US20180274316A1

US20180274316A1 - System and method for intelligent latch securement

Info

Publication number: US20180274316A1
Application number: US15/571,166
Authority: US
Inventors: William Wallace Dancer
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2016-12-27
Filing date: 2016-12-27
Publication date: 2018-09-27
Also published as: WO2018125036A1; AU2016433757A1; GB201903532D0; NO20190643A1; GB2568198A

Abstract

The disclosed embodiments include an assembly for anchoring a tool at a subsurface location in a wellbore. The assembly includes a latch coupling having a latch pocket on an internal surface of the latch coupling. Additionally, the assembly includes an outwardly biased latch having a key latch that in operation interacts with the latch pocket of the latch coupling to secure the outwardly biased latch within the latch coupling. Further, the assembly includes a first sensor disposed in the latch pocket, and a second sensor disposed in the key latch. The second sensor detects the first sensor when the outwardly biased latch is secured within the latch coupling. Furthermore, the assembly includes a communication sub communicatively coupled to the second sensor that transmits an indication to a surface of the well that the outwardly biased latch is secured within the latch coupling.

Description

BACKGROUND

The present disclosure relates generally to downhole latch assemblies in a well, and more specifically to intelligent latch verification of the downhole latch assemblies in the well.
While drilling a well, it may be beneficial at certain times to anchor and orient a tool at a downhole location within the well. For example, when preparing to drill a lateral bore off of a main wellbore, it may be desirable to anchor a whipstock within the main wellbore to direct a drill in a lateral direction within the well. Generally, to anchor the whipstock or another downhole tool, a downhole latch assembly interacts with a latch coupling to provide an anchor that prevents further movement of a tool in a downhole direction.
However, determining whether the downhole latch assembly is secured within the latch coupling is only made at a surface of the well by monitoring effects of forces applied on a drill string that transports the downhole latch assembly to the coupling. For example, verification that the downhole latch assembly is properly secured in the latch coupling may be accomplished by setting string weight to a level that should enable a drill string to travel downhole and detecting that the drill string is not moving. Similarly, verification that the downhole latch assembly is properly secured in the latch coupling may be accomplished by applying torque to a drill string that should turn the drill string and detecting that the drill string is not turning.

BRIEF DESCRIPTION OF THE DRAWINGS

Illustrative embodiments of the present disclosure are described in detail below with reference to the attached drawing figures, which are incorporated by reference herein, and wherein:

FIG. 1 is a cross section illustration of a downhole assembly of a well;

FIG. 1A is a detailed view of a portion of the cross section illustration of the downhole assembly of FIG. 1;

FIG. 2 a perspective view of a latch of the downhole assembly of FIG. 1;

FIG. 3 is a cross section illustration of a latch coupling that interacts with the latch of FIG. 2;

FIG. 4 is a flow chart of a method for verifying that latches of the downhole assembly of FIG. 1 are secured within the latch coupling of FIG. 3:

FIG. 5 is a schematic view of a directional drilling system prior to drilling of a lateral well; and

FIG. 6 is a schematic view of a directional drilling system after drilling of a lateral well.

The illustrated figures are only exemplary and are not intended to assert or imply any limitation with regard to the environment, architecture, design, or process in which different embodiments may be implemented.

DETAILED DESCRIPTION

In the following detailed description of the illustrative embodiments, reference is made to the accompanying drawings that form a part hereof. These embodiments are described in sufficient detail to enable those skilled in the art to practice the disclosed subject matter, and it is understood that other embodiments may be utilized and that logical structural, mechanical, electrical, and chemical changes may be made without departing from the spirit or scope of the disclosure. To avoid detail not necessary to enable those skilled in the art to practice the embodiments described herein, the description may omit certain information known to those skilled in the art. The following detailed description is, therefore, not to be taken in a limiting sense, and the scope of the illustrative embodiments is defined only by the appended claims.
As used herein, the singular forms “a”, “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “comprise” and/or “comprising,” when used in this specification and/or the claims, specify the presence of stated features, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, steps, operations, elements, components, and/or groups thereof. In addition, the steps and components described in the above embodiments and figures are merely illustrative and do not imply that any particular step or component is a requirement of a claimed embodiment.
Unless otherwise specified, any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to”. Unless otherwise indicated, as used throughout this document, “or” does not require mutual exclusivity.
The present disclosure relates to a latch assembly within a wellbore that anchors downhole tools at a downhole location. More particularly, the present disclosure relates to intelligent verification that the latch assembly is secured within a latch coupling at the downhole location. The presently disclosed embodiments may be used in horizontal, vertical, deviated, or otherwise nonlinear wellbores in any type of subterranean formation. Embodiments may be implemented to anchor downhole tools within the wellbore, such as a whipstock or other tools used to commence lateral drilling off of a main wellbore.
Referring to FIGS. 1 and 1A, a cross section illustration of a downhole assembly 100 of a well. The downhole assembly 100 (e.g., a latch assembly) includes an upper portion 102 of a tubular latch housing and a lower portion 104 of the tubular latch housing. In the illustrated embodiment, the upper portion 102 and the lower portion 104 may be substantially similar in size and shape with a difference in vertical orientation. For example, the lower portion 104 may be the same component as the upper portion 102, but the lower portion 104 may be upside down in relation to the upper portion 102.
A set of latches 106 are positioned between the upper portion 102 and the lower portion 104 of the tubular latch housing. While the cross section illustration of FIG. 1 illustrates a cross-section of latches 106A and 106B, an interior portion of latch 106C is also depicted. Further, in an embodiment, the configuration of the downhole assembly 100 includes a fourth latch 106D (not shown), that extends in a direction toward the removed portion of the downhole assembly 100. The latches 106 are radially outward biased and, in operation, interact with a latch coupling 108.
To bias the latches 106 in a radially outward manner, springs 110 and 112 may be positioned uphole and downhole from the latches 106, respectively. For example, each of the latches 106A-106D include a corresponding set of springs 110A-110D and 112A-112D. The springs 110A-110D provide a biasing force on uphole wedges 114A-114D, as shown in FIG. 1A, and the springs 112A-112D provide a biasing force on downhole wedges 116A-116D. In turn, the uphole wedges 114A-114D act on uphole actuating faces 118A-118D of the latches 106A-106D to provide a force on the latches 106A-106D that biases the latches 106A-106D in a radially outward manner. Similarly, the downhole wedges 116A-116D act on downhole actuating faces 120A-120D of the latches 106A-106D to provide additional force on the latches 106A-106D that biases the latches 106A-106D in a radially outward manner. While the present disclosure describes biasing the latches 106 in a radially outward manner using the springs 110 and 112, various other devices capable of producing the biasing force may also be implemented to urge the latches 106 in a radially outward direction.
A bull nose nut 122, as depicted in FIG. 1, is disposed on a downhole portion of the downhole assembly 100. The bull nose nut 122 may be adjusted to accommodate different configurations of the springs 110 and 112. Further, the uphole portion 102 and the downhole portion 104 of the tubular latch housing may function as spacers for the bull nose nut 122. For example, the uphole portion 102 and the downhole portion 104 may have an axial length that provides a desired amount of compression of the springs 110 and 112 to provide a desired biasing force on the latches 106. In this manner, the spacer function of the uphole portion 102 and the downhole portion 104 enables the bull noes nut 122 to securely fasten to the downhole assembly 100 while maintaining the springs 110 and 112 at a desired level of compression.
The downhole assembly 100 is dimensioned to fit tightly against an internal surface of a casing of a wellbore while the downhole assembly 100 is transported to the latch coupling 108. Further, the latch coupling 108 may be installed within the well between joints of the casing of a main wellbore when the casing is run into the main wellbore. As the downhole assembly 100 moves toward the latch coupling 108, the latches 106 may be compressed inward toward a downhole latch tubing 124 and an uphole latch tubing 126. For example, the latches 106 maintain firm sliding engagement with the internal surface of the casing during transport, and the firm sliding engagement prevents movement of the latches 106 in a radially outward direction. Additionally, an amount of force urging the latches 106 radially outward is determined by selecting an appropriate number and strength of elements in the springs 110 and 112 and by selecting appropriate inclined surfaces of the wedges 118 and 120.
The radially outward biasing of the latches 106 enables the latches 106 to engage with the latch coupling 108 when the latches 106 are properly oriented. For example, the latch coupling 108 includes a series of grooves 128 positioned along the latch coupling 108, as shown in FIG. 1A. The grooves 128 extend around an inner circumference of the latch coupling 108, and the grooves may allow the latches 106 to extend slightly in a radially outward direction when the latches 106 are within the latch coupling 108. Further, when the latches 106 extend outward into the grooves 128, an additional weight of approximately 20,000 pounds may be applied on a drill string 129 to move the downhole assembly 100 uphole or downhole. The weight to move the downhole assembly 100 uphole or downhole when the latches 106 are disposed within the grooves 128 may also be less than or greater than 20,000 pounds depending on the depth of the grooves 128 and the biasing force of the springs 110 and 112 provided to the latches 106. In an embodiment, the change in weight used to move the downhole assembly 100 provides an indication to an operator at the surface that the latches 106 are within the latch coupling 108 but not yet secured within the latch coupling 108. An operator may use a predetermined change in weight threshold to determine that the latches 106 are within the latch coupling 108 but not yet secured within the latch coupling 108.
The latch coupling 108 also includes key pockets 130A-130D and latch pockets 132. The key pockets 130A-130D are shaped to receive key bits 131A-131D, and the latch pockets 132 are shaped to receive square shoulder key latches 133A-133D and 135A-135D and key latches 137A-137D. The key pockets 130A-130D may be positioned about the interior of the latch coupling 108 in a configuration that allows the latches 106A-106D to be secured within the latch coupling 108 only when the downhole assembly 100 is at a single depth and a single orientation. For example, the key bits 131A-131D may be provided at different positions along the latches 106A-106D to correspond with the differing positions of the key pockets 130A-130D of the latch coupling 108.
The latch pockets 132, similar to the grooves 128, may extend around the inner circumference of the latch coupling 108. Accordingly, the square shoulder key latches 133A-133D and 135A-135D and the key latches 137A-137D may be provided at the same position on each of the latches 106A-106D. In an embodiment, the square shoulder key latches 133A-133D and 135A-135D provide the primary anchoring force for the downhole assembly 100 to anchor a downhole tool.
As illustrated, the latch 106B also includes a latch sensor 134. The latch sensor 134 may interact with a coupling sensor 136, which is disposed within the latch pocket 132 of the latch coupling 108, to provide an indication that the latches 106 are secured within the latch coupling 108. Because the downhole assembly 100 can only be secured within the latch coupling 108 in a single orientation, the coupling sensor 136 may be in a position within the latch pocket 132 that aligns with a location of the latch sensor 134 when the latches 106 are secured within the latch coupling 108. In this manner, the latch sensor 134 senses that the coupling sensor 136 is in sufficient proximity to indicate that the latches 106 are secured within the latch coupling 108.
The latch sensor 134 may be a magnetic sensor, an electric contact, or any other sensor capable of verifying that the latches 106 are secured within the latch coupling 108. Additionally, the coupling sensor 136 may be a strong magnet, a current path that completes an electric circuit of the latch sensor 134, or any other sensor or device capable of providing a signal to the latch sensor 134 indicating that the latches 106 are secured within the latch coupling 108. Alternatively, in an embodiment, the coupling sensor 136 may be a magnetic sensor, an electric contact, or any other sensor capable of verifying that the latches 106 are secured within the latch coupling 108. In the embodiment, the latch sensor 134 may be a strong magnet, a current path that completes an electric circuit of the coupling sensor 136, or any other sensor or device capable of providing a signal to the coupling sensor 136 indicating that the latches 106 are secured within the latch coupling 108.
A communication sub 138, which is communicatively coupled to the latch sensor 134 as depicted in FIG. 1, the coupling sensor 136, or both, provides a signal to a surface of the well that indicates that the latch sensor 134 and the coupling sensor 136 are in sufficient proximity to indicate that the latches 106 are secured within the latch coupling 108. For example, the communication sub 138 may communicate to the surface with conventional downhole tool to surface telemetry. The communication sub 138 may include a wall mounted pulser, or wall mounted electronics that provide a real-time signal to the surface. Data indicative of a secure connection between the latches 106 and the latch coupling 108 may also be stored in a memory of the communication sub 138 at a downhole location, and the data may be analyzed at the surface to ensure proper latching between the latches 106 and the latch coupling 108.
Communication between the latch sensor 134, the coupling sensor 136, or both and the communication sub 138 may be accomplished using fiber optic communication or coaxial cable communication. Additionally, communication between the communication sub 138 and the surface may be accomplished using acoustic telemetry, electro-magnetic telemetry, mud pulse telemetry, or any other communication method to communicate an indication that the latches 106 are secured within the latch coupling 108. By way of example, the communication to the surface may result in a visual signal (e.g., a light turning on or an indication on a display) that indicates to an operator that the latches 106 are secured within the latch coupling 108.
FIG. 2 is a perspective view of one of the latches 106 of the downhole assembly 100. As discussed above with reference to FIG. 1, the latch 106 includes an uphole actuating face 118 and a downhole actuating face 120 upon which wedges 114 and 116, respectively, apply the radially outward biasing force on the latch 106. The latch 106 includes key bits 131, which are received in the key pockets 130 of the coupling latch 108. To align the downhole assembly 100 in a proper orientation, the key bits 131 may be oriented at different locations along the latch 106. For example, referring back to FIG. 1A, the key bits 131A of the latch 106A are positioned further uphole than the key bits 131B of the latch 106B. The key pockets 130 of the latch coupling 108 may align with the key bits 131 in such a manner that there is only one orientation for the latches 106 to fit within the latch coupling 108.
The latch 106 also includes the square shoulder key latches 133 and 135 and the key latch 137. The square shoulder key latches 133 and 135 and the key latch 137 fit within the corresponding latch pockets 132 of the latch coupling 108. Further, the square shoulder key latches 133 and 135 provide the securing force of the latch 106 within the latch coupling 108. For example, when the square shoulder key latches 133 and 135 interact with corresponding latch pockets 132, the downhole assembly 100 is unable to continue in a downhole direction. Additionally, the key latch 137 assists in guiding the latch 106 into the latch coupling 108. The key latch 137 functions as a wear surface and helps centralize the latch 106 as the latches 106A-106D are rotated in and out of the latch coupling 108.
Because the key bits 131 allow only a single orientation of the latches 106 within the latch coupling 108, only a single square shoulder key latch 133 includes the latch sensor 134. Additionally, within the latch pocket 132, the coupling sensor 136 is disposed in a location that mates with the square shoulder key latch 133 that includes the latch sensor 134. Accordingly, to provide an indication that the latch 106 is secured within the latch coupling 108, only a single latch sensor 134 and a single coupling sensor 136 is used.
In another embodiment, the key bits 131 may be located in the same position on each of the latches 106A-106D. In such an embodiment, any of the latches 106 can mate with any of the key pockets 130 of the latch coupling 108. That is, the downhole assembly 100 may be oriented in as many directions as there are latches 106. Accordingly, the latch coupling 108 may include as many coupling sensors 136 as latches 106 in the downhole assembly 100. In this embodiment, the coupling sensors 136 are located at each location that the single latch sensor 134 may be located when secured within the latch coupling 108.
In another embodiment, each of the latches 106 may include the latch sensor 134 while a single coupling sensor 136 is located at a position where one of the latches 106 will be secured to the latch coupling 108. In this embodiment, one of the latch sensors 134 will always be at a location of the single coupling sensor 136. To provide additional redundancy, the latch coupling 108 may include the same number of coupling sensors 136 as the number of latches 106 and latch sensors 134. In such an embodiment, the multiple latch sensors 134 and coupling sensors 136 may provide the additional redundancy to ensure that at least one set of the sensors 134 and 136 are functioning properly.
While the latches 106 are secured in the latch coupling 108, the movement of the downhole assembly 100 in a downhole direction may be prevented. However, angled surfaces 202 of the key bits 131, square shoulder key latches 133 and 135, and the key latch 137 enable the downhole assembly 100 to be moved uphole even after the latches 106 are secured within the latch coupling 108. For example, while approximately 20,000 pounds applied to the drill string 129 overcome the force provided by the grooves 128, a weight of approximately 40,000 pounds applied to the drill string 129 in an uphole direction may overcome the force provided by the key pockets 130 and the latch pockets 132.
Referring to FIG. 3, a cross section illustration of the latch coupling 108 is depicted. As discussed above, the latch coupling 108 includes the grooves 128 positioned along a length of the latch coupling 108. The grooves 128 extend around an entire inner circumference of the latch coupling 108. Additionally, the grooves 128 provide recesses for the latches 106 to partially extend in a radially outward direction. By allowing the latches 106 to partially extend radially outward, additional force on the drill string 129 is required to move the downhole assembly 100 uphole or downhole. For example, the partial extension of the latches 106 may require an additional 20,000 pounds of weight applied to the drill string 129 to move the drill string 129 uphole or downhole.
Also illustrated are the key pockets 130A-130C. While only the three key pockets 130A-130C are shown in FIG. 3, the illustrated embodiment includes fourth key pockets 130D (not shown) on a direct opposite side of the latch coupling 108 from the key pockets 130C. The key pockets 130D in the illustrated embodiment may be positioned in a different vertical location from the position of the illustrated key pockets 130A-130C. The depicted key pockets 130A-130C receive the key bits 131A-131C from the latches 106A-106C. In this manner, the key pockets 130A-130C enable the latches 106A-106C to be secured in a specific orientation within the latch coupling 108.
To help secure the latches 106A-106C within the latch coupling 108, latch pockets 132 are also depicted. The latch pockets 132 extend around the entire circumference of the latch coupling 108 similar to the grooves 128, but the latch pockets 132 extend deeper into the latch coupling 108. Further, the latch pockets 132 may include squared portions 302 and 304 that interact with the square shoulder key latches 133 and 135. The squared portions 302 and 304 provide surfaces that enable the downhole assembly 100 to anchor a downhole tool in a downhole location.
The coupling sensor 136 is also illustrated in position within the latch pocket 132 directly uphole from the key pockets 130B in which the key bits 131B are positioned while the latch 106B is secured within the latch coupling 108. As discussed above, when the latch sensor 134, which is positioned in the square shoulder key latch 133B of the latch 106B, is in sufficient proximity to the coupling sensor 136, a signal indicating that the latch 106 is secured within the latch coupling 108 is transmitted to the surface.
Additionally, as discussed above with reference to FIG. 2, the latch coupling 108 may include more of the coupling sensors 136 positioned around the latch pocket 132. For example, the coupling sensors 136 may be positioned above each of the sets of key pockets 130A-130D to correspond with a latching sensor 134 that may be positioned in any of the latches 106A-106D. Furthermore, while FIGS. 1-3 illustrate the downhole assembly 100 including four latches 106, it may be appreciated that more or fewer latches 106 are also contemplated. For example, the downhole assembly 100, in an embodiment, may include a single latch 106 that interacts with the latch coupling 108. Alternatively, the downhole assembly, in another embodiment, may include, two, three, five, or more latches 106 that interact with corresponding number of key pockets 130 of the latch coupling 108. Additionally, in some embodiments it is contemplated that the latch coupling 108 may include a greater number of sets of key pockets 130 than a number of latches 106 that are included in the downhole assembly 100.
To help illustrate how the latches 106 are secured within the latch coupling 108, FIG. 4 is a flow chart of a method 400 for verifying that the latches 106 are secured within the latch coupling 108. Initially, at block 402, downhole force is applied on the drill string 129. Applying the force on the drill string 129 may include removing force that prevents the drill string 129 from travelling downhole in the well. For example, the force provided by a weight of the drill string 129 by itself may be sufficient for the drill string to travel downhole.
Subsequently, at block 404, a user may receive an indication that the weight on the drill string 129 has been reduced by a significant amount. By way of example, the user may receive an indication that a weight on the drill string has been reduced by approximately 20,000 pounds. The reduction in the weight on the drill string may be a result of the latches 106 coming into contact with the grooves 128 of the latch coupling 108. Based on the biasing force provided by the springs 110 and 112 and a depth of the grooves 128, the amount of the reduction in the weight on the drill string 129 may be increased or decreased. For example, a greater biasing force and deeper grooves 128 may increase the amount of the reduction in the weight on the drill string 129, while a decreased biasing force and shallower grooves 128 may decrease the amount of the reduction in the weight on the drill string 129. Accordingly, the indication that the weight on the drill string 129 has been reduced may include a reduction in the weight on the drill string 129 by between 1000 pounds and 50,000 pounds while still indicating that the latches 106 are in contact with the grooves 128.
After the reduction in the weight on the drill string 129 is indicated to the user, the drill string 129 may begin rotating at block 406. Because the latches 106 are within the grooves 128, rotating the drill string 129 orients the key bits 131 of the latches 106 in the proper orientation for reception in the key pockets 130. Further, as the latch pockets 132 extend around the entire circumference of the latch coupling 108, once the key bits 131 are properly aligned, the key latches 133, 135, and 137 are also received in the latch pockets 132 to secure the latches 106 within the latch coupling 108.
As the latches 106 are secured within the latch coupling 108, an indication is received by the user that the latch sensor 134 has detected the coupling sensor 136. In an embodiment, the latch sensor 134 is only sensitive enough to detect the coupling sensor 136 while in very close proximity. For example, in some embodiments, the latch sensor 134 may only detect the coupling sensor 136 when the latch sensor 134 is in physical contact with the coupling sensor 136. In other embodiments, the latch sensor 134 may only detect the coupling sensor 136 when the latch sensor 134 is within an inch or less of the coupling sensor 136. However, the sensitivity of the latch sensor 134 may be at any level that detects the coupling sensor 136 only when the latch 106 is secured within the latch coupling 108. Upon receiving the indication that the latch sensor 134 has detected the coupling sensor 136, the user obtains verification that the downhole assembly 100 is secured at the latch coupling 108 and prepared to anchor a downhole tool.
FIG. 5 is a schematic view of a directional drilling system 500 prior to drilling of a lateral well. The directional drilling system 500 includes a derrick 502 that is buttressed by a derrick floor 504. The derrick floor 504 supports a rotary table 506 that is driven during drilling at a desired rotational speed, for example, via a chain drive system through operation of a prime mover (not shown). The rotary table 506, in turn, provides the rotational force to the drill string 129. The drill string 129, as illustrated, is coupled to the communication sub 138 and the downhole assembly 100. Also depicted is the latch coupling 108, which is placed downhole between joints of casing 508 when a primary wellbore 510 is cased.
The downhole assembly 100 is secured to the latch coupling 108 within the primary wellbore 510 via the latches 106 using the method described above with reference to FIG. 4. For example, the derrick 502 lowers the drill string 129 into the primary wellbore 510. Upon interacting with the latch coupling 108, and receiving an indication that weight on the drill string 129 is reduced, the rotary table 506 begins rotating to align the latches 106 of the downhole assembly 100 in an appropriate orientation with the latch coupling 108. When the latches 106 are secured within the latch coupling 108, the latch sensor 134 detects the coupling sensor 136. The latch sensor 134 or the coupling sensor 136 then provides a signal, via the communication sub 138, to a user interface 512 at a surface 514 of the directional drilling system 500 that indicates that the latches 106 are secured within the latch coupling 108. Once the latches 106 are secured within the latch coupling 108, the downhole assembly 100 is used to secure downhole tools within the wellbore 510. For example, the downhole tools may include a latch cleaning tool, a milling machine, a whipstock, a completion deflector, a dual bore completion deflector, or any other downhole tool that may benefit from being anchored at a downhole location.
FIG. 6 is a schematic view of a directional drilling system 600 after drilling of a lateral well. Once the latch assembly 100 is verifiably secured within the latch coupling 108, a whipstock 602 may be lowered into the primary wellbore 510 and secured to the latch assembly 100. The latch assembly 100 anchors the whipstock 602 in a downhole position such that a drill bit 604 at the end of the drill string 129 is able to begin drilling a lateral wellbore 606. While FIG. 6 illustrates the whipstock 602 as the downhole tool anchored by the downhole assembly 100, it may be appreciated that other downhole tools are also contemplated as being anchored by the downhole assembly 100.
The above-disclosed embodiments have been presented for purposes of illustration and to enable one of ordinary skill in the art to practice the disclosure, but the disclosure is not intended to be exhaustive or limited to the forms disclosed. Many insubstantial modifications and variations will be apparent to those of ordinary skill in the art without departing from the scope and spirit of the disclosure. For instance, although the flowcharts depict a serial process, some of the steps/processes may be performed in parallel or out of sequence, or combined into a single step/process. The scope of the claims is intended to broadly cover the disclosed embodiments and any such modification. Further, the following clauses represent additional embodiments of the disclosure and should be considered within the scope of the disclosure:
Clause 1, an assembly for anchoring a tool at a subsurface location in a wellbore, comprising: a latch coupling comprising at least one latch pocket on an internal surface of the latch coupling; at least one outwardly biased latch comprising at least one key latch that in operation interacts with the at least one latch pocket of the latch coupling to secure the outwardly biased latch within the latch coupling; a first sensor disposed in the at least one latch pocket; a second sensor disposed in the at least one key latch, wherein the second sensor detects the first sensor when the at least one outwardly biased latch is secured within the latch coupling; and a communication sub communicatively coupled to the second sensor and configured to transmit an indication to a surface of the well that the at least one outwardly biased latch is secured within the latch coupling.
Clause 2, the assembly of clause 1, wherein the assembly comprises a plurality of the outwardly biased latches, and each of the outwardly biased latches comprises two key bits positioned at different distances from an uphole end of the outwardly biased latch than the key bits of the other outwardly biased latches.
Clause 3, the assembly of clause 2, wherein the latch coupling comprises key pockets that correspond to each of the key bits of the outwardly biased latches such that the outwardly biased latches are securable in the latch coupling in a single orientation.
Clause 4, the assembly of at least one of clauses 1-3, wherein the communication sub transmits the indication that the at least one outwardly biased latch is secured within the latch coupling using acoustic telemetry, electro-magnetic telemetry, mud pulse telemetry, or any combination thereof.
Clause 5, the assembly of at least one of clauses 1-4, wherein the assembly is configured to anchor a whipstock at an uphole location such that a lateral wellbore is drillable from the wellbore.
Clause 6, the assembly of at least one of clauses 1-5, wherein the latch coupling comprises a set of grooves extending around an inner circumference of the latch coupling that provides a mechanical indication that the at least one latch is within the latch coupling but not secured.
Clause 7, the assembly of clause 6, wherein the mechanical indication comprises a reduction in weight experienced by the drill string that exceeds a predetermined threshold.
Clause 8, the assembly of at least one of clauses 1-7, wherein the at least one key latch comprises a square shoulder that engages with the latch pocket of the latch coupling to prevent further downhole movement of the at least one latch.
Clause 9, the assembly of at least one of clauses 1-8, wherein the second sensor comprises a magnetic sensor or an electric contact.
Clause 10, the assembly of at least one of clauses 1-9, wherein the first sensor comprises a magnet or a current path.
Clause 11, an assembly, comprising: a latch assembly comprising: at least one outwardly biased latch comprising at least one key latch that in operation interacts with at least one latch pocket of a latch coupling located within the well to secure the latch assembly within the latch coupling; and a biasing device configured to provide a radially outward biasing force on the at least one outwardly biased latch; a first sensor disposed in the at least one key latch of the at least one outwardly biased latch, wherein the first sensor is configured to detect when the at least one key latch is secured within the at least one latch pocket; and a communication sub communicatively coupled to the first sensor and configured to transmit an indication to a surface of the well that the at least one outwardly biased latch is secured within the latch coupling.
Clause 12, the assembly of clause 11, wherein the assembly comprises a downhole tool positioned uphole from the latch assembly, and wherein the latch assembly, when secured within the latch coupling, provides a downhole anchor for the downhole tool.
Clause 13, the assembly of clause 11 or 12, wherein the latch assembly is securable to the latch coupling in only a single orientation.
Clause 14, the assembly of clause 11 or 12, wherein the latch assembly is securable to the latch coupling in more than one orientation.
Clause 15, the assembly of at least one of clauses 11-14, wherein the at least one key latch comprises a squared shoulder that is configured to engage with the latch pocket of the latch coupling to prevent further downhole movement of the at least one latch.
Clause 16, the assembly of at least one of clauses 11-15, wherein the at least one outwardly biased latch comprises two key latches, and each of the two key latches comprises a squared shoulder configured to support the latch assembly when the at least one outwardly biased latch is secured within the latch coupling.
Clause 17, a method of securing a latch assembly within a wellbore, comprising: applying a downhole force on a drill string; detecting a decrease in string weight on the drill string; rotating the drill string upon detecting the decrease in the string weight; and receiving a signal at a surface of the wellbore indicating that a sensor in an outwardly biased latch of the latch assembly is secured within a latch pocket of a latch coupling within the wellbore.
Clause 18, the method of clause 17, comprising installing a downhole tool within the wellbore at a position uphole from the latch assembly, wherein the latch assembly secured within the latch coupling prevents the downhole tool from moving downhole.
Clause 19, the method of clauses 17 or 18, wherein rotating the drill string comprises aligning the latch assembly in a single orientation that enables securement of the latch assembly within the latch coupling.
Clause 20, the method of at least one of clauses 17-19, wherein rotating the drill string comprises aligning the latch assembly in one of a number of orientations that enable securement of the latch assembly within the latch coupling.
While this specification provides specific details related to certain components related to intelligently securing a downhole assembly to a latch coupling, it may be appreciated that the list of components is illustrative only and is not intended to be exhaustive or limited to the forms disclosed. Other components related to intelligently securing the downhole assembly will be apparent to those of ordinary skill in the art without departing from the scope and spirit of the disclosure. Further, the scope of the claims is intended to broadly cover the disclosed components and any such components that are apparent to those of ordinary skill in the art.
It should be apparent from the foregoing disclosure of illustrative embodiments that significant advantages have been provided. The illustrative embodiments are not limited solely to the descriptions and illustrations included herein and are instead capable of various changes and modifications without departing from the spirit of the disclosure.

Claims

What is claimed is:

1. An assembly for anchoring a tool at a subsurface location in a wellbore, comprising:

a latch coupling comprising at least one latch pocket on an internal surface of the latch coupling;

at least one outwardly biased latch comprising at least one key latch that in operation interacts with the at least one latch pocket of the latch coupling to secure the outwardly biased latch within the latch coupling;

a first sensor disposed in the at least one latch pocket;

a second sensor disposed in the at least one key latch, wherein the second sensor detects the first sensor when the at least one outwardly biased latch is secured within the latch coupling; and

a communication sub communicatively coupled to the second sensor and configured to transmit an indication to a surface of the well that the at least one outwardly biased latch is secured within the latch coupling.

2. The assembly of claim 1, wherein the assembly comprises a plurality of the outwardly biased latches, and each of the outwardly biased latches comprises two key bits positioned at different distances from an uphole end of the outwardly biased latch than the key bits of the other outwardly biased latches.

3. The assembly of claim 2, wherein the latch coupling comprises key pockets that correspond to each of the key bits of the outwardly biased latches such that the outwardly biased latches are securable in the latch coupling in a single orientation.

4. The assembly of claim 1, wherein the communication sub transmits the indication that the at least one outwardly biased latch is secured within the latch coupling using acoustic telemetry, electro-magnetic telemetry, mud pulse telemetry, or any combination thereof.

5. The assembly of claim 1, wherein the assembly is configured to anchor a whipstock at an uphole location such that a lateral wellbore is drillable from the wellbore.

6. The assembly of claim 1, wherein the latch coupling comprises a set of grooves extending around an inner circumference of the latch coupling that provides a mechanical indication that the at least one latch is within the latch coupling but not secured.

7. The assembly of claim 6, wherein the mechanical indication comprises a reduction in weight experienced by the drill string that exceeds a predetermined threshold.

8. The assembly of claim 1, wherein the at least one key latch comprises a square shoulder that engages with the latch pocket of the latch coupling to prevent further downhole movement of the at least one latch.

9. The assembly of claim 1, wherein the second sensor comprises a magnetic sensor or an electric contact.

10. The assembly of claim 1, wherein the first sensor comprises a magnet or a current path.

11. An assembly, comprising:

a latch assembly comprising:

at least one outwardly biased latch comprising at least one key latch that in operation interacts with at least one latch pocket of a latch coupling located within the well to secure the latch assembly within the latch coupling; and

a biasing device configured to provide a radially outward biasing force on the at least one outwardly biased latch;

a first sensor disposed in the at least one key latch of the at least one outwardly biased latch, wherein the first sensor is configured to detect when the at least one key latch is secured within the at least one latch pocket; and

a communication sub communicatively coupled to the first sensor and configured to transmit an indication to a surface of the well that the at least one outwardly biased latch is secured within the latch coupling.

12. The assembly of claim 11, wherein the assembly comprises a downhole tool positioned uphole from the latch assembly, and wherein the latch assembly, when secured within the latch coupling, provides a downhole anchor for the downhole tool.

13. The assembly of claim 11, wherein the latch assembly is securable to the latch coupling in only a single orientation.

14. The assembly of claim 11, wherein the latch assembly is securable to the latch coupling in more than one orientation.

15. The assembly of claim 11, wherein the at least one key latch comprises a squared shoulder that is configured to engage with the latch pocket of the latch coupling to prevent further downhole movement of the at least one latch.

16. The assembly of claim 11, wherein the at least one outwardly biased latch comprises two key latches, and each of the two key latches comprises a squared shoulder configured to support the latch assembly when the at least one outwardly biased latch is secured within the latch coupling.

17. A method of securing a latch assembly within a wellbore, comprising:

applying a downhole force on a drill string;

detecting a decrease in string weight on the drill string;

rotating the drill string upon detecting the decrease in the string weight; and

receiving a signal at a surface of the wellbore indicating that a sensor in an outwardly biased latch of the latch assembly is secured within a latch pocket of a latch coupling within the wellbore.

18. The method of claim 17, comprising installing a downhole tool within the wellbore at a position uphole from the latch assembly, wherein the latch assembly secured within the latch coupling prevents the downhole tool from moving downhole.

19. The method of claim 17, wherein rotating the drill string comprises aligning the latch assembly in a single orientation that enables securement of the latch assembly within the latch coupling.

20. The method of claim 17, wherein rotating the drill string comprises aligning the latch assembly in one of a number of orientations that enable securement of the latch assembly within the latch coupling.