US20230272681A1

US20230272681A1 - Removing wellbore completion components in a wellbore

Info

Publication number: US20230272681A1
Application number: US17/652,824
Authority: US
Inventors: Abdullah Mohammed Aldejani
Original assignee: Saudi Arabian Oil Co
Current assignee: Saudi Arabian Oil Co
Priority date: 2022-02-28
Filing date: 2022-02-28
Publication date: 2023-08-31

Abstract

A bottom hole assembly (BHA) includes a top sub-assembly configured to couple to a downhole conveyance to move into a wellbore that includes completion components secured in the wellbore; a drill bit configured to drill out and remove a first portion of a subset of the completion components; and an expandable reamer including a cutting assembly and configured to adjust between a retracted position in which a diameter of the cutting assembly is less than a diameter of a bore through at least one of the completion components and an activated position in which the diameter of the cutting assembly is greater than the diameter of the bore. The expandable reamer is further configured to remove a second portion of the subset of the completion components in the activated position.

Description

TECHNICAL FIELD

The present disclosure describes apparatus, systems, and methods for removing wellbore completion components in a wellbore.

BACKGROUND

In wellbore re-entry completions, it is conventional to drill a curve of a directional wellbore, as well as a lateral, in a single section. Subsequently, the lateral can be completed with a lower completion. Conventionally, after setting completion components, a cement and liner accessories may be drilled through (for example, to the casing or liner full internal diameter). However, due to a difference in diameter sizes between some completion components and other (for example, further downhole) completion components, the conventional process typical requires multiple runs with a drill bit. First, a run with a liner full gauge bit to drill out cement and one or more completion components is performed. Second, a run with a smaller drill bit to pass through other completion components is performed. Multiple runs (and switching of drill bits) can be costly in terms of time and money.

SUMMARY

In an example implementation, a method for drilling out a wellbore completion includes running a downhole tool on a downhole conveyance from a terranean surface into a wellbore that includes a plurality of completion components secured in the wellbore. The downhole tool includes a bottom hole assembly that includes a drill bit and an expandable reamer that includes a cutting assembly. The method further includes operating the drill bit to drill out and remove a first portion of a subset of the plurality of completion components; adjusting the expandable reamer from a retracted position in which a diameter of the cutting assembly is less than a diameter of a bore through at least one of the plurality of completion components to an activated position in which the diameter of the cutting assembly is greater than the diameter of the bore through the at least one of the plurality of completion components; operating the expandable reamer in the activated position to remove a second portion of the subset of the plurality of completion components; adjusting the expandable reamer from the activated position to the retracted position; and running the drill bit and the expandable reamer in the retracted position through the bore of the at least one of the plurality of completion components.
An aspect combinable with the example implementation further includes running the downhole tool from the terranean surface through the wellbore to a depth that is uphole of the plurality of completion components with the expandable reamer in the retracted position.
In another aspect combinable with any of the previous aspects, the cutting assembly includes a plurality of expandable cutters.
In another aspect combinable with any of the previous aspects, the at least one of the completion components includes an open hole packer.
In another aspect combinable with any of the previous aspects, the subset of the plurality of completion components include at least one of: a cement valve or a liner float.
In another aspect combinable with any of the previous aspects, the first portion includes cement, and the second portion includes at least a part of the cement valve or the liner float.
In another aspect combinable with any of the previous aspects, the subset of the plurality of completion components are coupled to a tubular that is installed in the wellbore.
In another aspect combinable with any of the previous aspects, the tubular includes a wellbore liner.
In another aspect combinable with any of the previous aspects, running the downhole tool on the downhole conveyance includes running the downhole tool on a tubular work string that includes drill pipe.
In another aspect combinable with any of the previous aspects, adjusting the expandable reamer from the retracted position to the activated position includes at least one of mechanically adjusting the expandable reamer from the retracted position to the activated position; electrically adjusting the expandable reamer from the retracted position to the activated position; or hydraulically adjusting the expandable reamer from the retracted position to the activated position.
In another example implementation, a downhole bottom hole assembly (BHA) includes a top sub-assembly configured to couple to a downhole conveyance to move the BHA from a terranean surface into a wellbore that includes a plurality of completion components secured in the wellbore; a drill bit coupled to the top assembly and configured to drill out and remove a first portion of a subset of the plurality of completion components; and an expandable reamer coupled to the top sub-assembly uphole of the drill bit, the expandable reamer including a cutting assembly and configured to adjust between a retracted position in which a diameter of the cutting assembly is less than a diameter of a bore through at least one of the plurality of completion components and an activated position in which the diameter of the cutting assembly is greater than the diameter of the bore through the at least one of the plurality of completion components. The expandable reamer is further configured to remove a second portion of the subset of the plurality of completion components in the activated position, and each of the drill bit and the expandable reamer in the retracted position is configured to pass through the bore of the at least one of the plurality of completion components.
In an aspect combinable with the example implementation, the downhole tool is configured to run from the terranean surface through the wellbore to a depth that is uphole of the plurality of completion components with the expandable reamer in the retracted position.
In another aspect combinable with any of the previous aspects, the cutting assembly includes a plurality of expandable cutters.
In another aspect combinable with any of the previous aspects, the at least one of the completion components includes an open hole packer.
In another aspect combinable with any of the previous aspects, the subset of the plurality of completion components include at least one of: a cement valve or a liner float.
In another aspect combinable with any of the previous aspects, the first portion includes cement, and the second portion includes at least a part of the cement valve or the liner float.
In another aspect combinable with any of the previous aspects, the subset of the plurality of completion components are configured to couple to a tubular that is installed in the wellbore.
In another aspect combinable with any of the previous aspects, the tubular includes a wellbore liner.
In another aspect combinable with any of the previous aspects, the downhole conveyance includes a tubular work string that includes drill pipe.
In another aspect combinable with any of the previous aspects, the expandable reamer is configured to adjust from the retracted position to the activated position by at least one of a mechanical adjustment of the expandable reamer from the retracted position to the activated position; an electrical adjustment of the expandable reamer from the retracted position to the activated position; or a hydraulic adjustment of the expandable reamer from the retracted position to the activated position.
Implementations of systems and methods for removing wellbore completion components in a wellbore according to the present disclosure may include one or more of the following features. For example, implementations according to the present disclosure can minimize a number of runs to drill through multiple completion components of different diameter (for example, internal diameter) to a single run in, for instance, a directional wellbore. As another example, implementations according to the present disclosure can be adjusted or configured to use a single run to drill out multiple completion components of various sizes.
The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of an example implementation of a wellbore system for removing wellbore completion components in a wellbore according to the present disclosure.

FIGS. 2A-2E are schematic illustrations showing an example implementation of a downhole tool in a process for removing wellbore completion components in a wellbore according to the present disclosure.

DETAILED DESCRIPTION

FIG. 1 is a schematic diagram of wellbore system 10 that includes a downhole tool 100 for removing wellbore completion components in a wellbore according to the present disclosure. Generally, FIG. 1 illustrates a portion of one embodiment of a wellbore system 10 according to the present disclosure in which the downhole tool 100 can be run into a wellbore 20 and activated to remove one or more wellbore completion components that are coupled, within the wellbore 20, to a wellbore tubular. In this example, the downhole tool 100 is connected to a downhole conveyance 45 during run in and run out operations in the wellbore 20. The downhole conveyance 45 can be, for example, a tubing string (for example, drill string comprised of drill pipe sections, tubing work string or coiled tubing), wireline, slickline, or other conductor.
According to the present disclosure, the downhole tool 100 can be run into the wellbore 20 in order to remove all or a portion of one or more completion components 55 a, 55 b, and 55 c that are installed in the wellbore 20 and, more specifically, in or downhole of a wellbore tubular 35, such as a wellbore liner or other tubular, installed in the wellbore 20. As shown in FIG. 1 , in some aspects, the wellbore tubular 35 can have a particular dimension 46 (such as inner diameter) that is greater than a dimension 56 (such as inner diameter) of the one or more completion components 55 a, 55 b, and 55 c.
In the example of FIG. 1 , completion components 55 a, 55 b, and 55 c can include, for instance, cement valves, float equipment, open hole packers, and other completion equipment. For instance, completion component 55 a can be float equipment, while completion component 55 b can be a cement valve, and completion component 55 c can be an open hole packer. In some aspects, in order to drill a radius or curved portion of wellbore 20 and then an ensuing lateral of wellbore 20 (as shown in dashed line in FIG. 1 ). Thus, in order to drill the radius or curved portion of wellbore 20 and then the ensuing lateral of wellbore 20 (as shown in dashed line in FIG. 1 ), a different drill bit size to remove portions of the completion components 55 a-55 c may be required relative to a drill bit size required to drill the radius or curved portion of wellbore 20 and then the ensuing lateral of wellbore 20. The downhole tool 100, however, addresses this problem (and others) by utilizing multiple drilling and/or reaming of different and adjustable dimensions to drill through the completion components 55 a-55 c and then drill downhole of such components (for example, to complete the radius or curved portion of wellbore 20 and then the ensuing lateral of wellbore 20) in a single run with the downhole tool 100.
As shown, the wellbore system 10 accesses the subterranean formation 40 (and other formations) and provides access to hydrocarbons located in such subterranean formation 40. In an example implementation of system 10, the system 10 may be used for a production operation in which the hydrocarbons may be produced from the subterranean formation 40 within a wellbore tubular (for example, through the production casing 35 or other production tubular).
A drilling assembly (not shown) may be used to form the wellbore 20 extending from the terranean surface 12 and through one or more geological formations in the Earth. One or more subterranean formations, such as subterranean formation 40, are located under the terranean surface 12. As will be explained in more detail below, one or more wellbore casings, such as a surface casing 30 and production casing 35, may be installed in at least a portion of the wellbore 20. In some embodiments, a drilling assembly used to form the wellbore 20 may be deployed on a body of water rather than the terranean surface 12. For instance, in some embodiments, the terranean surface 12 may be an ocean, gulf, sea, or any other body of water under which hydrocarbon-bearing formations may be found. In short, reference to the terranean surface 12 includes both land and water surfaces and contemplates forming and developing one or more wellbore systems 10 from either or both locations.
In some embodiments of the wellbore system 10, the wellbore 20 may be cased with one or more casings. As illustrated, the wellbore 20 includes a conductor casing 25, which extends from the terranean surface 12 shortly into the Earth. A portion of the wellbore 20 enclosed by the conductor casing 25 may be a large diameter borehole. Additionally, in some embodiments, the wellbore 20 may be offset from vertical (for example, a slant wellbore). Even further, in some embodiments, the wellbore 20 may be a stepped wellbore, such that a portion is drilled vertically downward and then curved to a substantially horizontal wellbore portion. Additional substantially vertical and horizontal wellbore portions may be added according to, for example, the type of terranean surface 12, the depth of one or more target subterranean formations, the depth of one or more productive subterranean formations, or other criteria.
Downhole of the conductor casing 25 may be the surface casing 30. The surface casing 30 may enclose a slightly smaller borehole and protect the wellbore 20 from intrusion of, for example, freshwater aquifers located near the terranean surface 12. The wellbore 20 may than extend vertically downward. This portion of the wellbore 20 may be enclosed by the production casing 35. Any of the illustrated casings, as well as other casings or tubulars that may be present in the wellbore system 10, may include wellbore liners, such as an off bottom liner.
FIGS. 2A-2E are schematic illustrations showing an example implementation of a downhole tool 200 in a process for removing wellbore completion components in a wellbore according to the present disclosure. In some aspects, downhole tool 200 can be used as the downhole tool 100 as shown in FIG. 1 to remove, for example, one or more portions of completion components 210-216 in order to continue to drill a wellbore downhole of such components. Completion components 210-216 can be, for example, a cement valve 210, while completion components 212 and 214 can be float devices 212 and 214. In some aspects, each of the cement valve 210 and float devices 212 and 214 can be coupled to a tubular 201 of a wellbore, such as a liner 201, or cemented within the wellbore. Completion component 216, in this example, is an open hole packer 216 positioned between the wellbore 203 and the liner 201.
Turning first to FIG. 2A, downhole tool 200 is coupled to downhole conveyance 45 (in this example, a drill string) at a top-sub assembly 202. In this example, downhole tool includes an expandable reamer assembly 204 that is coupled to the top-sub assembly 202 and a drill bit 208 that is coupled to the expandable reamer assembly 204 through a housing 206. As shown, the downhole tool 200 can comprise all or part of a bottom hole assembly (BHA) 200. The BHA is shown within the liner 201 and in a run-in position in which the drill bit 208 is just uphole of the float device 212.
As shown in FIG. 2A, the drill bit 208 can be sized (for example, as to fit through a bore 218 (for example, about 3.5 inches) of the open hole packer 216. Thus, in some aspects, drill bit 208 can be a liner gauge drill bit (for example, as a 3.25 inch drill bit). Further, as shown in this figure, the expandable reamer assembly 204 includes one or more cutting assemblies 205 that can be retracted toward, or expanded away from, the housing 206 in order to adjust a dimension (for example, diameter) of the expandable reamer assembly 204 as it moved in the liner 201. In FIG. 2A, the expandable reamer assembly 204 is shown in a retracted position (for example, with a diameter of 3.25 inches) in which the cutting assemblies 205 are pulled in (for example, mechanically, electrically, or hydraulically) against the housing 206.
Turning now to FIG. 2B, this figure shows the BHA 200 within the wellbore 203 after the drill bit 208 has been used to remove portions of the completion components, namely portions of the cement valve 210 and float devices 212 and 214, thereby leaving remaining portions 211, 213, and 215 of these components, respectively, still within the liner 201. In some aspects, the remaining portions 211, 213, and 215 can be parts of the components, while in other aspects, one or more of the remaining portions 211, 213, and 215 can be cement. As shown, therefore, after the drill bit 208 as drilled through the completion components 210, 212, and 214, portions of these components have been removed but not fully to the dimension (for example, diameter) of the liner 201.
As shown in FIG. 2B, the expandable reamer assembly 204 can still be in a retracted position (with the cutting sub-assemblies 205 retracted toward the housing 206) as the drill bit 208 cuts through the completion components 210, 212, and 214. In some aspects, while in the retracted position, the expandable reamer assembly 204 can have a dimension (for example, diameter of 3.25 inches) that is similar to or the same as the dimension of the drill bit 208.
Turning now to FIG. 2C, this figure shows the expandable reamer assembly 204 in an expanded or activated position, in which the cutting sub-assemblies 205 have been activated (for example, mechanically, electrically, or hydraulically) to move away from the housing 206 and towards the liner 201. In the expanded, or activated, position, the cutting sub-assemblies 205 are moved such that their full dimension (for example, at 3.875 inches) is almost at or just within an inner dimension 221 (for example, at 4 inches) of the liner 201.
Turning now to FIG. 2D, this figure shows the BHA 200 run through the liner 201 with the cutting sub-assemblies 205 activated to remove the portions 211, 213, and 215 of the completion components 210, 212, and 214, respectively. As described, with the cutting sub-assemblies 205 adjusted to the activated position of the expandable reamer assembly 204, the diameter of the expandable reamer assembly 204 is just within the inner diameter 221 of the liner 201.
As the BHA 200 runs through the liner 201 with the expandable reamer assembly 204 in the activated position, the cutting sub-assemblies 205 can be operated to remove the remaining ports of the completion components 210, 212, and 214 without having the trip the BHA 200 out of the wellbore. Once this removal process is completed as shown in FIG. 2D, the expandable reamer assembly 204 is positioned just uphole of the open hole packer 216.
Turning now to FIG. 5E, this figure shows the BHA 200 as it moves through the open hole packer 216 with the expandable reamer assembly 204 having been adjusted back to the retracted position. In the retracted position, the diameter of the expandable reamer assembly 204 is less than the diameter of the bore 218 of the open hole packer 216. As the BHA 200 can move freely through the bore 218 with the expandable reamer assembly 204 in the retracted position, the BHA 200 can further drill portions (for example, laterals and otherwise) of the wellbore 203 downhole of the packer 216 without running out of the wellbore 203 to, for example, change the drill bit 208.
A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. For example, example operations, methods, or processes described herein may include more steps or fewer steps than those described. Further, the steps in such example operations, methods, or processes may be performed in different successions than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims.

Claims

1. A method for drilling out a wellbore completion, comprising:

running a downhole tool on a downhole conveyance from a terranean surface into a wellbore that comprises a plurality of completion components secured in the wellbore, the downhole tool comprising a bottom hole assembly that comprises a drill bit and an expandable reamer that comprises a cutting assembly;

operating the drill bit to drill out and remove a first portion of a subset of the plurality of completion components coupled to a wellbore liner installed in the wellbore;

adjusting the expandable reamer from a retracted position in which a diameter of the cutting assembly is: (i) less than a diameter of a bore through at least one of the plurality of completion components, and (ii) substantially the same as a diameter of the drill bit, to an activated position in which the diameter of the cutting assembly is: (i) greater than the diameter of the bore through the at least one of the plurality of completion components, and (ii) less than a diameter of the wellbore liner;

operating the expandable reamer in the activated position to remove a second portion of the subset of the plurality of completion components;

subsequently to operating the expandable reamer in the activated position to remove the second portion of the subset of the plurality of completion components, adjusting the expandable reamer from the activated position to the retracted position; and

running the drill bit and the expandable reamer in the retracted position through the bore of the at least one of the plurality of completion components.

2. The method of claim 1, further comprising running the downhole tool from the terranean surface through the wellbore to a depth that is uphole of the plurality of completion components with the expandable reamer in the retracted position.

3. The method of claim 1, wherein the cutting assembly comprises a plurality of expandable cutters.

4. The method of claim 1, wherein the at least one of the completion components comprises an open hole packer.

5. The method of claim 4, wherein the subset of the plurality of completion components comprises a cement valve and a liner float.

6. The method of claim 5, wherein the first portion comprises cement, and the second portion comprises at least a part of the cement valve or the liner float.

7. The method of claim 1, wherein the subset of the plurality of completion components are coupled to a tubular that is installed in the wellbore.

8. The method of claim 7, wherein the tubular comprises a wellbore liner.

9. The method of claim 1, wherein running the downhole tool on the downhole conveyance comprises running the downhole tool on a tubular work string that comprises drill pipe.

10. The method of claim 1, wherein adjusting the expandable reamer from the retracted position to the activated position comprises at least one of:

mechanically adjusting the expandable reamer from the retracted position to the activated position;

electrically adjusting the expandable reamer from the retracted position to the activated position; or

hydraulically adjusting the expandable reamer from the retracted position to the activated position.

11. A downhole bottom hole assembly (BHA), comprising:

a top sub-assembly configured to couple to a downhole conveyance to move the BHA from a terranean surface into a wellbore that comprises a plurality of completion components coupled to a wellbore liner installed in the wellbore;

a drill bit coupled to the top assembly and configured to drill out and remove a first portion of a subset of the plurality of completion components; and

an expandable reamer coupled to the top sub-assembly uphole of the drill bit, the expandable reamer comprising a cutting assembly and configured to adjust between a retracted position in which a diameter of the cutting assembly is: (i) less than a diameter of a bore through at least one of the plurality of completion components, and (ii) substantially the same as a diameter of the drill bit, and an activated position in which the diameter of the cutting assembly is: (i) greater than the diameter of the bore through the at least one of the plurality of completion components, and (ii) less than a diameter of the wellbore liner,

wherein the expandable reamer is further configured to remove a second portion of the subset of the plurality of completion components in the activated position and return to the retracted position, each of the drill bit and the expandable reamer in the retracted position configured to pass through the bore of the at least one of the plurality of completion components.

12. The downhole BHA of claim 11, wherein the downhole tool is configured to run from the terranean surface through the wellbore to a depth that is uphole of the plurality of completion components with the expandable reamer in the retracted position.

13. The downhole BHA of claim 11, wherein the cutting assembly comprises a plurality of expandable cutters.

14. The downhole BHA of claim 11, wherein the at least one of the completion components comprises an open hole packer.

15. The downhole BHA of claim 14, wherein the subset of the plurality of completion components comprises a cement valve and a liner float.

16. The downhole BHA of claim 15, wherein the first portion comprises cement, and the second portion comprises at least a part of the cement valve or the liner float.

17. The downhole BHA of claim 11, wherein the subset of the plurality of completion components are configured to couple to a tubular that is installed in the wellbore.

18. The downhole BHA of claim 17, wherein the tubular comprises a wellbore liner.

19. The downhole BHA of claim 11, wherein the downhole conveyance comprises a tubular work string that comprises drill pipe.

20. The downhole BHA of claim 11, wherein the expandable reamer is configured to adjust from the retracted position to the activated position by at least one of:

a mechanical adjustment of the expandable reamer from the retracted position to the activated position;

an electrical adjustment of the expandable reamer from the retracted position to the activated position; or

a hydraulic adjustment of the expandable reamer from the retracted position to the activated position.