US20230279729A1

US20230279729A1 - Adjustable drill string reamer

Info

Publication number: US20230279729A1
Application number: US17/685,062
Authority: US
Inventors: Abdullah Mohammed Aldejani
Original assignee: Saudi Arabian Oil Co
Current assignee: Saudi Arabian Oil Co
Priority date: 2022-03-02
Filing date: 2022-03-02
Publication date: 2023-09-07

Abstract

A wellbore assembly includes a drill string, a drill bit, and a reamer assembly. The reamer assembly is coupled to the drill string uphole of the drill bit and includes a side cutter. The reamer assembly includes a spring that moves the side cutter from an extended position, in which the side cutter is retained by a portion of the reamer assembly against inward movement and in which the cutter defines a first drilling diameter greater than a drilling diameter of the drill bit, to a retracted position in which the portion of the reamer assembly has been broken by a shear force applied by the side cutter under a weight on bit applied against an inner component of the casing. In the retracted position, the side cutter is housed within the housing and defines a drilling diameter equal to or less than the drilling diameter of the drill bit.

Description

FIELD OF THE DISCLOSURE

This disclosure relates to wellbore operations, and more particularly to wellbore cementing operations.

BACKGROUND OF THE DISCLOSURE

Wellbore cementing is the process of introducing cement to the annulus between the outer surface of a casing and the wall of a wellbore. Casings consist of successive casing pipes or strings extending from a surface of the wellbore to a downhole end of the wellbore. Cement is used to hold the casing in place and to prevent fluid migration between subsurface formations. Each casing pipe can be cemented in successive cementing operations. Each cementing operation can include lowering and setting a casing pipe, injecting cement, using a float assembly to push the cement downhole, drilling through the float assembly, and drilling beyond the casing pipe to begin a new cementing operation. The process of cementing a wellbore can be lengthy and expensive. Methods and equipment for improving cementing operations are sought.

SUMMARY

Implementations of the present disclosure include a wellbore assembly that includes a drill string, a drill bit, and a reamer assembly. The drill string can be disposed within a wellbore that includes a casing. The drill bit is coupled to a downhole end of the drill string. The reamer assembly is coupled to the drill string and resides uphole of the drill bit. The reamer assembly includes a side cutter coupled to a wall of the drill string. The reamer assembly also includes a tension spring attached to the drill string and to the side cutter. The tension spring biases the side cutter toward a side cutter housing configured to house the side cutter such that the tension spring moves the side cutter from an extended position, in which the side cutter is retained by a portion of the reamer assembly against inward movement toward the side cutter housing and in which the side cutter defines a first drilling diameter greater than a drilling diameter of the drill bit, to a retracted position in which the portion of the reamer assembly has been broken by a shear force applied by the side cutter under a weight on bit applied against an inner component of the casing. In the retracted position, the side cutter is housed within the side cutter housing with the side cutter defining a second drilling diameter equal to or less than the drilling diameter of the drill bit.
In some implementations, the portion of the reamer assembly is a shear pin attached to the side cutter housing and disposed within an aperture of the side cutter to retain, with the side cutter in the extended position, the side cutter against inward movement toward the side cutter housing. In some implementations, the shear pin defines a length that extends perpendicular with respect to a direction of the shear force applied by the side cutter.
In some implementations, the inner component of the casing includes an inner rim of an open hole packer, the inner rim includes an inner diameter less than the first drilling diameter of the side cutter such that a cutting face of the side cutter is arranged to bear, with the side cutter in the extended position, against the rim of the open hole packer. In some implementations, the portion of the reamer assembly is configured to break under a shear force applied by the side cutter bearing against the inner rim of the open hole packer as the drill bit is pushed downhole from a surface of the wellbore.
In some implementations, the casing includes a drillable float assembly disposed uphole of the open hole packer after a cementing operation, the drillable float assembly includes a float shoe and a float collar and the drill bit is configured to cut, together with the side cutter in the extended position, the drillable float assembly to reach the open hole packer.
In some implementations, the tension spring is attached to an inner surface of the side cutter housing and pulls the side cutter toward the side cutter housing.
In some implementations, the side cutter is arranged, in the extended position and the retracted position, at a common angle with respect to a central longitudinal axis of the drill string.
In some implementations, the wellbore assembly further includes one or more additional side cutters evenly distributed along a circumference of the drill string and configured to move from an extended position to a retracted position by a respective tension spring.
In some implementations, the reamer assembly includes a latch configured to latch onto the side cutter in the retracted position to prevent the side cutter from moving from the retracted position.
Implementations of the present disclosure include a wellbore assembly that includes a drill string, a side cutter, and a retaining member. The drill string can be disposed within a wellbore. The side cutter is coupled to a wall of the drill string and disposed uphole of a drill bit of the drill string. The retaining member is coupled to the drill string and to the side cutter. The retaining member is arranged to retain the side cutter in an extended position and prevent the side cutter from moving inwardly toward a housing configured to house at least part of the side cutter. The retaining member breaks under a shear force applied by the side cutter under a weight on bit applied against a portion of the wellbore that includes a reduced diameter to allow the side cutter to move to a retracted position in which the side cutter is at least partially housed within the housing. The side cutter defines, in the extend position, a first drilling diameter greater than a drilling diameter of the drill bit. The side cutter defines, in the retracted position, a second drilling diameter less than the first drilling diameter and such that the drill string is able to drift through the portion of the wellbore that includes the reduced diameter.
In some implementations, the wellbore assembly further includes a biasing member attached to the drill string and to the side cutter. The biasing member urge the side cutter toward the housing to move the side cutter from the extended position to the retracted position. The retaining member includes a shear pin attached to the side cutter housing and disposed within an aperture of the side cutter.
In some implementations, the portion of the wellbore includes an inner rim of an open hole packer. The inner rim includes an inner diameter less than the first drilling diameter of the side cutter such that a cutting face of the side cutter is arranged to bear, with the side cutter in the extended position, against the rim of the open hole packer.
In some implementations, the retaining member is configured to break under a shear force applied by the side cutter bearing against the inner rim of the open hole packer as the drill bit is pushed downhole from a surface of the wellbore.
In some implementations, the casing includes a drillable float assembly disposed uphole of the open hole packer after a cementing operation. The drillable float assembly includes a float shoe and a float collar and the drill bit cuts, together with the side cutter in the extended position, the drillable float assembly to reach the open hole packer.
In some implementations, the wellbore assembly further includes a biasing attached to an inner surface of the side cutter housing and is configured to pull the side cutter toward the side cutter housing.
In some implementations, the side cutter is arranged, in the extended position and the retracted position, at a common angle with respect to a central longitudinal axis of the drill string.
In some implementations, the reamer assembly includes a latch configured to latch onto the side cutter in the retracted position to prevent the side cutter from moving from the retracted position.
Implementations of the present disclosure include method that includes drilling, with a drill string disposed inside a wellbore that includes a casing and an open hole packer attached to the casing, a drillable wellbore component. The drill string includes a drill bit and a reamer assembly residing uphole of the drill bit. The reamer assembly includes i) a side cutter coupled to the drill string and ii) a retaining member coupled to the drill string and to the side cutter. The retaining member is arranged to retain the side cutter in an extended position and prevent the side cutter from moving inwardly toward a housing configured to house at least part of the side cutter. The retaining member breaks under a shear force applied by the side cutter under a weight on bit applied against a portion of the wellbore that includes a reduced diameter to allow the side cutter to move to a retracted position in which the side cutter is at least partially housed within the housing. The side cutter defines, in the extend position, a first drilling diameter greater than a drilling diameter of the drill bit. The side cutter defines, in the retracted position, a second drilling diameter less than the first drilling diameter and such that the drill string is able to drift past the portion of the wellbore that includes the reduced diameter. The method also includes applying weight on the drill string to push the side cutter against an inwardly projecting shoulder of the open hole packer until the portion of the reamer assembly breaks under a shear force applied by the side cutter bearing against the inwardly projecting shoulder of the open hole packer and the side cutter moves, with the portion of the reamer assembly broken, to the retracted position. The method also includes moving, with the side cutter in the retracted portion, the drill bit and side cutters through the casing past the open hole packer to continue to drill downhole of the open hole packer.
In some implementations, the method further includes, before drilling the drillable wellbore component, cementing the casing on the wellbore, the drillable wellbore component that includes a float shoe disposed inside the casing and an open hole packer attached to the casing and disposed downhole of the float shoe.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic view, partially cross-sectional, of a wellbore during a wellbore operation according to implementations of the present disclosure.

FIGS. 2-6 are side schematic views, partially cross-sectional, of sequential steps of drilling through cement during a wellbore operation.

FIGS. 7-8 are side schematic views, partially cross-sectional, of sequential steps of retracting a reamer of a drill string during a wellbore operation.

FIG. 9 is a flow chart of a cleanout method according to implementations of the present disclosure.

DETAILED DESCRIPTION OF THE DISCLOSURE

The present disclosure relates to methods and equipment for drilling using a drilling assembly having two different drilling diameters. The drilling assembly can be used in different wellbore operations, such as drilling, cementing, cleaning, and remediating a wellbore. For example, the drilling assembly can be used for a cleanout operation or to install and cement a progressive casing in a wellbore using the same drill string. Typically, to case and cement a wellbore, multiple casing pipes are lowered and cemented in separate trips using different drill string, which requires lengthy rig time and can be costly.
Additionally, it may be common for downhole completions to vary in their inner diameters. In such cases, specific parts of completions may have to be fully drifted to the maximum drift internal diameter (ID). Thus, where a large ID completion has to be fully drifted followed by smaller ID completion, different separate runs (each with a respective drift size) may have to be performed, which results in a lengthy cleanout operation. For example, during the cleanout operation of a cemented off bottom liner (OBL) and its drillable accessories, a first drill bit is used to drill the OBL (which drills to the casing full internal diameter) and then a second, smaller drill bit (of a different drill string) is used to drifting the smaller inner diameter of the open hole packers disposed downhole of the OBL. In other words, due to the difference in diameter sizes between the drillable OBL accessories and the smaller internal surface of the open hole packers, the operation is traditionally done in two runs.
The present disclosure includes a drill string with retractable or adjustable side cutters or reamers that, when retracted, reduce the drilling diameter of the drill string. The drill string has a drill bit and one or more side cutters that reside above the drill bit. When retracted, the side cutters are retained by a tension spring inside a housing of the drill bit such that the side cutters have a drilling diameter equal to or less than the drilling diameter of the drill bit. When extended, the side cutters are held, under inward tension applied by the tension spring, by a shear pin such that the drilling diameter of the side cutters is greater than the drilling diameter of the drill bit. During a cementing operation, the drill bit is deployed with the side cutters extended to drill the cement and off bottom liner (OBL) components. The OBL components reside above an open hole packer. Once the drill bit and side cutters drill through the cement and OBL components, the drill bit stops drilling and the side cutters sit on the inner shoulder of the open hole packer. With the side cutters supported on the shoulder of the packer, weight is applied on the drill string to push the cutters against the inner shoulder of the packer until the shear pins collapse and the side cutters retract, by force of the tension spring, into the housing of the side cutters. With the side cutters retracted, the drill bit is able to drift beyond the packer to drill downhole of the packer.
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 drill string of the present disclosure minimizes the required number of cleanout runs for completions with various inner diameters. Additionally, the simple design of the reamer assembly uses few components, which has manufacturing, maintenance, and performance advantages.
FIG. 1 shows a wellbore assembly 100 disposed within a wellbore 102 (e.g., a horizontal or non-vertical wellbore) formed in a geologic formation 101. The geologic formation 101 can include a hydrocarbon reservoir 103 from which hydrocarbons can be extracted. The wellbore 102 extends from a surface 113 (e.g., a terranean surface) of the wellbore to a downhole end 116 of the wellbore 102. The wellbore 102 includes a casing 104 disposed within the wellbore 102. The casing includes drillable equipment or off bottom liner components 114 and one or more packers 112 (e.g., an open hole packer) that has an internal diameter smaller than the internal diameter of the casing 104. The drillable equipment or off bottom liner components 114 can include a float assembly 114 (e.g., a float shoe, a float collar, and a wiper plug) disposed inside the casing 104. During a cementing operation, the wiper plug pushes the cement “C” downhole and out the casing 104 to fill the annulus 107 defined between the casing 104 and the wellbore 102. Once the cement has cured, the wellbore can be completed (if the wellbore reached total depth, where the pay zone is anticipated) or further drilled to reach total depth.
The wellbore assembly 100 includes a drill string 106 and a reamer assembly 105 attached to the drill string 106. During the cementing operation of the wellbore 102, the drill string 106 is deployed to drill through the cement and continue to drill (e.g. lengthen) the wellbore 102. The drill string 106 has a drill bit 108 attached to a downhole end of the drill string 106. The reamer assembly 105 is attached to or near a downhole end of the drill string 106 and disposed uphole of the drill bit 108. In some implementations, the reamer assembly 105 can be part of the drill string 106 and the drill bit 108 can be part of the reamer assembly 105. The reamer assembly 105 drills through the cement inside the casing 104 and through the float assembly 114. The reamer assembly 105 includes one or more side cutters or reamers 110 that are retractable to reduce the drilling or drilling diameter of the drill string 106. In the case of multiple cutters 110, the side cutters 110 can be evenly distributed along a circumference of the drill string 106.
FIG. 2 shows the reamer assembly 105 positioned uphole of the float assembly 114. The side cutters 110 of the reamer assembly 105 define, when extended outwardly (e.g., extended position), a drilling diameter “D1” greater the drilling diameter “Db” (e.g., the external diameter) of the drill bit 108. The drilling diameter “D1” of the side cutters 110 can be defined as the distance between cutting tips 130 of opposite cutters 110, or as two times the distance from a central longitudinal axis “A” to a cutting tip 130 of the cutter 110 further away from the axis “A.” The drilling diameter “Db” of the drill bit 108 can be the outer diameter of drill bit 108, including its outermost cutters 132. The respective diameters “D1,” “Db” define respective drift sizes to drift or drill through different internal diameters. In other words, the diameters “D1,” “Db” are arranged to correspond with the inner diameter of the casing 104 and the inner diameter of the packer 112, respectively. For example, the drilling diameter “D1” of the side cutters 110 can be equal to or slightly less than the internal diameter of the casing 104, and the drilling diameter “Db” can be equal to or slightly less than the internal diameter of the packer 112 to drift the open hole packers 112. For example, if the casing 104 is a four-inch casing (with an internal diameter of 4.026 inches and an external diameter of 4.5 inches), the drilling diameter “D1” of the side cutters 110 can be between 3.7 and 4 inches (e.g., 3.875 inches). Similarly, if the internal diameter of the packer 112 is 3.5 inches, the drilling diameter “D1” of the drill bit 108 can be between 3.1 and 3.5 inches (e.g., 3.25 inches).
Before deploying the drill string 106, the casing 104 is ran in hole with the bottom hole assembly to the liner float accessory. Them, after flowing the cement and allowing the cement to cure, an operator can run in hole the drill string 106 with a drill bit 108 that corresponds with the downhole equipment. For example, the operator can select a drill bit 108 with a diameter that allows the drill bit 108 to pass through the open hole packers and any inflow control devices that have a diameter small than a diameter of the casing.
The casing or liner 104 includes the packer 112 which is used to center the casing 104 and set the casing on the wall of the open hole wellbore 102. In some implementations, the packer 112 can also isolate a portion (e.g., an undesirable portion or formation zone from a production zone) of the wellbore 102. The float assembly 114 is attached to and disposed inside the casing 104 uphole of the packer 112. The float assembly 114 can include a float shoe or casing shoe 144, a float collar 142, and a wiper plug 140. The float collar 432 can have a landing collar that receives the wiper plug 140 after the wiper plug 140 pushes the cement “C” out the casing 104 through the float collar 142 and the float shoe 144. For example, the wiper plug 306 is placed in the casing 104 and moved downhole by a fluid (e.g. drilling mud) to flow from the surface of the wellbore to the landing collar of the float collar 142. As the wiper plug 140 moves along the casing, the cement “C” flows from the outlet of the casing 104 to the open hole annulus on both sides of the packer 112. Once the cement “C” has cured and the wellbore is ready for the next operation, the drill string 106 is deployed to drill through the float assembly 114 and past the outlet of the casing 104.
FIG. 3 illustrates the drill bit 108 and side cutters 110 drilling through the cement “C” and float assembly 114. The drill bit 108 can rotate with respect to the drill string 106 and can alternatively or additionally be rotated by rotation of the drill string 104. The side cutters 110 rotate with the drill string 106 as the drill string 106 is rotated from the surface of the wellbore 102. The drill string 106 drills through the cement “C” and float assembly 114 until the cutting tip 130 of the side cutters 110 reach the inwardly projecting shoulder or rim 134 of the packer 112.
FIG. 4 depicts the drill string 106 at the inwardly projecting shoulder 134 of the packer 112 after drilling through the float assembly. As further described in detail below with respect to FIGS. 7-8 , to side cutters 110 are retracted to allow the drill string 106 to dirt or drill through the lower completion (e.g., the internal diameter of the packer 112) without damaging the packer 112. To retract the cutters 110, weight is applied on the drill string 106 from the surface of the wellbore 102 to push the side cutters 110 against the rim or inwardly projecting portion 134 of the packer 112. The force applied against the side cutters 110 breaks a retaining portion (e.g., a shear pin) of the reamer assembly that holds the side cutters 110 in their extended position to retract the side cutters 110.
As shown in FIG. 5 , with the retaining member broken, the side cutters 110 are retracted into a housing of the reamer assembly to reduce the drilling diameter of the side cutters 110. For example, the side cutters 110 can have, in the retracted position, a drilling diameter “D2” that is less than the drilling diameter “D1” of the side cutters 110 in their extended position. In some implementations, the drilling diameter “D2” is similar to or less than the drilling diameter “Db” of the drill bit. For example, if the drilling diameter “D1” of the drill bit 108 is around 3.25 inches, the drilling diameter “D2” of the side cutters 110 in their retracted position can be less than 3.5 inches (e.g., 3.25 inches). In some implementations, the drilling diameter “D2” of the side cutters 110 in their retracted position can be slightly larger than the drilling diameter of the drill bit, as long as the drill string 106 is able to drift through the packer 112.
FIG. 6 shows the drill string 106 after drifting through the packer 112 to continue drilling downhole of the packer 112. As the drill bit 108 passes through the interior surface of the packer 112, the drill bit 108 can be rotated (by the drill string 106 or with respect to the drill string 106) to drill through any cement that may be within the inner diameter of the packer 112. Because the drilling diameter of the retracted cutters is less than the inner diameter of the packer 112, the reamer assembly 105 passes through the interior of the packer 112 without damaging the packer 112. The drill string 106 can continue to drill past the cured cement outside of the casing 104 to increase the depth of the wellbore 102. For example, the drill string 106 can continue to drill to either deploy more casing or to reach total depth, where the pay zone is anticipated.
FIGS. 7 and 8 show sequential steps for retracting a side cutter 110 of the reamer assembly 105 to drift the reamer assembly 105 through the packer 112. The side cutter 110 can be attached to a wall 208 of the reamer assembly 105 (or the drill string 106) by way of a biasing member 202 (e.g., a tension spring). The tension spring 202 is attached to the reamer assembly 105 (or the drill string 106) and to the side cutter 110. The tension spring 202 is arranged to bias the side cutter 110 from the extended position, as shown in FIG. 7 , to the retracted position, as shown in FIG. 8 . Specifically, the tension spring 202 urges the side cutter 110 toward a side cutter housing 206 that houses all or part of the side cutter 110.
As shown in FIG. 7 , the side cutter 110 is retained in the extended position by a retaining member 204 (e.g., a shear pin) that is attached to and extends from the side cutter housing 206 and is disposed within an aperture of the side cutter 110 to retain, with the side cutter 110 in the extended position, the side cutter 110 against inward movement toward the retracted position (e.g., toward the opposite end of the spring 202). The retaining member 204 can also be a mechanical fastener, ratchet teeth, or a similar mechanism to retain the cutter 110. The retaining member 204 is designed to break under a shear force applied by the cutter 110. For example, to retract the side cutter 110, weight is applied on the drill string 106 (weight on bit) to push the side cutter 110 against the inwardly projecting shoulder 134 of the open hole packer 112 until the shear pin 204 breaks under a shear force applied by the side cutter 110 bearing against the inwardly projecting shoulder 134. As shown in FIG. 8 , with the shear pin 204 broken, the side cutter 110 is moved by the spring 202 to the retracted position. In some implementations, the side cutters 110 can be pushed against another inner surface of a transitioning point in which the inner diameter of the casing or the wellbore decreases.
As shown in FIG. 7 , a front or cutting face 210 of the side cutter 110 is arranged to bear, with the side cutter 110 in the extended position, against the rim or shoulder 134 of the open hole packer 112. The side cutter 110 defines a length or a longitudinal axis “X” that extends in a non-parallel direction with respect to the central longitudinal axis “A” of the drill string 106. In other words, the side cutter 110 can be arranged at an angle with respect to the central axis “A” of the drill string 106 such that linear movement of the cutter 110 along its longitudinal axis “X” and toward the central longitudinal axis “A” reduces the drilling diameter of the cutter 110. Thus, the side cutter 110 is arranged, in the extended and retracted positions, at a common angle with respect to a central longitudinal axis “A” of the drill string 106.
The shear pin 204 extends (e.g., along its length) perpendicular with respect to a direction of the shear force applied by the side cutter. The shear force can be parallel or substantially parallel with respect to the longitudinal axis “X” of the side cutter 110.
The spring 202 can extend along the longitudinal axis “X” of the side cutter 110. The tension spring 202 is attached to a back or inner surface of the side cutter housing 206 and pulls the side cutter toward the back surface of the housing 206. The spring 202 can be permanently attached (e.g., welded) to the side cutter 110 and to the wall 208 of the reamer assembly 105.
The wall 208 of the reamer assembly 105 can also define jetting nozzles 212 to direct fluid out the bore of the reamer assembly 105 to prevent debris from accumulating around the side cutter (e.g., within the spring 202), preventing the side cutter 110 from retracting into the housing 206. Thus, the nozzles 212 ensure continuous cleaning of the cutter 110 and cutter housing 206 from anything that may prevent the side cutter from moving to the retracted position.
Referring to FIG. 8 , the reamer assembly 105 includes a lock or latch 214 (e.g., a spring loaded latch) or ratchet teeth that engage the side cutter 110 when the side cutter is in the retracted position to prevent the side cutter 110 from moving from the retracted position toward the extended position. The lock 214 can be a one-way lock that locks the side cutter 110 in the retracted position.
To move the side cutter 110 to the extended position, an operator can disengage the latch 214, move the cutter 110 to the extended position, and insert a new shear pin to prevent the spring from pulling the cutter 110 into the retracted position. Thus, the side cutter 110 is adjustable and can shift outward and inward from and to the housing 206.
FIG. 9 shows a flow chart of an example method 900 that includes drilling, with a drill string disposed inside a wellbore that includes a casing and an open hole packer attached to the casing, a drillable wellbore component. The drill string has a drill bit and a reamer assembly residing uphole of the drill bit. The reamer assembly includes i) a side cutter coupled to the drill string and ii) a biasing member attached to the drill string and to the side cutter. The biasing member is arranged to bias the side cutter toward a side cutter housing such that the biasing member moves the side cutter from an extended position, in which the side cutter is retained by a portion of the reamer assembly against inward movement toward the housing and in which the side cutter defines a first drilling diameter greater than a drilling diameter of the drill bit, to a retracted position in which the side cutter is at least partially housed within the side cutter housing with the side cutter defining a second drilling diameter equal to or less than the drilling diameter of the drill bit. The method also includes applying weight on the drill string to push the side cutter against an inwardly projecting shoulder of the open hole packer until the portion of the reamer assembly breaks under a shear force applied by the side cutter bearing against the inwardly projecting shoulder of the open hole packer and the spring moves, with the portion of the reamer assembly broken, the side cutter to the retracted position. The method also includes moving or drifting, with the side cutter in the retracted portion, the drill bit and side cutters through the casing past the open hole packer to continue to drill downhole of the open hole packer.
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 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 assembly, comprising:

a drill string configured to be disposed within a wellbore comprising a casing;

a drill bit coupled to a downhole end of the drill string; and

a reamer assembly coupled to the drill string and residing uphole of the drill bit; the reamer assembly comprising:

a side cutter coupled to a wall of the drill string, and

a tension spring attached to the drill string and to the side cutter, the tension spring arranged to bias the side cutter toward a side cutter housing configured to house the side cutter such that the tension spring moves the side cutter from an extended position, in which the side cutter is retained by a portion of the reamer assembly against inward movement toward the side cutter housing and in which the side cutter defines a first drilling diameter greater than a drilling diameter of the drill bit, to a retracted position in which the portion of the reamer assembly has been broken, the portion of the reamer assembly configured to break under shear force applied by the side cutter bearing against an inner component of the casing that pushes, under a weight on bit applied in a downhole direction against the inner component, the side cutter inwardly until the side cutter breaks the portion of the reamer assembly to retract the side cutter, and in which the side cutter is housed within the side cutter housing with the side cutter defining a second drilling diameter less than the first drilling diameter.

2. The wellbore assembly of claim 1, wherein the portion of the reamer assembly comprises a shear pin attached to the side cutter housing and disposed within an aperture of the side cutter to retain, with the side cutter in the extended position, the side cutter against inward movement toward the side cutter housing.

3. The wellbore assembly of claim 2, wherein the shear pin defines a length that extends perpendicular with respect to a direction of the shear force applied by the side cutter.

4. The wellbore assembly of claim 1, wherein the inner component of the casing comprises an inner rim of an open hole packer, the inner rim comprising an inner diameter less than the first drilling diameter of the side cutter such that a cutting face of the side cutter is arranged to bear, with the side cutter in the extended position, against the rim of the open hole packer.

5. The wellbore assembly of claim 4, wherein the portion of the reamer assembly is configured to break under a shear force applied by the side cutter bearing against the inner rim of the open hole packer as the drill bit is pushed downhole from a surface of the wellbore.

6. The wellbore assembly of claim 4, wherein the casing comprises a drillable float assembly disposed uphole of the open hole packer after a cementing operation, the drillable float assembly comprising a float shoe and a float collar and the drill bit is configured to cut, together with the side cutter in the extended position, the drillable float assembly to reach the open hole packer.

7. The wellbore assembly of claim 1, wherein the tension spring is attached to an inner surface of the side cutter housing and pulls the side cutter toward the side cutter housing.

8. The wellbore assembly of claim 1, wherein the side cutter is arranged, in the extended position and the retracted position, at a common angle with respect to a central longitudinal axis of the drill string.

9. The wellbore assembly of claim 1, further comprising one or more additional side cutters evenly distributed along a circumference of the drill string and configured to move from an extended position to a retracted position by a respective tension spring.

10. The wellbore assembly of claim 1, wherein the reamer assembly comprises a latch configured to latch onto the side cutter in the retracted position to prevent the side cutter from moving from the retracted position.

11. A wellbore assembly, comprising:

a drill string configured to be disposed within a wellbore;

a side cutter coupled to a wall of the drill string and disposed uphole of a drill bit of the drill string; and

a retaining member coupled to the drill string and to the side cutter, the retaining member arranged to retain the side cutter in an extended position and prevent the side cutter from moving inwardly toward a housing configured to house at least part of the side cutter, the retaining member configured to break under a shear force applied by the side cutter bearing against a portion of the wellbore comprising a reduced diameter that biases, under a weight on bit applied in a downhole direction against the inner component, the side cutter inwardly until the side cutter breaks the retaining member to allow the side cutter to move to a retracted position in which the side cutter is at least partially housed within the housing, the side cutter defining, in the extend position, a first drilling diameter greater than a drilling diameter of the drill bit, and the side cutter defining, in the retracted position, a second drilling diameter less than the first drilling diameter and such that the drill string is able to drift through the portion of the wellbore comprising the reduced diameter.

12. The wellbore assembly of claim 11, further comprising a biasing member attached to the drill string and to the side cutter, the biasing member arranged to urge the side cutter toward the housing to move the side cutter from the extended position to the retracted position, and wherein the retaining member comprises a shear pin attached to the side cutter housing and disposed within an aperture of the side cutter.

13. The wellbore assembly of claim 11, wherein the portion of the wellbore comprises an inner rim of an open hole packer, the inner rim comprising an inner diameter less than the first drilling diameter of the side cutter such that a cutting face of the side cutter is arranged to bear, with the side cutter in the extended position, against the rim of the open hole packer.

14. The wellbore assembly of claim 13, wherein the retaining member is configured to break under a shear force applied by the side cutter bearing against the inner rim of the open hole packer as the drill bit is pushed downhole from a surface of the wellbore.

15. The wellbore assembly of claim 11, wherein the casing comprises a drillable float assembly disposed uphole of the open hole packer after a cementing operation, the drillable float assembly comprising a float shoe and a float collar and the drill bit is configured to cut, together with the side cutter in the extended position, the drillable float assembly to reach the open hole packer.

16. The wellbore assembly of claim 11, further comprising a biasing attached to an inner surface of the side cutter housing and configured to pull the side cutter toward the side cutter housing.

17. The wellbore assembly of claim 1, wherein the second drilling diameter of the side cutter is equal to or less than the drilling diameter of the drill bit.

18. The wellbore assembly of claim 11, wherein the reamer assembly comprises a latch configured to latch onto the side cutter in the retracted position to prevent the side cutter from moving from the retracted position.

19. A method, comprising:

drilling, with a drill string disposed inside a wellbore comprising a casing and an open hole packer attached to the casing, a drillable wellbore component, the drill string comprising a drill bit and a reamer assembly residing uphole of the drill bit, the reamer assembly comprising i) a side cutter coupled to the drill string and ii) a retaining member coupled to the drill string and to the side cutter, the retaining member arranged to retain the side cutter in an extended position and prevent the side cutter from moving inwardly toward a housing configured to house at least part of the side cutter, the retaining member configured to break under a shear force applied by the side cutter bearing against a portion of the wellbore comprising a reduced diameter that biases, under a weight on bit applied in a downhole direction against the inner component, the side cutter inwardly until the side cutter breaks the retaining member to allow the side cutter to move to a retracted position in which the side cutter is at least partially housed within the housing, the side cutter defining, in the extend position, a first drilling diameter greater than a drilling diameter of the drill bit, and the side cutter defining, in the retracted position, a second drilling diameter less than the first drilling diameter and such that the drill string is able to drift pass the portion of the wellbore comprising the reduced diameter;

applying weight on the drill string to push the side cutter against an inwardly projecting shoulder of the open hole packer until the retaining member breaks under a shear force applied by the side cutter bearing against the inwardly projecting shoulder of the open hole packer and the side cutter moves, with the retaining member broken, to the retracted position; and

moving, with the side cutter in the retracted portion, the drill bit and side cutters through the casing past the open hole packer to continue to drill downhole of the open hole packer.

20. The method of claim 19, further comprising, before drilling the drillable wellbore component, cementing the casing on the wellbore, wherein the drillable wellbore component comprises a float shoe disposed inside the casing and an open hole packer attached to the casing and disposed downhole of the float shoe.