REMOVING WELLBORE COMPLETION COMPONENTS IN A WELLBORE

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.

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.

DETAILED DESCRIPTION

FIG.1is a schematic diagram of wellbore system10that includes a downhole tool100for removing wellbore completion components in a wellbore according to the present disclosure. Generally,FIG.1illustrates a portion of one embodiment of a wellbore system10according to the present disclosure in which the downhole tool100can be run into a wellbore20and activated to remove one or more wellbore completion components that are coupled, within the wellbore20, to a wellbore tubular. In this example, the downhole tool100is connected to a downhole conveyance45during run in and run out operations in the wellbore20. The downhole conveyance45can 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 tool100can be run into the wellbore20in order to remove all or a portion of one or more completion components55a,55b, and55cthat are installed in the wellbore20and, more specifically, in or downhole of a wellbore tubular35, such as a wellbore liner or other tubular, installed in the wellbore20. As shown inFIG.1, in some aspects, the wellbore tubular35can have a particular dimension46(such as inner diameter) that is greater than a dimension56(such as inner diameter) of the one or more completion components55a,55b, and55c.

In the example ofFIG.1, completion components55a,55b, and55ccan include, for instance, cement valves, float equipment, open hole packers, and other completion equipment. For instance, completion component55acan be float equipment, while completion component55bcan be a cement valve, and completion component55ccan be an open hole packer. In some aspects, in order to drill a radius or curved portion of wellbore20and then an ensuing lateral of wellbore20(as shown in dashed line inFIG.1). Thus, in order to drill the radius or curved portion of wellbore20and then the ensuing lateral of wellbore20(as shown in dashed line inFIG.1), a different drill bit size to remove portions of the completion components55a-55cmay be required relative to a drill bit size required to drill the radius or curved portion of wellbore20and then the ensuing lateral of wellbore20. The downhole tool100, however, addresses this problem (and others) by utilizing multiple drilling and/or reaming of different and adjustable dimensions to drill through the completion components55a-55cand then drill downhole of such components (for example, to complete the radius or curved portion of wellbore20and then the ensuing lateral of wellbore20) in a single run with the downhole tool100.

As shown, the wellbore system10accesses the subterranean formation40(and other formations) and provides access to hydrocarbons located in such subterranean formation40. In an example implementation of system10, the system10may be used for a production operation in which the hydrocarbons may be produced from the subterranean formation40within a wellbore tubular (for example, through the production casing35or other production tubular).

A drilling assembly (not shown) may be used to form the wellbore20extending from the terranean surface12and through one or more geological formations in the Earth. One or more subterranean formations, such as subterranean formation40, are located under the terranean surface12. As will be explained in more detail below, one or more wellbore casings, such as a surface casing30and production casing35, may be installed in at least a portion of the wellbore20. In some embodiments, a drilling assembly used to form the wellbore20may be deployed on a body of water rather than the terranean surface12. For instance, in some embodiments, the terranean surface12may 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 surface12includes both land and water surfaces and contemplates forming and developing one or more wellbore systems10from either or both locations.

In some embodiments of the wellbore system10, the wellbore20may be cased with one or more casings. As illustrated, the wellbore20includes a conductor casing25, which extends from the terranean surface12shortly into the Earth. A portion of the wellbore20enclosed by the conductor casing25may be a large diameter borehole. Additionally, in some embodiments, the wellbore20may be offset from vertical (for example, a slant wellbore). Even further, in some embodiments, the wellbore20may 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 surface12, 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 casing25may be the surface casing30. The surface casing30may enclose a slightly smaller borehole and protect the wellbore20from intrusion of, for example, freshwater aquifers located near the terranean surface12. The wellbore20may than extend vertically downward. This portion of the wellbore20may be enclosed by the production casing35. Any of the illustrated casings, as well as other casings or tubulars that may be present in the wellbore system10, may include wellbore liners, such as an off bottom liner.

FIGS.2A-2Eare schematic illustrations showing an example implementation of a downhole tool200in a process for removing wellbore completion components in a wellbore according to the present disclosure. In some aspects, downhole tool200can be used as the downhole tool100as shown inFIG.1to remove, for example, one or more portions of completion components210-216in order to continue to drill a wellbore downhole of such components. Completion components210-216can be, for example, a cement valve210, while completion components212and214can be float devices212and214. In some aspects, each of the cement valve210and float devices212and214can be coupled to a tubular201of a wellbore, such as a liner201, or cemented within the wellbore. Completion component216, in this example, is an open hole packer216positioned between the wellbore203and the liner201.

Turning first toFIG.2A, downhole tool200is coupled to downhole conveyance45(in this example, a drill string) at a top-sub assembly202. In this example, downhole tool includes an expandable reamer assembly204that is coupled to the top-sub assembly202and a drill bit208that is coupled to the expandable reamer assembly204through a housing206. As shown, the downhole tool200can comprise all or part of a bottom hole assembly (BHA)200. The BHA is shown within the liner201and in a run-in position in which the drill bit208is just uphole of the float device212.

As shown inFIG.2A, the drill bit208can be sized (for example, as to fit through a bore218(for example, about 3.5 inches) of the open hole packer216. Thus, in some aspects, drill bit208can be a liner gauge drill bit (for example, as a 3.25 inch drill bit). Further, as shown in this figure, the expandable reamer assembly204includes one or more cutting assemblies205that can be retracted toward, or expanded away from, the housing206in order to adjust a dimension (for example, diameter) of the expandable reamer assembly204as it moved in the liner201. InFIG.2A, the expandable reamer assembly204is shown in a retracted position (for example, with a diameter of 3.25 inches) in which the cutting assemblies205are pulled in (for example, mechanically, electrically, or hydraulically) against the housing206.

Turning now toFIG.2B, this figure shows the BHA200within the wellbore203after the drill bit208has been used to remove portions of the completion components, namely portions of the cement valve210and float devices212and214, thereby leaving remaining portions211,213, and215of these components, respectively, still within the liner201. In some aspects, the remaining portions211,213, and215can be parts of the components, while in other aspects, one or more of the remaining portions211,213, and215can be cement. As shown, therefore, after the drill bit208as drilled through the completion components210,212, and214, portions of these components have been removed but not fully to the dimension (for example, diameter) of the liner201.

As shown inFIG.2B, the expandable reamer assembly204can still be in a retracted position (with the cutting sub-assemblies205retracted toward the housing206) as the drill bit208cuts through the completion components210,212, and214. In some aspects, while in the retracted position, the expandable reamer assembly204can have a dimension (for example, diameter of 3.25 inches) that is similar to or the same as the dimension of the drill bit208.

Turning now toFIG.2C, this figure shows the expandable reamer assembly204in an expanded or activated position, in which the cutting sub-assemblies205have been activated (for example, mechanically, electrically, or hydraulically) to move away from the housing206and towards the liner201. In the expanded, or activated, position, the cutting sub-assemblies205are moved such that their full dimension (for example, at 3.875 inches) is almost at or just within an inner dimension221(for example, at 4 inches) of the liner201.

Turning now toFIG.2D, this figure shows the BHA200run through the liner201with the cutting sub-assemblies205activated to remove the portions211,213, and215of the completion components210,212, and214, respectively. As described, with the cutting sub-assemblies205adjusted to the activated position of the expandable reamer assembly204, the diameter of the expandable reamer assembly204is just within the inner diameter221of the liner201.

As the BHA200runs through the liner201with the expandable reamer assembly204in the activated position, the cutting sub-assemblies205can be operated to remove the remaining ports of the completion components210,212, and214without having the trip the BHA200out of the wellbore. Once this removal process is completed as shown inFIG.2D, the expandable reamer assembly204is positioned just uphole of the open hole packer216.

Turning now toFIG.5E, this figure shows the BHA200as it moves through the open hole packer216with the expandable reamer assembly204having been adjusted back to the retracted position. In the retracted position, the diameter of the expandable reamer assembly204is less than the diameter of the bore218of the open hole packer216. As the BHA200can move freely through the bore218with the expandable reamer assembly204in the retracted position, the BHA200can further drill portions (for example, laterals and otherwise) of the wellbore203downhole of the packer216without running out of the wellbore203to, for example, change the drill bit208.