Downhole completion assembly and systems and related methods of use

Abstract

A completion assembly suitable for use in a wellbore, the completion assembly having a downhole tool. The completion assembly is configured to move from a run-in configuration to an intermediate configuration, as well as a disconnected configuration. In the intermediate configuration the downhole tool is coupled with a bottom hole assembly. In the disconnected configuration the downhole tool is not coupled with the bottom hole assembly.

Description

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0001] Not applicable. BACKGROUNDField of the Disclosure

[0002] This disclosure generally relates to downhole tools and related systems and methods used in oil and gas wellbores. More specifically, the disclosure relates to a downhole system having a completion assembly that may be run into a wellbore and useable for wellbore isolation, and methods pertaining to the same. In particular embodiments, the completion assembly may include a connect-disconnect system or (sub)assembly usable to connect and / or disconnect, and re-connect, a workstring with a downhole sub.BACKGROUND OF THE DISCLOSURE

[0003] An oil or gas well includes a wellbore extending into a subterranean formation at some depth below a surface (e.g., Earth’s surface), and is usually lined with a tubular, such as casing, to add strength to the well. Many commercially viable hydrocarbon sources are found in “tight” reservoirs, which means the target hydrocarbon product may not be easily extracted. The surrounding formation (e.g., shale) to these reservoirs typically has low permeability, and it is uneconomical to produce the hydrocarbons (i.e., gas, oil, etc.) in commercial quantities from this formation without the use of drilling accompanied with fracing operations.

[0004] Fracing now has a significant presence in the industry, and is commonly understood to include the use of some type of plug set in the wellbore below or beyond the respective target zone, followed by pumping or injecting high pressure frac fluid into the zone. For economic reasons, fracing (and any associated or peripheral operation) is now ultra-competitive, and in order to stay competitive innovation is paramount. A frac plug and accompanying operation may be such as described or otherwise disclosed in U.S. Patent No. 8,955,605, incorporated by reference herein in its entirety for all purposes.

[0005] FIG. 1 illustrates a conventional plugging system 100 that includes use of a downhole tool 102 used for plugging a section of the wellbore 106 drilled into formation 110. The tool or plug 102 may be lowered into the wellbore 106 by way of workstring 112 (e.g., e-line, wireline, coiled tubing, etc.) and / or with setting-disconnect type tool 117, as applicable. The tool 102 generally includes a body 103 with a compressible seal member 122 to seal the tool 102 against an inner surface 107 of a surrounding tubular, such as casing 108. The tool 102 may include the seal member 122 disposed between one or more slips 109, 111 that are used to help retain the tool 102 in place.

[0006] In operation, forces (usually axial relative to the wellbore 106) are applied to the slip(s) 109, 111 and the body 103. As the setting sequence progresses, slip 109 moves in relation to the body 103 and slip 111, the seal member 122 is actuated, and the slips 109, 111 are driven against corresponding conical surfaces 104. This movement axially compresses and / or radially expands the compressible member 122, and the slips 109, 111, which results in these components being urged outward from the tool 102 to contact the inner wall 107. In this manner, the tool 102 provides a seal expected to prevent transfer of fluids from one section 113 of the wellbore across or through the tool 102 to another section 115 (or vice versa, etc.), or to the surface. Tool 102 may also include an interior passage (not shown) that allows fluid communication between section 113 and section 115 when desired by the user. Oftentimes multiple sections are isolated by way of one or more additional plugs (e.g., 102A).

[0007] The system 100 may include other types of downhole tools 102, 102a such as a packer (e.g., open hole packer, etc.). A conventional packer may be a swellable type, while other packers are known as inflatable or hydraulic.

[0008] Packers, frac plugs, and other downhole tools of the sort all share a point of commonality, in that such tools need to be run, set, disconnected, and / or later removed or retrieved, which requires multiple or repeated interventions into the well. What is needed is an improved apparatus, system, and the like for disconnecting and / or (re)connecting a workstring with a downhole tool, especially without having to resort to using separate run-in and retrieval tools.SUMMARY

[0009] Embodiments of the disclosure pertain to a downhole completion assembly (and related systems and methods) for use in a wellbore.

[0010] The completion assembly may include one or more of a downhole tool, an upper sub, a lower sub, a bottom hole assembly, or other suitable components.

[0011] Any completion assembly embodiment of the disclosure may be used with a system, method, etc. for operation thereof. This may include use of a workstring operably connected with the completion assembly.

[0012] A completion assembly for any embodiment may be used in a wellbore. The wellbore may have a tubular disposed therein, such as casing or comparable.

[0013] The completion assembly may include a downhole tool. The downhole tool may have a mandrel. There may be a second mandrel, which may be integral to or coupled with the mandrel. The mandrel may be configured with an outer surface, such as to accommodate various other components or component interaction. The outer surface may include a crest. The crest may be proximate or adjacent trough, recess, etc. or other surface portion with a reduced diameter as compared to that of the crest.

[0014] The downhole tool may have one or more collet devices, such as a lock collet. The lock colt may be disposed around the mandrel. The lock collet may have one or more lock collect fingers. There may be a plurality of lock collet fingers. Any or all of the fingers may be configured with a respective finger end, which may be of suitable shape for engaging the collet with one or more surrounding surfaces.

[0015] The completion assembly may include a first or upper sub. There may be a second or lower sub, which may be integral to or coupled with the upper sub. The upper sub may be disposed, such as at least partially, around the downhole tool. The upper sub may be disposed around the downhole tool in a run-in configuration. The upper sub may be configured with one or more surface structures. For example, the upper sub may include an inner sub surface. The inner sub surface may have a detent. The detent may be discernable may respective sub surfaces having different or varied IDs.

[0016] In aspects, at least one of the respective finger ends may be engaged with at least one of the crest, the detent, or both, such as in the run-in configuration. This may be a locked, run-in configuration.

[0017] The outer surface may be configured with one or more profiles, such as a first profiled surface and / or a second profiled surface. The lock collet may be coupled with the first profiled surface. In aspects, a sleeve, such as a lower release sleeve, may be coupled with the second profiled surface.

[0018] The lower release sleeve may be coupled with the mandrel, such as via one or more shear features / members. In aspects, the completion assembly may be configured to move from the run-in configuration to an intermediate configuration upon shearing of each of the set of set shear members. Shearing may occur via linear or longitudinal movement. The shear movement need not be rotational.

[0019] The completion assembly may be configured to move from the run-in configuration to the intermediate configuration via respective longitudinal movement between the downhole tool and the upper sub. In aspects, an end of the lower release sleeve may be in direct contact with at least one of the respective finger ends in the run-in configuration.

[0020] The downhole tool may include a latch surface having a ratchet profile configured to engage with a respective profile of the inner sub surface. The downhole tool may include a latch collet disposed around the mandrel comprises the latch surface. A disconnected configuration the downhole tool may be disengaged from the upper sub.

[0021] The completion assembly may include a bottom hole assembly (BHA) coupled with the upper sub. The BHA may be a dowhole device, such as a packer. The upper sub may be a polished bore receptacle (PBR).

[0022] Other embodiments here may include a completion assembly for use in a wellbore that has a downhole tool coupled with an upper sub. The downhole tool may include a mandrel with an outer surface. There may be one or more collets disposed around the mandrel, such as a lock collet. The lock collet may be configured to facilitate the completion assembly being in a locked, run-in configuration. The lock collet may have a plurality of lock collet fingers, one or more of which configured with a respective finger end.

[0023] The completion assembly may have an upper sub disposed at least partially around the downhole tool in a run-in configuration. The upper sub may have an inner sub surface. In the run-in configuration, at least one of the respective finger ends may be engaged with each of the outer surface and the inner sub surface.

[0024] The completion assembly may be configured to move from the run-in configuration to a disconnected configuration, which may be via linear, longitudinal, or both, movement between the downhole tool and the upper sub.

[0025] The completion assembly may be configured to move from the run-in configuration to a disconnected configuration without need of rotation between the downhole tool and the upper sub.

[0026] Yet other embodiments of the disclosure may pertain to a completion assembly having one or more of a downhole tool, an upper sub, and a bottom hole assembly, one or more of which may be coupled together when the assembly is in a run-in configuration.

[0027] The completion assembly may be configured to move from the run-in configuration to a disconnected configuration via linear movement between one or more of the downhole tool, the upper sub, and the bottom hole assembly. Operation =the completion assembly to move to the disconnected configuration need not require rotational movement of the completion assembly.

[0028] These and other embodiments, features and advantages will be apparent in the following detailed description and drawings.BRIEF DESCRIPTION OF THE DRAWINGS

[0029] A full understanding of embodiments disclosed herein is obtained from the detailed description of the disclosure presented herein below, and the accompanying drawings, which are given by way of illustration only and are not intended to be limitative of the present embodiments, and wherein:

[0030] FIG. 1 is a side view of a process diagram of a conventional plugging system;

[0031] FIG. 2A shows an isometric view of a downhole system having a completion assembly, according to embodiments of the disclosure;

[0032] FIG. 2B shows a partial longitudinal side cross-sectional view of a completion assembly, according to embodiments of the disclosure;

[0033] FIG. 2C shows a longitudinal side view of a downhole tool useable with a completion assembly according to embodiments of the disclosure;

[0034] FIG. 2D shows an isometric component breakout view of part of a downhole tool according to embodiments of the disclosure;

[0035] FIG. 2E shows an isometric component breakout view of a collet with one or more release sleeves for use with the downhole tool of FIG. 2D according to embodiments of the disclosure;

[0036] FIG. 2E shows an isometric component breakout view of a packer assembly or system for use with the downhole tool of FIG. 2D according to embodiments of the disclosure;

[0037] FIG. 2G shows an isometric view of a bottom hole assembly (or component thereof) for use with a completion assembly according to embodiments of the disclosure;

[0038] FIG. 2H shows an isometric component breakout view of a lower end of a downhole tool having a lower packer assembly or system according to embodiments of the disclosure;

[0039] FIG. 3A shows a longitudinal side cross-sectional view of a completion assembly in run-in configuration according to embodiments of the disclosure;

[0040] FIG. 3B shows a close-up longitudinal side cross-sectional view of the assembly of FIG. 3A according to embodiments of the disclosure;

[0041] FIG. 3C shows a longitudinal side cross-sectional view of the completion assembly in an unlocked configuration according to embodiments of the disclosure;

[0042] FIG. 3D shows a close-up longitudinal side cross-sectional view of the assembly of FIG. 3C according to embodiments of the disclosure;

[0043] FIG. 3E shows a longitudinal side cross-sectional view of the completion assembly moving to a disconnected configuration according to embodiments of the disclosure;

[0044] FIG. 3F shows a close-up longitudinal side cross-sectional view of the assembly of FIG. 3E according to embodiments of the disclosure;

[0045] FIG. 3G shows a longitudinal side cross-sectional view of the completion assembly in a disconnected configuration according to embodiments of the disclosure;

[0046] FIG. 3H shows a longitudinal side cross-sectional view of the completion assembly moving to a latched or (re)connected configuration according to embodiments of the disclosure;

[0047] FIG. 3I shows a close-up longitudinal side cross-sectional view of the assembly of FIG. 3H according to embodiments of the disclosure;

[0048] FIG. 3J shows a longitudinal side cross-sectional view of the completion assembly moving to a complete latched or (re)connected configuration according to embodiments of the disclosure;

[0049] FIG. 3K shows a close-up longitudinal side cross-sectional view of the assembly of FIG. 3H according to embodiments of the disclosure; and

[0050] FIG. 3L shows a close-up longitudinal side cross-sectional view of a collet finger end engaged in a detent surface according to embodiments of the disclosure.DETAILED DESCRIPTION

[0051] Herein disclosed are novel apparatuses, systems, and methods that pertain to and are usable for wellbore operations, details of which are described herein.

[0052] Embodiments of the present disclosure are described in detail in a non-limiting manner with reference to the accompanying Figures. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, such as to mean, for example, “including, but not limited to…”. While the disclosure may be described with reference to relevant apparatuses, systems, and methods, it should be understood that the disclosure is not limited to the specific embodiments shown or described. Rather, one skilled in the art will appreciate that a variety of configurations may be implemented in accordance with embodiments herein.

[0053] Although not necessary, like elements in the various figures may be denoted by like reference numerals for consistency and ease of understanding. Numerous specific details are set forth in order to provide a more thorough understanding of the disclosure; however, it will be apparent to one of ordinary skill in the art that the embodiments disclosed herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Directional terms, such as “above,”“below,”“upper,”“lower,”“front,”“back,”“right”, “left”, “down”, etc., are used for convenience and to refer to general direction and / or orientation, and are only intended for illustrative purposes only, and not to limit the disclosure.

[0054] Connection(s), couplings, or other forms of contact between parts, components, and so forth may include conventional items, such as lubricant, additional sealing materials, such as a gasket between flanges, PTFE between threads, and the like. The make and manufacture of any particular component, subcomponent, etc., may be as would be apparent to one of skill in the art, such as molding, forming, press extrusion, machining, or additive manufacturing. Embodiments of the disclosure provide for one or more components that may be new, used, and / or retrofitted.

[0055] Various equipment may be in fluid communication directly or indirectly with other equipment. Fluid communication may occur via one or more transfer lines and respective connectors, couplings, valving, and so forth. Fluid movers, such as pumps, may be utilized as would be apparent to one of skill in the art.

[0056] Numerical ranges in this disclosure may be approximate, and thus may include values outside of the range unless otherwise indicated. Numerical ranges include all values from and including the expressed lower and the upper values, in increments of smaller units. As an example, if a compositional, physical or other property, such as, for example, molecular weight, viscosity, temperature, pressure, distance, melt index, etc., is from 100 to 1,000, it is intended that all individual values, such as 100, 101, 102, etc., and sub ranges, such as 100 to 144, 155 to 170, 197 to 200, etc., are expressly enumerated. It is intended that decimals or fractions thereof be included. For ranges containing values which are less than one or containing fractional numbers greater than one (e.g., 1.1, 1.5, etc.), smaller units may be considered to be 0.0001, 0.001, 0.01, 0.1, etc. as appropriate. These are only examples of what is specifically intended, and all possible combinations of numerical values between the lowest value and the highest value enumerated, are to be considered to be expressly stated in this disclosure. Others may be implied or inferred.

[0057] Embodiments herein may be described at the macro level, especially from an ornamental or visual appearance. Thus, a dimension, such as length, may be described as having a certain numerical unit, albeit with or without attribution of a particular significant figure. One of skill in the art would appreciate that the dimension of “2 centimeters” may not be exactly 2 centimeters, and that at the micro-level may deviate. Similarly, reference to a “uniform” dimension, such as thickness, need not refer to completely, exactly uniform. Thus, a uniform or equal thickness of “1 millimeter” may have discernable variation at the micro-level within a certain tolerance (e.g., 0.001 millimeter) related to imprecision in measuring and fabrication.Terms

[0058] The term “connected” as used herein may refer to a connection between a respective component (or subcomponent) and another component (or another subcomponent), which can be fixed, movable, direct, indirect, and analogous to engaged, coupled, disposed, etc., and can be by screw, nut / bolt, weld, and so forth. Any use of any form of the terms “connect”, “engage”, “couple”, “attach”, “mount”, etc. or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements (unless indicated otherwise) and may also include indirect interaction between the elements described.

[0059] The term “fluid” as used herein may refer to a liquid, gas, slurry, multi-phase, etc. and is not limited to any particular type of fluid such as hydrocarbons.

[0060] The term “fluid connection”, “fluid communication,”“fluidly communicable,” and the like, as used herein may refer to two or more components, systems, etc. being coupled whereby fluid from one may flow or otherwise be transferrable to the other. The coupling may be direct or indirect. For example, valves, flow meters, pumps, mixing tanks, holding tanks, tubulars, separation systems, and the like may be disposed between two or more components that are in fluid communication.

[0061] The term “pipe”, “conduit”, “line”, “tubular”, or the like as used herein may refer to any fluid transmission means, and may be tubular in nature.

[0062] The term “composition” or “composition of matter” as used herein may refer to one or more ingredients, components, constituents, etc. that make up a material (or material of construction). Composition may refer to a flow stream, or the material of construction of a component of a downhole tool, of one or more chemical components.

[0063] The term “chemical” as used herein may analogously mean or be interchangeable to material, chemical material, ingredient, component, chemical component, element, substance, compound, chemical compound, molecule(s), constituent, and so forth and vice versa. Any ‘chemical’ discussed in the present disclosure need not refer to a 100% pure chemical. For example, although ‘water’ may be thought of as H2O, one of skill would appreciate various ions, salts, minerals, impurities, and other substances (including at the ppb level) may be present in ‘water’. A chemical may include all isomeric forms and vice versa (for example, "hexane", includes all isomers of hexane individually or collectively).

[0064] The term “pump” as used herein may refer to a mechanical device suitable to use an action such as suction or pressure to raise or move liquids, compress gases, and so forth. ‘Pump’ can further refer to or include all necessary subcomponents operable together, such as impeller (or vanes, etc.), housing, drive shaft, bearings, etc. Although not always the case, ‘pump’ can further include reference to a driver, such as an engine and drive shaft. Types of pumps include gas powered, hydraulic, pneumatic, and electrical.

[0065] The term “frac operation” as used herein may refer to fractionation of a downhole well that has already been drilled. ‘Frac operation’ can also be referred to and interchangeable with the terms fractionation, hydrofracturing, hydrofracking, fracking, fracing, frac, and the like. A frac operation can be land or water based.

[0066] The term “mounted” as used herein may refer to a connection between a respective component (or subcomponent) and another component (or another subcomponent), which can be fixed, movable, direct, indirect, and analogous to engaged, coupled, disposed, etc., and can be by screw, nut / bolt, weld, and so forth.

[0067] The term “run-in configuration” (run-in position, etc.) may refer to an arrangement of components on or coupled with a workstring collectively deployed downhole (such as into a wellbore or tubestring). ‘Run-in’ configuration is understood by one of skill in the art to precede in temporal sequence to a set or disconnected configuration. The components of the workstring (separately or in combination) may be field dressed, shop dressed, and sometimes both. The ‘run-in’ configuration is akin to an ‘unset’ configuration.

[0068] The term “workstring” as used herein may refer to any type of device (e.g., wireline, etc.) that is operable to provide some kind of action, such as drilling, running a tool, or any other kind of downhole / wellbore action, and combinations thereof.

[0069] The term “sub” or “portion” may be used in an analogous manner to refer to a subassembly or component, which may be useable with another subassembly or component. One or more subs may be coupled together as an overall assembly and / or with a workstring. A bottom hole assembly (BHA) may be analogous to a sub. A BHA may be referred to as a downhole tool. A completion assembly be referred to as one or more downhole tools, assemblies, (sub)systems, and the like, coupled together. A completion assembly may have a run-in configuration with one or more downhole tools of the assembly coupled together. The completion assembly may have a disconnected configuration with one or more downhole tools no longer coupled together.

[0070] The completion assembly may be a combination of one or more portions, tools, subs, etc. For example, the completion assembly may have a first portion (also, upper / top portion, retrievable portion, first sub [subassembly], etc.). The completion assembly may have a second portion (also, lower / bottom portion, disconnected portion, second sub, etc.). The second portion may be any type of downhole tool (for example, a packer or frac plug).

[0071] Such downhole tools may include a number of components, such as a mandrel having a distal end; a proximate end; and an outer surface. Any number of components may be disposed around the mandrel. For example, one or more of: a seal element and / or a slip, and so forth.

[0072] Any component of embodiments herein may be made of a composite material, a metallic material, a reactive material, poly- (PGA, etc.) material, plastic material, corrodible material, etc. and combinations thereof. The material may be dissolvable, or otherwise reactive to surrounding materials (such as wellbore fluid).

[0073] Embodiments herein provide for a completion assembly for use in a wellbore. The completion assembly may have a first sub and a second sub. The first sub and the second sub may be at least partially engaged in a run-in configuration, and may be at least partially disconnected or disengaged in a disconnected configuration. The completion assembly may be engaged with a workstring (such as wireline or the like) when run or deployed into the wellbore.

[0074] For some embodiments, a material of construction may include a composition of matter designed or otherwise having the inherent characteristic to react or change integrity or other physical attribute when exposed to certain wellbore conditions, such as a change in time, temperature, water, heat, pressure, solution, combinations thereof, etc. Heat may be present due to the temperature increase attributed to the natural temperature gradient of the earth, and water may already be present in existing wellbore fluids. The change in integrity may occur in a predetermined time period, which may vary from several minutes to several weeks. In aspects, the time period may be about 12 to about 36 hours.

[0075] The term “machined” can refer to a computer numerical control (CNC) process whereby a robot or machinist runs computer-operated equipment to create machine parts, tools and the like. Any component may be machined. Any component may be 3D-printed or made with other forms of additive manufacturing.

[0076] The term “plane” or “planar” as used herein may refer to any surface or shape that is flat, at least in cross-section. For example, a frusto-conical surface may appear to be planar in 2D cross-section. It should be understood that plane or planar need not refer to exact mathematical precision, but instead be contemplated as visual appearance to the naked eye. A plane or planar may be illustrated in 2D by way of a line.

[0077] The term “parallel” as used herein may refer to any surface or shape that may have a reference plane lying in the same direction or vector as that of another. It should be understood that parallel need not refer to exact mathematical precision, but instead be contemplated as visual appearance to the naked eye.

[0078] Referring now to FIGS. 2A, 2B, 2C, 2D, 2E, 2F, 2G, and 2H together, an isometric view of a downhole system having a completion assembly, a partial longitudinal side cross-sectional view of a completion assembly, a longitudinal side view of a downhole tool useable with a completion, an isometric component breakout view of part of a downhole tool, an isometric component breakout view of a collet with one or more release sleeves, an isometric component breakout view of a packer assembly or system, an isometric view of a bottom hole assembly (or component thereof) for use with a completion assembly, and an isometric component breakout view of a lower end of a downhole tool having a lower packer assembly or system, respectively, illustrative of embodiments disclosed herein, are shown.

[0079] FIGS. 2A-2H depict a wellbore 206 formed in a subterranean formation 210 with a tubular 208 disposed therein. In an embodiment, the tubular 208 may be casing (e.g., casing, hung casing, casing string, etc.) (which may be cemented), and the like.

[0080] A workstring 212 (shown only here in partial or schematic block form) may may be used to position or run a completion assembly 201 into and through the wellbore 206 to a desired location. The completion assembly 201 may have a number of configurations (or positions, etc.), which may have a temporal sequence of operations associated therewith. For example, the assembly 201 may have a run-in (or run-in hole RIH) configuration, and a disconnected configuration. There may be a number of other or intermediate configurations.

[0081] The completion assembly 201 may be understood or contemplated as one or more tools, subs, portions, components, etc. coupled together, with any thereof having respective components, assemblies, systems, etc. As shown in FIG. 2A, the completion assembly 201 may have the run-in configuration that includes a first sub, or also downhole tool, 202. The downhole tool 202 may be configured for coupling with the workstring 212. The downhole tool 202 may be coupled with an upper sub 233, and may be coupled with a lower or bottom hole sub 205. The upper sub 233 is not meant to be limited, and may be tool such as a polished bore receptacle (PBR), tie-back receptacle (TBR), seal receptacle, or the like.

[0082] The bottom hole sub 205 is not meant to be limited, and may be any type of tool or device useable in the wellbore 208. For the sake of brevity, the sub 205 may be referred to as a bottom-hole-assembly or BHA. No additional meaning should be inferred from ‘bottom-hole’, as the use of the term is only intended for general non-limiting discussion. An example of the BHA 205 may be a frac plug, a packer, or other comparable fluid isolation or sealing devices, tools, etc. The BHA 205 may be configured and operable for having a surface (such as a seal and / or a slip) engage against tubular sidewall surface 207.

[0083] The completion assembly 201 may have a disconnected configuration, which may include the downhole tool 202 disconnected or unengaged from the upper sub 233. Thus, in the disconnected configuration, the completion assembly 201 may include the downhole tool 202 coupled with the workstring 212, but the upper sub 233 and the BHA 205 remain in the wellbore disconnected from the workstring 212.

[0084] The downhole tool 202 may include a first or upper tool end 202a, and a second or lower tool end 202b. The first tool end 202a may be associated with upper or primary mandrel 214. The first tool end 202a may be coupled with the worstring 212 (such as via threading or the like). While the tool 202 may only include a single mandrel 214, sometimes it may be the case that greater tool length is desired. Thus, the tool 202 may include more than one mandrel, such as the upper mandrel 214 and a lower or secondary mandrel 215 (or sometimes ‘stinger’).

[0085] Although not limited, the lower mandrel 215 may be elongated and of a tubular nature. The second end 202b may be associated with the distal end of the lower mandrel 215. The mandrels 214, 215 may be of the size or shape to readily dispose and fit within the upper sub 233. The upper sub 233 may be a housing type structure (such as of a PBR-type device, etc.). Although the upper sub 233 may be the only housing for the assembly 201, there may be a bottom sub 232 coupled with the upper sub 233 (such as via threading or the like). As such, one or both of the mandrels 214, 215 may also be of the size or shape to readily dispose and fit within the lower sub 232.

[0086] The lower sub 232 may couple with the BHA 205. As the setting and operation of any BHA 205 would be known to one of skill, only a schematic block representation of the BHA 205 need be shown. The lower mandrel 215 may be configured with a lower seal or packing system 241, which may provide sealing or fluid containment against inner sub surface 255.

[0087] The lower system 241 may be one or more seals / packers 242 and retainer rings 243 that form a stack. The seals 242 and rings 243 may be positioned in an alternating configuration around an outer lower sub surface 215a. In an analogous manner, there may be an upper seal or packing system 240. The upper system 240 may include one or more seals / packers 242a and rings 243a, which may form a stack. As shown here, the lower sub 232 may include a lower or bottom sleeve 260 (which may be a mule shoe or the like).

[0088] The downhole tool 202, as well as its components, may be annular in nature, and thus centrally disposed or arranged with respect to a longitudinal axis 285. The downhole tool 202 may include the mandrel 214 (and / or 215) may be configured to extend, at least partially or entirely, the long length of the tool 202 (or tool body).

[0089] As shown here, although not required, the upper mandrel 214 with the lower mandrel may include a flowpath or bore 250 formed therein (e.g., an axial bore). The bore 250 may extend partially or for a short distance through the mandrels 214, 215. Alternatively, the bore 250 may extend through the entire tool 202, with an opening at its proximate upper end 202a and oppositely at its distal lower end 202b (near downhole end of the tool 202).

[0090] With the presence of the bore 250, the upper mandrel 214 may have an inner bore surface 256a (see also bore surface 256b of mandrel 215), which may be smooth and annular in nature. In cross-section, the bore surfaces 256a, 256b may be planar. In embodiments, the bore surfaces 256a, 256b (in cross-section) may be parallel to a (central) tool axis 285.

[0091] An outer mandrel surface 230 may have one or more surfaces (in cross-section) offset or angled, parallel, perpendicular, combinations thereof, etc. to the tool axis 285. As shown here, the outer mandrel surface 230 may be discontinuous with one or more undulations, protrusions, grooves, etc.

[0092] There may be an upper sleeve 216 disposed around the outer mandrel surface 230. The upper sleeve 216 may be held in place via one or more securements 223 (pins, set screws, or the like). The upper sleeve 216 may be engaged or otherwise coupled with the mandrel 214, such as at a sleeve contact point or connection 257. The contact point / connection 257 may be, for example, a threaded connection, whereby the sleeve 216 and the mandrel 214 have respective mating features such as threads.

[0093] With the presence of a rigid-style connection, the sleeve 216 may be used as a locator or a physical stop against the upper sub 233 for the time when the downhole tool 202 is stabbed back into and (re)connected with the sub 233.

[0094] The upper sleeve 216 may be a retainer-type sleeve used for retaining or holding a latch collet (sleeve, ring, etc.) 217. For example, a first latch collet end 224a may be solid ring structure, which may also be disposed around the mandrel 214. The upper sleeve 216 may be engaged with the upper mandrel 214 in a manner that holds and retains the collet end 224a, and thus the latch collet 217, in place.

[0095] The latch collet 217 may have one or more latch collet fingers that extend away from the first collet end 224a all the way to a second collet end 224b. Respective, adjacent latch collet fingers may be separated by elongated, longitudinal cuts or grooves 217a. One or more of the collet fingers may be configured with a respective latch surface or ratchet profile 227, which may be at respective ends 224b.

[0096] To facilitate position of the latch collet 217 along the mandrel 214, the mandrel 214 may have a splined outer surface or portion 230a. As shown, the splined outer surface 230a may have one or more splines 222 disposed thereon. Although not limited to any particular shape, the splines 222 may be elongated and longitudinal in nature in orientation. Generally, the splines 222 may be configured (sized, shaped, etc.) to coincide with slidingly engaging with the latch collet 217 via respective grooves 217a.

[0097] Also disposed around the mandrel 214 (or outer surface 230) may be one or more sleeves, retainers, etc. As shown here, there may be an upper release sleeve 218, which may be held in place via one or more upper shear members 221a (such as shear pins, shear screws, etc.). Any shear member 221a may be disposed through one or more sleeve holes or apertures 246a, and into respective receptacles 247a of the upper mandrel 214 (see outer mandrel surface portion 230b).

[0098] The downhole tool 202 may include other sleeves, such as a lower release sleeve 229. Analogous to the upper sleeve 218, the lower release sleeve 229 may be held in place via one or more upper shear members 221b (such as shear pins, shear screws, etc.). Any shear member 221b may be disposed through one or more sleeve holes or apertures 246b, and into respective receptacles 247b of the upper mandrel 214 (see outer mandrel surface portion 230c).

[0099] Between the sleeves 218, 229 may be a lower or lock collet 231. The lower collet 231 may have an upper collet end of a solid ring-type shape 235a, from which one or more lower collet fingers 235b may extend therefrom. The position of the lower collet 231 may be used to assess whether the completion assembly may be in a proper locked, run-in configuration. For example, the upper sub 233 may be configured with a port or opening 234 within its sidewall that provides a visual indicator V of the location of a collet finger end (nub, extension, etc.) 236. The port 234 may be closed via installing or closing with a seal cap or cover 234a (one or more securement devices [pins, screws, etc.] may be used).

[0100] When the collet finger end 236 (of a respective finger 235b) is positioned against and on a crest surface 238 of the mandrel, as well as within a detent or recess 239 formed on inner sub surface 233a of the upper sub 233, the completion assembly 201 may be in the locked, run-in configuration. While it need not be necessary to be locked in order to run-in the wellbore 206, the locked position may aid against inadvertent or undesired movement of any component of the assembly 201.

[0101] One or more lock ring or retainers 226, 228 may be disposed around the mandrel 214. The outer surface 230 may have one or more profiled (e.g., threaded portions) 258a, 258b, for which the any lock ring and / or sleeve may engage there against. The outer surface 230 may have one or more depressed portions 237a, 237b, which may be used to accommodate movement of the finger ends 236.

[0102] Referring now to FIGS. 3A, 3B, 3C, 3D, 3E, 3F, 3G, 3H, 3I, 3J, 3K, and 3L together, a longitudinal side cross-sectional view of a completion assembly in a run-in configuration, a close-up longitudinal side cross-sectional view of the same, a longitudinal side cross-sectional view of the completion assembly in an unlocked configuration, a close-up longitudinal side cross-sectional view of the assembly of the same, a longitudinal side cross-sectional view of the completion assembly moving to a disconnected configuration, a close-up longitudinal side cross-sectional view of the assembly of the same, a longitudinal side cross-sectional view of the completion assembly in a disconnected configuration, a longitudinal side cross-sectional view of the completion assembly moving to a latched or (re)connected configuration, a close-up longitudinal side cross-sectional view of the assembly of the same, a longitudinal side cross-sectional view of the completion assembly moving to a complete latched or (re)connected configuration, a close-up longitudinal side cross-sectional view of the same, and a close-up longitudinal side cross-sectional view of a collet finger end engaged in a detent surface, respectively, in accordance with embodiments disclosed herein, are shown.

[0103] A downhole system 300 may have a completion assembly 301 (with downhole tool 302), which may be run, set, and operated as described herein and in other embodiments (such as in System 200, and so forth), and as otherwise understood to one of skill in the art.

[0104] Components of the completion assembly 301 may include a downhole tool 302 coupled with a bottom hole assembly (BHA, 205), as described herein and in other embodiments, and as otherwise understood to one of skill in the art. The BHA may be a known device (packer, frac plug, liner hanger, etc.) configured with its own setting feature mechanism, such as to extend a packer element, slip, etc. away from the BHA and into engagement with a (surrounding) tubular 308.

[0105] Setting may include conventional components such as a power charge or other type of setting function. Setting may occur via (fluid) pressure transferred through the downhole tool 302 to the BHA. Details of the BHA are not needed for understanding the operation of the assembly 301. The assembly 301 may also include an upper sub 333, which may be coupled with the BHA.

[0106] Thus, completion assembly 301 may be comparable or identical in aspects, function, operation, components, etc. as that of other embodiments disclosed herein. Similarities may not be discussed for the sake of brevity.

[0107] For use in operation the assembly 301 (or portions thereof) may be assembled, such as at a worksite, shop, etc. On its own, the assembly 301 may be the downhole tool 302 and the upper sub 333, with the BHA already in the wellbore 306 or coupled as part of the assembly 301. In a run-in configuration the assembly 301 may include the downhole tool 302 coupled with a workstring (212, as described herein and in other embodiments). The workstring may be a known device or mechanism, details of which are not needed for understanding the operation of the assembly 301.

[0108] FIGS. 3A-3B show the assembly 301 in a run-in configuration. The upper sub 333 may have a port 324, which may be used to provide a visual indication of whether the assembly 301 is in a locked, run-in configuration. The sub 333 and the tool 302 may be movable with respect to each other to ensure a collet finger end(s) 336 (of a lower or lock collet 331) engages into a detent or recess 339 formed on inner sub surface 333a of the upper sub 333.

[0109] The downhole tool 302 may include a first or upper mandrel 314. Although the mandrel 314 be elongated for the entirety of the assembly 301, it may be desired to have a second or lower mandrel 315. The mandrels 314, 315 may be configured with mating features (threads, etc.) for coupling together.

[0110] In an analogous manner there may just be the upper sub 333; however, it may be desirous to have another (second, lower, etc.) sub 332. The subs 332, 333 may be tubular housing type structures, which may have respective ends 332a, 333b configured for coupling together (threads, etc. – see sub engagement point 348). The mandrels 314, 315 may be configured for movingly disposing within the subs 332, 333 (unless or until the locked, run-in configuration is reached).

[0111] The mandrel 314, 315 may extend through the tool (or tool body) 302 in the sense that components may be disposed therearound. In aspects, the mandrel 314 may include a flowpath or bore 350 formed therein (e.g., an axial bore). The bore 350 may extend partially or for a short distance through the tool 302. Alternatively, the bore 350 may extend through the entire mandrel 314, 315 with an opening at its proximate tool end 302a and oppositely at its distal end 302b.

[0112] Other components of the tool 302 may be disposed around the mandrel 314 (or outer surface 330 thereof) in a manner that there is sufficient, desired fit within spacing or inner annulus 345 formed between the mandrel 314 and sub 330. There may be a first or upper sleeve 316, which may be engaged and disposed around the mandrel to facilitate the holding or retaining of an upper latch collet 317. The latch collet 317 may have one or more collet fingers configured with teeth or ratchet profile 327.

[0113] In the proximate vicinity of the latch collet 317 there may be a first or upper release sleeve 318, which may be held in place around the mandrel 314 via one or more securements (pins, screws, etc.). Further along the mandrel 314 may be a second or lower release sleeve 329, which may also be held in place around the mandrel 314 via one or more securements or shear members (pins, screws, etc.) 321b (disposed through the sleeve 329 and also into the mandrel 314).

[0114] The mandrel 314 (or the outer surface 330) may be configured with one or more profiled surfaces 358a, 358b. The surfaces 358a, 358b may be teeth, threads, ratchet, etc. The use of a ratchet type configuration for surfaces 358a, 358b may facilitate movement of the respective sleeve in a first direction, but prevent return movement the opposite direction. The profiled surfaces 358a, 358b may be configured to facilitate unidirectional movement of respective sleeves during operation.

[0115] The second sleeve 329 may be engaged with the profiled surface 358b. There may be a respective lock ring 328 coupled between the sleeve 329 and the surface 358b, which may facilitate ease of use, maintenance, and repair.

[0116] The lower release sleeve 329 may have a first or upper sleeve end 329a and a second sleeve end 329b. The lock ring 328 may be engaged more so toward the second sleeve end 329b, whereas the upper sleeve end 329a may be proximate the collet finger end(s) 336. In the locked, run-in configuration, the upper sleeve end 329a may abut against and engage the end(s) 336 (see FIGS. 3A, 3B).

[0117] Disposed around the mandrel 314 and between the sleeves 318, 329 may be the lower collet 331. Comparable to the release sleeve 329, the lower collet 331 may have a lower collet body end 331a configured to couple with the profile surface 358a. There may be an upper lock ring 326, which may be coupled between the lower collet end 331a and the profile surface 358a.

[0118] In assembly of the completion assembly 301, the position of the lower collet 331 may be adjusted until the end(s) 336 rest on a mandrel surface crest 338. The lower collet 331 may have fingers biased inward (toward axis 385). The shape and configuration of the crest 338 may ensure that the end 336 may be moved or otherwise urged into the detent 339. The crest 338 may be contemplated as a surface portion of the mandrel 314 that has a crest outer diameter D1 that may be larger than an adjacent or proximate surface portion of the mandrel 314 with portion diameter D2.

[0119] The nature of the bias of the collet 331 may be sufficient to maintain the end 336 in the detent 339 as the assembly is 331 moved from the locked, run-in configuration to an intermediate configuration, such as an unlocked configuration. To change the configuration of the assembly 301 the workstring (212) may undergo a pull, rotation, etc. Because the BHA may be held in place against the tubular 308, and the upper sub 333 is maintained with the tool 302 (via the lock of end 336 with detent 339), the assembly 301 may not change configuration unless or until a disruption event occurs.

[0120] It may be the case that the configuration of the assembly 301 may be changed exclusive to liner longitudinal motion (pull) of the workstring and assembly 301, thus without need of any rotation. This type of motion may be understood as having a vector in parallel to the axis 385, and not in rotation therearound.

[0121] The amount of force needed in pulling on the workstring to change the configuration of the assembly may be predetermined, and accomplished from using a desired amount of shear members (e.g., 321b). For example, if four shear members 321b are used with a shear / break rating of 4,000 lbsf, then the pull force on the workstring would need be more than 16,000 lbsf in order to cause the disruption and breaking of the members 321b so that the assembly 301 may now move to the unlocked configuration.

[0122] FIGS. 3C and 3D illustrate the intermediate or unlocked configuration, whereby members 321b have undergone shear or breakage, thereby allowing lower sleeve 329 to urge or move with respect to the mandrel 314. In the same respect, the end 336 may also now move off the crest 338. Due to the inward bias of fingers of lower collet 331, the ends 336 (or fingers) may flex against recessed mandrel surface portion 337a, 337b (337b illustrated here).

[0123] As the end 336 need no longer constrain the movement of the sub 333, the assembly 301 may now be considered in the unlocked configuration. Thus, the unlocked configuration may include breakage of the members 321b, and the end 336 engaged against surface portion 337b (and / or off of the crest 338).

[0124] In the unlocked configuration, the assembly 301 now may include the downhole tool 302 with freedom of movement from either the sub 333 and / or the BHA (205). It may be the case the downhole tool 302 may maintain some form of sealing engagement with the sub 333 (or sub 332) (e.g., via upper and lower packer systems 340, 341) unless or until a disconnected configuration (see FIG. 3G). The use of packer systems 340, 341 may facilitate holding pressure during any circulation sequence through the assembly 301.

[0125] FIGS. 3E and 3F illustrate the assembly 301 in a moment in time moving from the intermediate or unlocked configuration to a disconnected configuration. The workstring may be used to continue to move the downhole tool 302 (or mandrels 314, 315) out of sub bore 350a. FIG. 3G shows a disconnected configuration whereby the downhole tool end 302b is free of the bore 350a. The disconnected configuration may include the downhole tool 302 no longer sealingly engaged with the sub 333 (or lower sub 332).

[0126] In the disconnected configuration any number of downhole or completion operations may occur in the wellbore 306 (or tubular 308). When it is desired to remove or retrieve the BHA, the assembly 301 may be moved to a re-connected configuration. In this manner, the workstring may be used to (re)lower the downhole tool 302 back into engagement with the sub 333 and the BHA.

[0127] FIGS. 3H and 3I illustrate the end 302b stabbed back into the sub 332 / 333, and which may include back into sealing engagement therebetween. As before, this may occur in a linear and / longitudinal movement, which may be without need of rotation. The benefit of a linear movement (as compared to rotational) means there need not be any backing off of threads of components which may otherwise be impacted by rotational movement. Moreover, because components of the assembly 301 may be operated without rotational movement means that other components may be rotated for their respective, isolated operation.

[0128] In aspects, the linear movement to operate the assembly 301 may be void of rotational movement. In other aspects, there may be some nominal amount of rotation (such as inadvertent) that the assembly 301 may tolerate, such as about less than + / - 10 degrees.

[0129] The annulus 345 permits the freedom of the movement between the tool 302 and the sub 333, which may continue to a point where an inner sub profile (such as teeth or the like) 351 may move into contact and engagement with the latch surface profile 327 (see contact point 349). As one of skill would appreciate, the nature of the latch surface profile 327 may facilitate movement of the profile 351 thereagainst in the re-connection direction, but prevents movement the opposite direction.

[0130] The re-connected configuration may include a complete re-connected configuration, such as that shown by way of example in FIGS. 3J and 3K. Although not required to re-connect entirely in this manner, it may be desirous to move the assembly 301 to the complete re-connected configuration in order to achieve a better mechanical advantage in support of BHA removal. In this configuration, the maximum amount of contact may occur between sub profile 351 and the latch surface profile 327. Further movement may be precluded by sub end surface 353 abutting against or stopped by upper sleeve end 316a (see contact point 354).

[0131] The upper sleeve 316 may be engaged or otherwise coupled with the mandrel 314, such as at a sleeve contact point or connection (e.g., 257). The contact point / connection may be, for example, a threaded connection, whereby the sleeve 316 and the mandrel 314 have respective mating features such as threads.

[0132] With the presence of a rigid-style connection, the sleeve 316 may be used as a locator or a physical stop against the upper sub 333 in the (complete) reconnected configuration.

[0133] Embodiments of the disclosure provide a completion assembly that may be run-in all together, for example the completion assembly in the run-in configuration may include the downhole tool, the upper sub, and the bottom hole assembly all coupled together. The completion assembly may be run-in the wellbore via a workstring.

[0134] In this complete coupling of the completion assembly, the BHA may be set without having to disconnect from the downhole tool. In this manner, setting may occur while the completion assembly remains together. Circulation of fluid through the assembly may be used, which may result in saving a trip out of the wellbore.Advantages .

[0135] Embodiments of the disclosure may provide for a downhole system that may provide or include a reliable, high-performance downhole tool suitable for a wide range of production and injection applications. Such system may be available in a variety of configurations to suit a wide range of well conditions.

[0136] Embodiments herein may be a one-trip system, which may be conveyed or operated with via a workstring (such as any suitable downhole tubing). One-trip configuration may reduce rig time and simplify installation. Also advantageously the downhole system may allow for retrieval of an upper completion device or sub without disturbing other downhole devices (such as a packer).

[0137] Embodiments herein may advantageously provide improved (upward to maximum) sealing reliability. For example, a high-pressure packing element system may be used with a field-adjustable start-to-set pressure.

[0138] Any component may be made from any desired variety of materials to suit most well environments. May be used with production, injection, and zonal isolation. Deviated wells or other applications where no rotation for installation or removal is desired. Applications where displacing and setting the packers after the well is flanged up is desirable. No mandrel movement during setting of the packer. Anchored or floating seal application. May be provided in numerous ratings, such as 10k, 12K, and 15K psi (emissions V3-V0). Available in permanent, shift to release and cut to release options. Rotationally locked components for ease in milling.

[0139] While preferred embodiments of the disclosure have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the disclosure disclosed herein are possible and are within the scope of the disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations. The use of the term "optionally" with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, and the like.

[0140] Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present disclosure. Thus, the claims are a further description and are an addition to the preferred embodiments of the present disclosure. The inclusion or discussion of a reference is not an admission that it is prior art to the present disclosure, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent they provide background knowledge; or exemplary, procedural or other details supplementary to those set forth herein.

Claims

1. A completion assembly for use in a wellbore, the completion assembly comprising:a downhole tool comprising:a mandrel with an outer surface comprising a crest; anda lock collet disposed around the mandrel, the lock collet comprising a plurality of lock collet fingers, each configured with a respective finger end;an upper sub disposed at least partially around the downhole tool in a run-in configuration, the upper sub comprising an inner sub surface configured with a detent,wherein in the run-in configuration at least one of the respective finger ends is engaged with at least one of the crest, the detent, or both.

2. The completion assembly of claim 1, wherein the outer surface comprises a first profiled surface and a second profiled surface, and wherein the lock collet is coupled with the first profiled surface, and a lower release sleeve is coupled with the second profiled surface.

3. The completion assembly of claim 2, wherein the lower release sleeve is coupled with the mandrel via a set of one or more shear members, and wherein the assembly is configured to move from the run-in configuration to an intermediate configuration upon shearing of each of the set of set shear members.

4. The completion assembly of claim 3, wherein the completion assembly is configured to move from the run-in configuration to the intermediate configuration via respective longitudinal movement between the downhole tool and the upper sub.

5. The completion assembly of claim 2, wherein an end of the lower release sleeve is in direct contact with at least one of the respective finger ends in the run-in configuration.

6. The completion assembly of claim 5, wherein the downhole tool further comprises a latch surface having a ratchet profile configured to engage with a respective profile of the inner sub surface.

7. The completion assembly of claim 6, wherein a latch collet disposed around the mandrel comprises the latch surface.

8. The completion assembly of claim 5, wherein in a disconnected configuration the downhole tool is disengaged from the upper sub.

9. The completion assembly of claim 5, the completion assembly further comprising a bottom hole assembly (BHA) coupled with the upper sub.

10. The completion assembly of claim 9, wherein the BHA comprises a packer and the upper sub comprises a polished bore receptacle (PBR).

11. A completion assembly for use in a wellbore, the completion assembly comprising:a downhole tool comprising:a mandrel with an outer surface; anda lock collet disposed around the mandrel, the lock collet comprising a plurality of lock collet fingers, each configured with a respective finger end;an upper sub disposed at least partially around the downhole tool in a run-in configuration, the upper sub comprising an inner sub surface,wherein in the run-in configuration at least one of the respective finger ends is engaged with each of the outer surface and the inner sub surface.

12. The completion assembly of claim 11, wherein the completion assembly is configured to move to a disconnected configuration via linear movement between the downhole tool and the upper sub.

13. The completion assembly of claim 11, wherein the completion assembly is configured to move to a disconnected configuration without need of rotation between the downhole tool and the upper sub.

14. The completion assembly of claim 11, wherein the outer surface comprises a first profiled surface and a second profiled surface, and wherein the lock collet is coupled with the first profiled surface, and a lower release sleeve is coupled with the second profiled surface.

15. The completion assembly of claim 14, wherein the lower release sleeve is coupled with the mandrel via a set of one or more shear members, and wherein the assembly is configured to move from the run-in configuration to an intermediate configuration upon shearing of each of the set of set shear members.

16. The completion assembly of claim 15, wherein an end of the lower release sleeve is in direct contact with at least one of the respective finger ends in the run-in configuration.

17. The completion assembly of claim 11, wherein the downhole tool further comprises a latch surface having a ratchet profile configured to engage with a respective profile of the inner sub surface in a re-connected configuration, but the ratchet profile is not engaged with the respective profile in the run-in configuration.

18. The completion assembly of claim 17, the completion assembly further comprising a bottom hole assembly (BHA) configured as a packer coupled with the upper sub, wherein the upper sub comprises a polished bore receptacle (PBR).1919 A completion assembly for use in a wellbore, the completion assembly comprising:a downhole tool;an upper sub; anda bottom hole assembly,wherein in a run-in configuration the downhole tool, the upper sub, and the bottom hole assembly are coupled together,wherein the completion assembly is configured to move to a disconnected configuration via linear movement between one or more of the downhole tool, the upper sub, and the bottom hole assembly.

20. The completion assembly of claim 19, wherein operating the completion assembly to move to the disconnected configuration does not require rotational movement of the completion assembly.

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