Downhole Completion Assembly and Related Systems and Methods of Use

Not applicable.

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 and completion assembly that may be run into a wellbore and useable for wellbore isolation, and methods pertaining to the same. In particular embodiments, the downhole system may include a completion assembly that may have a first sub and a second sub.

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.

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. Pat. No. 8,955,605, incorporated by reference herein in its entirety for all purposes.

illustrates a conventional plugging systemthat includes use of a downhole toolused for plugging a section of the wellboredrilled into formation. The tool or plugmay be lowered into the wellboreby way of workstring(e.g., e-line, wireline, coiled tubing, etc.) and/or with setting tool, as applicable. The toolgenerally includes a bodywith a compressible seal memberto seal the toolagainst an inner surfaceof a surrounding tubular, such as casing. The toolmay include the seal memberdisposed between one or more slips,that are used to help retain the toolin place.

In operation, forces (usually axial relative to the wellbore) are applied to the slip(s),and the body. As the setting sequence progresses, slipmoves in relation to the bodyand slip, the seal memberis actuated, and the slips,are driven against corresponding conical surfaces. This movement axially compresses and/or radially expands the compressible member, and the slips,, which results in these components urged outward from the toolto contact the inner wall.

In this manner, the toolprovides a seal expected to prevent transfer of fluids from one sectionof the wellbore across or through the toolto another section(or vice versa, etc.), or to the surface. Toolmay also include an interior passage (not shown) that allows fluid communication between sectionand sectionwhen desired by the user. Oftentimes multiple sections are isolated by way of one or more additional plugs (e.g.,A).

The setting toolis incorporated into the workstringalong with the downhole tool. Examples of conventional setting tools include the Baker #10 and #20, and the ‘Owens Go’.

Conventional, and even modern, tools require an amount of materials and components that still result in a set tool being in excess of twelve inches. A shorter tool means less materials, less parts, reduced removal time, and easier to deploy. Also by convention, it remains that one type of company is known to provide a working setting tool, while another type of company is known to provide a downhole tool. Putting these two together for the downhole environment is usually done by way of an adapter kit or the like. This leaves end users trying to mate a setting tool made by one company with a downhole tool made by another company, with neither of these tools being made with each other specifically in mind.

Because legacy setting tools like Bakerare made to be generic (usable with many tools via an adapter kit), they have not changed in a manner that accommodates rapid change and advancement in corresponding downhole tool(s). These setting tools use numerous parts and sealings that all are subject to failure (hence increased risk) over time; all require constant redress and/or maintenance. These setting tools use additional parts, such as a barrel piston and a setting sleeve, to convert hydraulic force (via increased gas pressure) to mechanical force (pushing the setting sleeve against the downhole tool).

Accordingly, there are needs in the art for novel systems and methods for isolating wellbores in a fast, viable, and economical fashion. There is a great need in the art for downhole plugging tools that form a reliable and resilient seal against a surrounding tubular that use less materials, less parts, have reduced or eliminated removal time, and are easier to deploy, even in the presence of extreme wellbore conditions. There is a need in the art to avoid use of a conventional setting tool kit or adapter, and instead provide end users with a combination completion assembly (which may already be pre-assembled). Other needs include an improved completion assembly that is one or more of shorter, simpler, less (or no) moving parts, lighter, cheaper, either reusable or disposable, and/or can convey a hydraulic force directly to the downhole tool.

Embodiments of the disclosure pertain to a completion assembly (and related systems and methods) for use in a wellbore. The completion assembly may be a combination of one or more portions or subs. 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 frac plug).

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, a slip, a bearing ring, an expansion ring, a lower sleeve or shoe, and so forth.

Any component of the first or second portion 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).

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.

In the run-in configuration the second sub may be configured to maintain integrity of a primary pressure chamber disposed at least partially within the first sub, the second sub, or both.

The first sub may be configured to convey a non-mechanical force to the second sub. The non-mechanical force (such as from fluid [gas] pressure) may be used to move the completion assembly from the run-in configuration to the disconnected configuration. The completion assembly may move from the run-in configuration to a set configuration, which may have a range of position motion associated therewith.

Any portion of the first sub that remains engaged with the workstring may be retrievable out of the wellbore in the disconnected configuration. Also in the disconnected configuration an at least a portion of the second sub remains in the wellbore. The second sub may be used in support of an at least one downhole operation that occurs after the first sub is retrieved out of the wellbore (for example, hydraulic fracturing or other type of pressure isolation function).

Embodiments herein provide for a completion assembly for use in a wellbore that may include the first sub coupled with the second sub in a run-in configuration. In the run-in configuration the second sub is configured to maintain integrity of an atmospheric pressure chamber disposed at least partially within the second sub. The completion assembly may be void of any components of a conventional setting tool, such as a setting tool adapter or adapter kit, a barrel piston, and a setting sleeve.

Other embodiments of the disclosure may provide for a downhole setting system for use in a wellbore that may include a completion assembly having a first sub; and a second sub comprising a component having a working surface, the second sub engaged with the first sub in a run-in configuration.

In a disconnected configuration the first sub may be disengaged from the second sub, and thereafter first sub may be retrievable out of the wellbore without at least a portion of the second sub. In the disconnected configuration the working surface may not be retrieved out of the wellbore.

Yet other embodiments herein may provide for a downhole setting system for use in a wellbore. The system may have a completion assembly configured with a first sub; and a second sub engaged with the first sub (suitable for use in the wellbore, such as in a run-in configuration). In the run-in configuration the completion assembly may include an inner chamber maintained at a first pressure that is isolated from an external wellbore pressure as the completion assembly is run into the wellbore.

Still other embodiments of the disclosure herein may provide for a downhole setting system for use in a wellbore that may include a completion assembly operable in an at least one configuration comprising: a run-in configuration, a set configuration, a disconnected configuration, and combinations thereof.

In the run-in configuration the completion assembly may have an inner chamber maintained at a first pressure that is isolated from an external pressure (such a from fluid in the wellbore, tubular, etc.) as the completion assembly is run into the wellbore. In the disconnected configuration the inner chamber may no longer be isolated from the external wellbore pressure.

Other embodiments of the disclosure pertain to a downhole setting system for use in a wellbore that may include a workstring; a power charge mandrel coupled to the workstring; and a downhole tool coupled with the power charge mandrel. The power charge mandrel may be retrievable with the workstring. The downhole tool may be coupled with the power charge mandrel in a run-in configuration. The downhole tool may be disconnected from the power charge mandrel in a set or disconnected configuration. A completion assembly may be coupled with the workstring, whereby the completion assembly includes the power charge mandrel coupled with the downhole tool.

The completion assembly may be pre-assembled, which is to say the power charge mandrel and the downhole tool may be coupled together prior to use or delivery to an end user. The pre-assembly may occur, for example, in a shop environment or some other suitable location. The pre-assembly may occur more than 0.5 miles from a wellhead. As measured from a point of original of pre-assembly to final delivery destination, the range of distance may be about 0.25 miles to about 10,000 miles. In other embodiments, the completion assembly may be (pre)assembled at the wellhead or other point of delivery.

The power charge mandrel may include a first power charge mandrel end and a second power charge mandrel end. A power charge or other type of ignitable material suitable to create (gas) pressure may be disposed within the power charge mandrel.

The power charge mandrel may be configured to pass a (gas/fluid/hydraulic) pressure to the downhole tool. In aspects, the (non-mechanical) pressure may act directly onto and/or against a working surface of the downhole tool. In a run-in configuration the working surface (and the downhole tool) may be coupled with the power charge mandrel. In another configuration (such as a set or disconnected configuration), the working surface may be disconnected from the power charge mandrel, and remain downhole with an at least one component of the (set) downhole tool (which may be for a period of time, random or known).

Any completion assembly of embodiments herein may have an isolation device and/or an isolation device sea. The device/seat may be disposed at least partially within or in direct proximity to any inner chamber in the run-in configuration. For example, this may be such that the isolation device and the isolation device seat may each or both be isolated from the external wellbore pressure as the completion assembly is run into the wellbore.

Any completion assembly embodiment herein in the run-in configuration may have a second pressure chamber maintained at a respective pressure (e.g., atmospheric) that may also isolated from the external wellbore pressure as the completion assembly is run into the wellbore.

Any second pressure chamber may be formed between a pair of seal rings separated by a chamber length of at least 0.2 inches to no more than 10 inches.

Any completion assembly embodiment herein in the run-in configuration may be void of any of: a setting tool adapter or adapter kit, a barrel piston, and a setting sleeve. In aspects, the assembly may be void of each of: a setting tool adapter or adapter kit, a barrel piston, and a setting sleeve.

Any completion assembly embodiment herein may have the first sub that includes a power charge mandrel, and the second sub that includes a downhole tool (such as a frac plug). The power charge mandrel may be engaged with the downhole tool via a mating feature in the run-in configuration. The mating feature may be broken, sheared, disconnected, etc. when the completion assembly moves to the disconnected configuration.

Any completion assembly embodiment herein may have the second sub configured with a working surface. The working surface may be directly contacted by pressure/force conveyed from the first sub.

Any completion assembly of embodiments herein may have the first sub configured with an inner bore or chamber in fluid communication with a pressure chamber. The pressure chamber may be a region or space that changes volume over time, such as when the completion assembly moves from the run-in configuration to another configuration.

Any completion assembly of embodiments herein may have the second sub configured with a (tool) mandrel. The mandrel is not limited to any particular shape. The mandrel may have a distal end; a proximate end; an inner flowbore; and an outer surface.

Any completion assembly of embodiments herein may be pre-assembled, whereby the first sub is engaged with the second sub prior to use in the field. Pre-assembly may occur at any location, such as at the wellhead or in a shop environment. In aspects, the first sub and the second sub may be pre-assembled engaged together at a location measured by a straight-line distance range of at least 0.5 miles to no more than 10,000 miles away from a wellhead associated with the wellbore.

Any completion assembly of the disclosure may be have one or more components may be made of any desired material. For example, one or more components may be made of: a reactive material, a composite plastic material, a hard metal material (such as cast iron), a soft metal material (such as magnesium), a corrodible material, a dissolvable material, etc., and combinations thereof.

Any completion assembly of embodiments herein may have an inner pressure chamber maintained at a first pressure that is isolated from external wellbore pressure as the completion assembly is run into the wellbore. The first sub and/or second sub may be configured to facilitate the isolation of the first pressure from the external wellbore pressure in the run-in configuration (such as via one or more seal rings therebetween).

Any completion assembly of embodiments herein may have at least one component of the second sub engaged with a tubular or other surrounding surface in the wellbore in the disconnected configuration. The engagement may be for any amount of period of time. The period of time need not be indefinitely or permanent.

Any component of the completion assembly embodiments herein may be engaged, for a limited duration, such as at least 12 hours to no more than 500 days.

Any completion assembly of embodiments herein may be void any moving parts or components normally associated with conventional setting tools that used in moving the second sub from the run-in configuration to a set configuration.

Any completion assembly of embodiments herein may use a power charge suitable to create or increase a fluid pressure. The assembly may be configured to convey the fluid pressure to an intended target, such as a working surface. In this respect, the fluid pressure may directly impact on the working surface.

Any completion assembly of embodiments herein may use a non-mechanical force to move the completion assembly from the run-in configuration to the disconnected configuration. The non-mechanical force may impact directly against a working surface that remains in the wellbore in the disconnected configuration.

Any completion assembly of embodiments herein may have the first sub include a power charge mandrel.

Any completion assembly of embodiments herein may have the second sub include a downhole tool.

These and other embodiments, features and advantages will be apparent in the following detailed description and drawings.

Herein disclosed are novel apparatuses, assemblies, tools, systems, methods, etc. that pertain to and are usable for wellbore operations, details of which are described herein.

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.

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.