner 110. Thus, the tubular body 132 does not reduce the flow rate capacity of wellbore or of the liner 110.

FIG. 6 shows a flow chart of an example method 600 of installing a tieback string or liner. The method includes running a tieback string within a wellbore including a liner defining an annulus between an external surface of the liner and a wall of the wellbore. The tieback string has a receptacle end with an inner diameter larger than an outer diameter of the liner. The receptacle end has at least one annular seal that swells inwardly to form, with the portion of the liner inserted within the receptacle end, a seal with the external surface of the liner (605). The method also includes positioning the receptacle end around a portion of the liner (610). The method also includes activating the at least one annular seal to form, with the external surface of the liner, a seal. The tieback string is fluidly coupled, with the seal formed, to the liner to receive production fluid from the liner (615).

Although the following detailed description contains many specific details for purposes of illustration, it is understood that one of ordinary skill in the art will appreciate that many examples, variations and alterations to the following details are within the scope and spirit of the disclosure. Accordingly, the exemplary implementations described in the present disclosure and provided in the appended figures are set forth without any loss of generality, and without imposing limitations on the claimed implementations.

Although the present implementations have been described in detail, it should be understood that various changes, substitutions, and alterations can be made hereupon without departing from the principle and scope of the disclosure. Accordingly, the scope of the present disclosure should be determined by the following claims and their appropriate legal equivalents.

The singular forms “a”, “an” and “the” include plural referents, unless the context clearly dictates otherwise.

As used in the present disclosure and in the appended claims, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.

As used in the present disclosure, terms such as “first” and “second” are arbitrarily assigned and are merely intended to differentiate between two or more components of an apparatus. It is to be understood that the words “first” and “second” serve no other purpose and are not part of the name or description of the component, nor do they necessarily define a relative location or position of the component. Furthermore, it is to be understood that the mere use of the term “first” and “second” does not require that there be any “third” component, although that possibility is contemplated under the scope of the present disclosure.

Claims

1. A wellbore tieback system, comprising:

a liner disposed within a wellbore, the liner set on the wellbore and defining an annulus between an external surface of the liner and a wall of the wellbore;

a tieback string configured to be disposed within the wellbore, the tieback string comprising a receptacle end defining an inner diameter larger than an outer diameter of the liner such that the receptacle end is configured to be disposed within the annulus to receive a portion of the liner; and

a seal system coupled to an internal surface of the receptacle end, the seal system comprising at last one annular seal configured to swell inwardly to form, with the portion of the liner inserted within the receptacle end, a seal with the external surface of the liner, the tieback string fluidly coupled, with the seal formed, to the liner to receive production fluid from the liner.

2. The wellbore tieback system of claim 1, wherein the tieback string comprises a tubular body extending from or near a terranean surface of the wellbore to the receptacle end, the tubular body defining an inner diameter substantially equal to or greater than an inner diameter of the liner.

3. The wellbore tieback system of claim 1, wherein the at least one annular seal comprises at least one swellable seal configured to swell upon exposure to a wellbore fluid to form the seal.

4. The wellbore tieback system of claim 3, wherein the wellbore fluid is at a temperature of between 150 and 350 degrees Fahrenheit when the fluid touches the at least one swellable seal.

5. The wellbore tieback system of claim 3, wherein the at least one swellable seal comprise an elastomer configured to absorb fluid to swell over a time period of 3 to 5 days to form the seal.

6. The wellbore tieback system of claim 3, wherein the at least one swellable seal is configured to swell absent mechanical movements of the tieback string and absent fluid pumped downhole through the tieback string.

7. The wellbore tieback system of claim 1, wherein the liner is partially cemented in the wellbore, the annulus extending from an uphole inlet of the liner to a liner hanger or cement disposed between the liner and a wall of the wellbore.

8. The wellbore tieback system of claim 1, wherein the liner comprises a monobore completion liner, and the portion of the liner comprises an uphole fluid inlet formed upon cutting the liner and retrieving a second portion of the liner uphole of the portion of the liner.

9. A wellbore assembly, comprising:

a casing pipe configured to be disposed within a wellbore, the casing pipe defining, with the casing pipe set on the wellbore, an annulus between an external surface of the casing pipe and a wall of the wellbore; and

a wellbore string configured to be disposed within the wellbore, the wellbore string comprising a downhole end defining an inner diameter larger than an outer diameter of an uphole end of the casing pipe, the downhole end comprising at least one internal, annular seal configured to expand to form, with the uphole end of the casing pipe inserted within the downhole end of the wellbore string, a seal with the external surface of the casing pipe, the wellbore string fluidly coupled, with the seal formed, to the casing pipe to flow fluid between the wellbore string and the casing pipe.

10. The wellbore assembly of claim 9, wherein the wellbore string comprises a tubular body extending from or near a terranean surface of the wellbore to the downhole end, the tubular body defining an inner diameter equal to or greater than an inner diameter of the casing pipe.

11. The wellbore assembly of claim 9, wherein the at least one annular seal comprises at least one swellable seal configured to swell upon exposure to a wellbore fluid to form the seal

12. The wellbore assembly of claim 11, wherein the wellbore fluid is at a temperature of between 150 and 350 degrees Fahrenheit when the fluid touches the at least one swellable seal.

13. The wellbore assembly of claim 11, wherein the at least one swellable seal comprises an elastomer configured to absorb fluid to swell over a period of time and form a seal with an unpolished or uneven surface of the casing pipe.

14. The wellbore assembly of claim 11, wherein each swellable seal is disposed within a respective internal groove of the downhole end, each swellable seal comprising a compliant external surface configured to swell from the groove toward the external surface of the casing pipe.

15. The wellbore assembly of claim 9, wherein the casing pipe is partially cemented in the wellbore, the annulus extending from an uphole inlet of the casing pipe to a casing pipe hanger or packer or cement disposed between the casing pipe and a wall of the wellbore.

16. The wellbore assembly of claim 9, wherein the seal fluidly isolates the annulus from a bore of the wellbore string and a bore of the casing pipe.

17. The wellbore assembly of claim 9, wherein the casing pipe comprises a monobore completion casing pipe, and the portion of the casing pipe comprises an uphole fluid inlet formed upon cutting the casing pipe and retrieving a second portion of the casing pipe uphole of the portion of the casing pipe.

18. A method, comprising:

running a tieback string within a wellbore comprising a liner defining an annulus between an external surface of the liner and a wall of the wellbore, the tieback string comprising a receptacle end comprising an inner diameter larger than an outer diameter of the liner, the receptacle end comprising at least one annular seal configured to swell inwardly to form, with the portion of the liner inserted within the receptacle end, a seal with the external surface of the liner;

positioning the receptacle end around a portion of the liner; and

activating the at least one annular seal to form, with the external surface of the liner, a seal, the tieback string fluidly coupled, with the seal formed, to the liner to receive production fluid from the liner.

19. The method of claim 18, further comprising, before running the tieback string within the wellbore, cutting the liner and retrieving an upper portion of the liner to form the portion of the liner.

20. The method of claim 18, wherein activating the annular seal comprises flowing, from a terranean surface of the wellbore and through the tieback string, a fluid configured to reach the at least one annular seal at a temperature of between 150 and 350 degrees Fahrenheit.