RU2788698C1 - Downhole tool and method of its use - Google Patents

Abstract

FIELD: drilling.

SUBSTANCE: the invention relates to a downhole tool that can be used to isolate the wellbore. A downhole tool for isolating a wellbore for hydraulic fracturing is claimed, containing a taper mandrel containing a distal end, a proximal end, an outer surface and an inner flow channel, and the taper mandrel additionally contains a ball seat formed in the inner flow channel, a support ring engaged in a sliding manner with the proximal end of the taper mandrel. The support ring additionally contains the outer groove for the sealing element, the sealing element located in the outer groove for the sealing element, a wedge die connected to the distal end and a lower sleeve connected to the slip. In this case, the slip contains at least one groove of the slip, which forms a side hole in the slip, which is determined by the depth that extends from the outer surface of the slip to the inner surface of the slip. Moreover, the outer surface contains the first inclined surface and the second inclined surface. In this case, the first inclined surface contains the first plane, which in cross-section is intersected in half by the longitudinal axis at the first angle in the range from 5 to 10°, and the second inclined surface contains the second plane, which in cross-section is intersected in half by the longitudinal axis at an angle negative with respect to the first angle. Moreover, the first inclined surface and the second inclined surface converge at the crest, and the crest has a crest wall thickness exceeding the wall thickness of the furthest distal end and the wall thickness of the nearest end.

EFFECT: providing a reliable seal in relation to the surrounding tubular element while simplifying the design of the device

20 cl, 11 dwg

Description

Technical field

[0001] This disclosure generally relates to downhole tools and associated systems and methods used in oil and gas wellbores. More specifically, this disclosure relates to a downhole system and tool that can be run into a wellbore and can be used to isolate the wellbore, as well as methods related thereto. In specific embodiments, the downhole tool may be a plug made from drillable materials. In other embodiments, one or more of the components may be made from a soluble material, any of which may be composite or metal based.

State of the art

[0002] An oil or gas well includes a wellbore extending into a subterranean formation at some depth below the surface ( e.g. , the Earth's surface), and is typically lined with a tubular member, such as a casing, to increase the strength of the well. Many commercially viable sources of hydrocarbons are in "tight" reservoirs, which means that the desired hydrocarbon product cannot be easily recovered. The formation surrounding these reservoirs ( eg shale) usually has low permeability and it is uneconomical to produce commercial quantities of hydrocarbons ( i.e. gas, oil, etc.) from this formation without the use of drilling followed by hydraulic fracturing operations.

[0003] Fracturing is now widely used in the industry and is generally understood as the use of a set of plugs of some type in a wellbore below or outside of the respective target zone, followed by pumping or injecting a high pressure fracturing fluid into said zone. For economic reasons, hydraulic fracturing (and any associated or peripheral operation) is currently ultra-competitive, and in order to remain competitive, innovation is paramount. The fracturing plug and accompanying operation may be as described or otherwise disclosed in US Pat. No. 8,955,605.

[0004] FIG. 1 illustrates a conventional plug setting system 100 that includes the use of a downhole tool 102 used to plug a section of a wellbore 106 drilled into a formation 110. The tool or plug 102 may be lowered into the wellbore 106 using a workstring 112 ( e.g. , electric cable, cable, flexible tubing, etc.) and/or using the installation tool 117, as the case may be. The tool 102 generally includes a housing 103 with a compressible sealing element 122 for sealing the tool 102 against the inner surface 107 of a surrounding tubular element, such as a casing 108. The tool 102 may include a sealing element 122 positioned between one or more slip slips. 109, 111 which are used to hold the tool 102 in place.

[0005] In operation, forces (typically axial with respect to the wellbore 106) are applied to the slip(s) 109, 111, and body 103. As the installation sequence progresses, slip 109 moves relative to body 103 and slip 111, sealing member 122 is actuated and the wedges 109, 111 are pressed against the respective conical surfaces 104. This movement axially compresses and/or expands the compressible element 122 and the wedges 109, 111 in the radial direction, causing these components to be pushed outward from the tool. 102 to contact the inner wall 107. Thus, the tool 102 provides a seal that is intended to prevent fluids from being transferred from one wellbore section 113 along or through the tool 102 to another section 115 (or vice versa, etc.) or onto surface. Tool 102 may also include an internal passageway (not shown) that provides fluid communication between section 113 and section 115 as desired by the user. Often several sections are insulated with one or more additional plugs ( eg 102A).

[0006] The setting tool 117 is integrated into the workstring 112 along with the downhole tool 102. Examples of commercial setting tools include Baker #10 and #20, and Owens Go. When properly installed, the plug can be subjected to high or extreme pressure and temperature conditions, which means that the plug must withstand these conditions without breaking the plug or the seal formed by the sealing element. High temperatures are generally defined as downhole temperatures above 200°F, and high pressures are generally defined as downhole pressures above 7500 psi and even above 15000 psi. Extreme wellbore conditions may also include high and low pH environments. Under these conditions, conventional tools, including those with compressible sealing elements, may become ineffective due to degradation. For example, said sealing element may melt, harden, or otherwise lose elasticity, resulting in the loss of its ability to form a sealing barrier.

[0007] Conventional plugs typically require some sort of removal process, such as milling or drilling, before mining operations can begin. Drilling usually entails drilling through a set plug, but in some cases the plug may be removed from the wellbore substantially intact ( i.e. , retrieval). A common problem with retrievable plugs is debris buildup on the top of the plug, which can make it difficult or impossible to engage and remove the plug. Such accumulation of debris can also adversely affect the relative movement of the various parts within the cork. In addition, with modern retrieval tools, jerky movements or friction against the well casing can cause the retrieval tool to accidentally disengage (causing further slippage of the tools into the wellbore) or re-lock the plug (due to triggering of the plug's anchor elements). Problems like this often cause a plug to be drilled out that should have been recoverable.

[0008] However, because the plugs must withstand extreme downhole conditions, they are designed for durability and strength, which often makes the process of through drilling difficult, time-consuming and/or requiring considerable experience. Even drillable plugs are usually made of metal, such as cast iron, which can be drilled out with a drill bit at the end of the drill string. Steel can also be used in the structural body of the plug to provide structural strength for tool placement. The more metal parts used in the tool, the longer the drilling operation takes. Because metal components are more difficult to drill, this process may require additional runs into and out of the wellbore to replace worn drill bits.

[0009] Composite materials, such as filament-wound materials, are popular in the fracturing industry because of their ease of drilling. The process for making filament-wound materials is known in the art and, although it may vary, generally involves the known process. However, even composite plugs require drilling or often have one or more pieces of metal (sometimes hardened metal).

[0010] The use of wellbore plugs presents other problems because these tools are subject to known failure modes. When the plug is driven into place, slips tend to be pre-set before the plug reaches its destination, resulting in casing damage and job delays. Presetting can occur, for example, from residue or debris ( eg sand) left over from a previous fracturing. In addition, it is known that conventional plugs do not seal well not only with the casing, but also between plug components. For example, when a sealing element is subjected to compression, its surfaces do not always seal properly with surrounding components ( eg , cones, etc.).

[0011] Downhole tools are often activated by a drop ball that flows from the surface down to the tool, where the fluid pressure must be sufficient to overcome the static pressure and buoyancy of the downhole fluid(s) in order for the ball to reach the tool. The fracturing fluid is also under high pressure to not only transport the fluid into and through the wellbore, but also to pass into the formation, causing the fracture. Accordingly, the downhole tool must be able to withstand these additional higher pressures.

[0012] It is naturally desirable to "flow back", i.e. from the formation to the surface, the injected fluid or formation fluid(s); however, this is not possible until the previously installed tool or its lock is removed. Removal of tools (or blockage) usually requires intervention to retrieve or drill through, which is time and cost intensive, and increases the potential risk of damage to the wellbore.

[0013] The more metal parts used in the tool, the longer the through drilling operation takes. Because metal components are more difficult to drill, such an operation may require additional trips in and out of the wellbore to replace worn drill bits.

[0014] In the interest of conserving materials that react under certain downhole conditions, significant research has been carried out considering the potential offered by the oilfield industry. For example, such an improved material having the ability to break down in response to a change in the environment is desirable because no or limited intervention is required to remove or activate.

[0015] Such a material, largely self-acting due to changes in its environment ( for example , the presence of a certain liquid, a change in temperature and / or a change in pressure, etc.), can potentially replace expensive and complex designs and can be most advantageous in situations when availability is limited or even deemed impossible, such as in a downhole (underground) environment. However, these materials tend to be exotic, making related instruments made from such materials undesirable due to their high cost.

[0016] Conventional and even modern tools require so many materials and components that it still results in an installed tool that exceeds twelve inches. The shorter the tool, the less materials, fewer parts, less dismantling time and easier deployment.

[0017] The ability to save on materials and/or labor time (as well as save operating costs) leads to significant competition in the market. Reaching for any opportunity to save time, or ultimately cost, results in an immediate competitive advantage.

[0018] Accordingly, there is a need in the art for new systems and methods for isolating wellbores in a fast, viable, and economical manner. Moreover, it remains desirable to have a downhole tool that provides a larger flow path but is still capable of withstanding installation forces. There is a great need in the art for downhole plug setting tools that form a secure and resilient seal against the surrounding tubular, that use fewer materials, fewer parts, reduce or eliminate removal time, and are easier to deploy even in the presence of extreme downhole conditions. conditions. There is also a need for a downhole tool made from a substantially drillable material that is easier and faster to drill, or that completely eliminates the need for through drilling.

SUMMARY OF THE INVENTION

[0019] Embodiments of this disclosure relate to a downhole tool for use in a wellbore, which may include any of the following: a cone mandrel comprising: a distal end; proximal end; and outer surface. There may be a support ring slidably engaged with said distal end. The support ring may include an outer groove for the sealing element. The sealing element may be located in the outer groove for the sealing element. There may be a wedge die engaged with the proximal end. There may be a lower bushing connected to a wedge ram.

[0020] The conical mandrel may be in the form of a double truncated cone. Thus, the outer surface may include a first inclined surface and a second inclined surface. The first inclined surface may include a first plane that is bisected in cross section by a longitudinal axis with a first angle range of 5 degrees to 40 degrees. The second slope may be negative with respect to the first slope. In some aspects, the second inclined surface may include a second plane that, in cross section, bisects a longitudinal angle negative with respect to the first angle. The second angle may be in the range of the second angle from 5 degrees to 40 degrees.

[0021] The wedge ram may include at least one wedge ram groove that defines a side hole in the wedge ram. The wedge ram groove may be formed by a first piece of wedge ram material at the first end of the wedge ram and a second piece of wedge ram material at the second end of the wedge ram. The groove of the wedge ram may have a depth that extends from the outer surface of the wedge ram to the inner surface of the wedge ram.

[0022] The wedge ram may have at least one pin hole adjacent to at least one groove of the wedge ram. The lower sleeve may have a pin groove proximate the at least one pin hole. There may be a pin located within one or both of at least one pin hole and at least one pin hole.

[0023] Any component of the downhole tool may be made from a composite material. Any downhole tool component is made from a soluble material. The soluble material may be composite or metal based.

[0024] The wedge ram may include at least one primary fracture. The support ring can be configured to be elongated by about 10% to 20% over its original shape. The support ring can be extended without breaking.

[0025] The downhole tool (or cone) may have an internal flow channel. The inner flow channel may have an internal diameter in the range of the channel from about 1 inch to 5 inches.

[0026] The lower sleeve may have a shear tongue. In aspects, the sealing element is not engaged or otherwise in direct contact with the cone. In aspects, the longitudinal length of the downhole tool after installation may be in the installation length range of about 5 inches to about 15 inches.

[0027] The taper mandrel may include a ball seat formed in the inner flow channel.

[0028] Other embodiments of this disclosure relate to a downhole installation system for use in a wellbore, which may include a workstring; a setting tool assembly connected to the work string; and a downhole tool connected to the setting tool assembly.

[0029] The setting tool may include a tension mandrel having a first tension mandrel end and a second tension mandrel end. The installation tool assembly may include an installation sleeve.

[0030] The downhole tool may include: a conical mandrel comprising: a distal end; proximal end; and outer surface. The downhole tool may have a support ring slidably engaged with said distal end. The support ring may include an outer groove for the sealing element. A sealing element may be located in the outer groove for the sealing element. There may be a wedge die engaged with the proximal end. There may be a lower bushing connected to a wedge ram.

[0031] The tension mandrel may be positioned through the downhole tool. The nose nut may be engaged with each of the second end of the tension mandrel and the lower sleeve.

[0032] The outer surface of the cone mandrel may be a double truncated cone. Thus, there may be a first inclined surface and a second inclined surface. The first inclined surface may include a first plane that is bisected in cross section by a longitudinal axis with a first angle range of 5 degrees to 40 degrees. The second inclined surface may include a second plane that, in cross section, bisects a longitudinal angle negative with respect to the first angle. The second angle can be in the range of the second angle (negative) from 5 degrees to 40 degrees.

[0033] The cone mandrel may include a ball seat formed in the inner flow channel.

[0034] Any downhole tool component can be made from a polymer-based material. Any downhole tool component can be made from a metal base material.

[0035] Embodiments of this disclosure relate to a downhole tool suitable for use in a wellbore. The downhole tool may include a mandrel made from a reactive material, which may be metal based. The mandrel may include a distal end; proximal end; and outer surface.

[0036] An uninstalled downhole tool may have a length of about 4 inches to about 20 inches in the longitudinal direction. The downhole tool in a fully installed position may be less than 15 inches long in the longitudinal direction.

[0037] These and other embodiments, features, and advantages will be apparent from the following detailed description and drawings.

BRIEF DESCRIPTION OF GRAPHICS

[0038] A complete understanding of the embodiments disclosed herein is derived from the detailed description of the disclosure provided herein below and the accompanying drawings, which are given by way of illustration only and are not intended to limit the present embodiments, and in which:

[0039] FIG. 1 is a side view of a flow chart of a conventional plug setting system;

[0040] in FIG. 2A is an isometric view of a system having a downhole tool in accordance with embodiments of this disclosure;

[0041] in FIG. 2B is an isometric sectional view of a system having a downhole tool, in accordance with embodiments of this disclosure;

[0042] onfig. 2C shows a longitudinal side view in cross section an unidentified downhole tool in accordance with embodiments of this disclosure;

[0043] in FIG. 2D is a longitudinal sectional side view of the downhole tool of FIG. 2C, in a mounted position in accordance with embodiments of this disclosure;

[0044] in FIG. 2E is a longitudinal sectional side view of the downhole tool shown in FIG. 2C, in position and disconnected from the work string, in accordance with embodiments of this disclosure;

[0045] in FIG. 3A is an isometric exploded view of a downhole tool in accordance with embodiments of this disclosure;

[0046] in FIG. 3B is an assembled isometric view of the downhole tool of FIG. 3A in accordance with embodiments of this disclosure;

[0047] in FIG. 3C is a longitudinal sectional side view of the downhole tool of FIG. 3B, in accordance with embodiments of this disclosure;

[0048] in FIG. 4A is a longitudinal sectional side view of a downhole tool having a flap according to embodiments of this disclosure; and

[0049] in FIG. 4B is a longitudinal sectional side view of the downhole tool of FIG. 4A with an open flap in accordance with embodiments of this disclosure.

DETAILED DESCRIPTION

[0050] Disclosed herein are novel apparatuses, systems, and methods that relate to wellbore operations and can be used for wellbore operations, the details of which are described herein.

[0051] Embodiments of the present disclosure are described in detail in non-limiting form with reference to the accompanying figures. In the following discussion and in the claims, the terms "including" and "comprising" are used in the clear, for example, meaning "including but not limited to...". While this disclosure may be described with reference to appropriate apparatuses, systems, and methods, it should be understood that this disclosure is not limited to the specific embodiments shown or described. Rather, one of skill in the art will appreciate that a variety of configurations may be implemented in accordance with the embodiments provided herein.

[0052] Although not required, the same elements in different figures may be identified by the same reference numbers for consistency and ease of understanding. Numerous specific details are set forth in order to provide a more complete understanding of this disclosure; however, one skilled in the art will appreciate that the embodiments disclosed herein may be practiced without these specific details. In other cases, well-known features have not been described in detail in order to avoid unnecessary complexity of the description. Direction terms such as "above", "below", "up", "down", "front", "back", "right", "left", "down", etc. are used for convenience and refer to the general direction and/or orientation and are intended for illustrative purposes only and not to limit this disclosure.

[0053] Connection(s), bushings, or other forms of contact between parts, components, etc. may include conventional items such as lubricant, additional sealing materials such as gasket between flanges, PTFE between threads, etc. Fabrication and production of any particular component, sub-component, etc. may be obvious to a person skilled in the art, such as injection molding, molding, extrusion, machining, or additive manufacturing. Embodiments of this disclosure provide for one or more components, which may be new, used, and/or refurbished.

[0054] Various equipment may be in fluid communication, direct or indirect, with other equipment. Fluid communication may occur through one or more transmission lines and associated connectors, bushings, valves, etc. As will be appreciated by one of skill in the art, fluid movers such as pumps can be used.

[0055] Numerical ranges in this disclosure may be approximate and thus may include values outside the range unless otherwise noted. Numeric ranges include all values, including expressed low and high values, in increments of smaller units. For example, if a compositional, physical, or other property such as, for example, molecular weight, viscosity, temperature, pressure, distance, melt index, etc., is between 100 and 1000, it is assumed that all individual values, for example, 100 , 101, 102, etc., and sub-ranges, for example, 100 to 144, 155 to 170, 197 to 200, etc., are explicitly listed. Decimal fractions or their fractions are supposed to be included. For ranges containing values less than one or containing fractional numbers greater than one ( for example , 1.1, 1.5, etc.), 0.0001, 0.001, 0.01, 0.1, etc. can be considered smaller units. d. depending on the situation. These are only examples of what is specifically intended, and all possible combinations of numerical values between the lowest value and the highest of the listed values should be considered as expressly stated in this disclosure. Others may be implied or assumed.

[0056] Embodiments herein may be described at a macro level, especially in terms of decorative or visual appearance. Thus, a dimension such as length can be described as having a specific numerical unit, albeit with or without specifying a specific significant figure. One of ordinary skill in the art will appreciate that the "2 cm" dimension may not be exactly 2 cm, and that 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 a noticeable deviation at the micro level within a certain tolerance ( for example , 0.001 millimeters) associated with measurement and manufacturing inaccuracies.

Terms

[0057] As used herein, the term "connected" may refer to the connection between the respective component (or subcomponent) and another component (or other subcomponent), which may be fixed, movable, direct, indirect, and similar to engagement, connection, placement, and etc., and can be with screw, nut/bolt, welding, etc. Any use of any form of the terms "connect", "hook", "bind", "attach", "mount", etc. or any other term describing the interaction between elements does not mean that the interaction is limited to direct interaction between elements, and may also include indirect interaction between the described elements.

[0058] As used herein, the term "fluid" may refer to a liquid, gas, slurry, multi-phase material, etc. and is not limited to any particular type of fluid such as hydrocarbons.

[0059] The terms "fluid connection", "fluid communication", "fluid communication" and the like, as used herein, may refer to two or more components, systems, etc. connected, whereby fluid from one can flow or otherwise be transferred to the other. The connection can be direct or indirect. For example, valves, flow meters, pumps, mixing tanks, collection tanks, tubular elements, separation systems, etc. may be located between two or more components in fluid communication.

[0060] The term "pipe", "pipe", "line", "tubular element" and the like, as used herein, may refer to any fluid transfer medium and may be tubular in nature.

[0061] As used herein, the term "composition" or "substance composition" can refer to one or more of the ingredients, components, constituents, etc. that make up a material (or material of construction). Composition may refer to the flow or material of construction of a downhole tool component comprised of one or more chemical components.

[0062] As used herein, the term "chemical" may mean similar to or be interchangeable with material, chemical material, ingredient, component, chemical component, element, substance, compound, chemical compound, molecule(s), constituent, etc. . and vice versa. Any "chemical" discussed in the present description does not have to refer to a chemical with 100% purity. For example, while "water" may be understood to mean H2O, one skilled in the art will appreciate that 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 together).

[0063] As used herein, the term "pump" may refer to a mechanical device capable of using an action such as suction or pressure to lift or move liquids, compress gases, etc. "Pump" can also refer to or include all the necessary sub-components working together, such as the impeller (or impellers, etc.), housing, drive shaft, bearings, etc. Although not always the case, "pump" may also include a reference to a drive such as a motor and a drive shaft. Pump types include gas, hydraulic, pneumatic and electric.

[0064] As used herein, the term "fracturing operation" may refer to fracturing a well that has already been drilled. "Fracturing operation" may also be referred to and used interchangeably with the terms hydraulic fracturing, hydraulic fracturing, hydraulic fracturing, hydraulic fracturing, hydraulic fracturing, fracturing, and the like. The fracturing operation may be land or water.

[0065] As used herein, the term "fixed" may refer to the connection between the respective component (or subcomponent) and another component (or other subcomponent), which may be fixed, movable, direct, indirect, and similar to engagement, connection, placement, and etc., and can be with screw, nut/bolt, welding, etc.

[0066] As used herein, the term "reactive material" can refer to a material with a composition of matter having properties and/or characteristics that cause the material to respond to change over time and/or under certain conditions. The term "reactive material" may encompass degradable, soluble, separable, dissociable, etc.

[0067] As used herein, the term "degradable material" can refer to a composition of matter having properties and/or characteristics that, although they may change over time and/or under certain conditions, result in a change in the integrity of the material. For example, the material may initially be hard, tough, and strong at ambient or surface conditions, but over time (eg, within about 12-36 hours) and under certain conditions (eg, downhole conditions), the material softens.

[0068] The term "soluble material" may be analogous to degradable material. As used herein, the term may refer to a composition of a substance that has properties and/or characteristics that, although they may change over time and/or under certain conditions, lead to a change in the integrity of the material, including degradation, partial or complete dissolution. . For example, the material may initially be hard, tough, and strong at ambient or surface conditions, but over time (eg, within about 12-36 hours) and under certain conditions (eg, downhole conditions), the material softens. As another example, the material may initially be hard, stiff, and strong at ambient or surface conditions, but over time (eg, within about 12-36 hours) and under certain conditions (eg, downhole conditions), the material softens. , the material dissolves at least partially, and may completely dissolve. The material may dissolve by one or more mechanisms such as oxidation, reduction, degradation, going into solution, or otherwise losing sufficient mass and structural integrity.

[0069] As used herein, the term "destructible material" can refer to a composition of matter having properties and/or characteristics that, although they may change over time and/or under certain conditions, result in brittleness. For example, a material may be hard, tough, and strong under environmental or surface conditions, but becomes brittle over time and under certain conditions. The destructible material may break into several pieces, but not necessarily dissolve.

[0070] For some embodiments, the material of construction may include a composition of matter designed or otherwise having intrinsic properties to react or change integrity or other physical properties when exposed to certain conditions in the wellbore, such as changes in time, temperature, water, heat, pressure , solution, their combinations, etc. Heat may be present due to temperature rise associated with the earth's natural temperature gradient, and water may already be present in existing well fluids. The change in integrity may occur in a predetermined period of time, which may vary from several minutes to several weeks. In aspects, the time period may be from about 12 hours to about 36 hours.

[0071] The term "machined" may refer to a numerical control (CNC) process in which a robot or operator runs computer-controlled equipment to create machine parts, tools, and the like.

[0072] As used herein, the term "plane" or "flat" can refer to any surface or shape that is planar, at least in cross section. For example, a frustoconical surface may appear flat in two-dimensional cross section. It should be understood that flat or flat does not necessarily have to refer to exact mathematical precision, but instead should be considered as being visible to the naked eye. A plane or flat can be depicted in two-dimensional space using a line.

[0073] As used herein, the term "parallel" can refer to any surface or shape that can have a base plane lying in the same direction or vector as another. It should be understood that parallel does not necessarily have to refer to exact mathematical precision, but is instead treated as an appearance to the naked eye.

[0074] As used herein, the term "tapered mandrel" may refer to a tubular component having at least one surface, typically in the form of a truncated cone. Said conical mandrel may have an outer surface which, in cross section, has a base line/plane that is bisected at an angle by the base axis. The taper mandrel may be a double (also "two-sided", "double-sided", etc.) cone, which means that there may be a second outer surface having a second base line/plane that is divided by a base axis (in cross section) under the second angle. The second angle can be negative with respect to the first angle ( eg +10 degrees for the first, -10 degrees for the second).

[0075] Referring now to FIG. 2A and 2B together are perspective views of a system 200 having a downhole tool 202 illustrating the embodiments disclosed herein. In FIG. 2B shows a wellbore 206 formed in a subterranean formation 210 with tubular 208 disposed therein. In an embodiment, tubular 208 may be a casing string ( e.g. , a casing string, a suspended casing string, a casing string, etc.) (which may be cemented), etc.

[0076] A workstring 212 (which may include a setting tool [or setting tool portion 217] provided with adapter 252) may be used to position or run a downhole tool 202 into and through the wellbore 206 to a desired location. The person skilled in the art will appreciate that the installation tool may be the same as suggested by Baker or Owen. The installation tool assembly 217 may include or be associated with an installation sleeve 254. The mounting sleeve 254 may be engaged with the downhole tool 202 (or component thereof).

[0077] The setting tool may include a tension mandrel 216 coupled ( eg , coupled) to an adapter 252. adapter 252. Said connection may be a threaded connection (eg, via the threads on the adapter 252 and the corresponding threads of the tension mandrel 216 - not shown here). Tension mandrel 216 may protrude at least partially from tool 202 (bottom/downhole/distal end).

[0078] The end or extension 216a of the tension mandrel 216 may be connected to the nose sleeve or nut 224. The nut 224 may have a threaded connection 225 to the end 216a (and thus a corresponding mating thread), although other forms of connection are possible. For additional securing, one or more set screws 226 may be located through the set screw holes 227 and screwed or tightened on end 216a. The nut 224 may engage or abut against the shear tab of the lower sleeve 260.

[0079] The downhole tool 202, as well as its components, may be annular and thus centered or positioned relative to the longitudinal axis 258. In accordance with embodiments of this disclosure, the tool 202 may be configured as a plug setting tool. , which can be installed within tubular member 208 such that tool 202 forms a fluid-tight seal on inner surface 207 of tubular member 208. ring 223. A back-up ring 223 may be positioned around a taper mandrel 214. Once installed, the downhole tool 202 may be held in place by at least one slip 234. The slip 234 may have a one-piece configuration.

[0080] In an embodiment, the downhole tool 202 may be configured as a bridging plug, whereby flow is controlled from one section of the wellbore to another ( eg , above and below the tool 202). In other embodiments, the downhole tool 202 may be in the form of a fracturing plug, where flow into one section 213 of the wellbore 206 may be blocked and otherwise diverted to the surrounding formation or reservoir 210.

[0081] In other embodiments, the downhole tool 202 may also be a drop-ball tool. In this aspect, the ball ( eg , 285, FIG. 2E) may be dropped into the wellbore 206, flow into the tool 202, and stop in the appropriate ball seat (286) at the end of the taper mandrel 214. The landing of the ball may provide a seal within the tool 202 resulting in to blockage, which may result in a pressure drop across the tool 202. The ball seat may have a radius or curvature. The radius or curvature may be convex or concave in nature.

[0082] In other embodiments, the downhole tool 202 may be a check ball valve, with the tool 202 configured with the ball already in place when the tool 202 is lowered into the wellbore. The tool 202 can then act as a check valve and allow one-way flow. Fluid may be directed from the wellbore 206 into the formation 210 using any of these configurations.

[0083] Once the tool 202 has reached its intended position within the pipe, the setting mechanism or work string 212 may be detached from the tool 202 in a variety of ways, resulting in the tool 202 remaining insulated within the surrounding tubular member 208 and one or more sections ( e.g. , 213 ) wellbore 206. In one embodiment, after tool 202 is set, tension may be applied to setting tool (217) until a shear connection between tool 202 and work string 212 breaks. However, downhole tool 202 may have other forms of release. The amount of load applied to the setting tool and the shear joint may be in the range of about, for example, 20,000 lbf to 55,000 lbf.

[0084] In embodiments, the tension mandrel 216 may separate or detach from the lower sleeve 260 (directly or indirectly), whereby the workstring 212 may separate from the tool 202, which may occur at a predetermined moment. The loads shown in this document are not limiting and are provided as an example only. The setting force may be determined by the special design of the tool interfaces 202 and the corresponding tool face angles. The tool 202 may also have a predetermined break point (not shown) configured to fail, break, or otherwise break. For example, the lower sleeve 260 may be provided with a groove in communication with a shear joint or tongue, the groove being suitable for causing a tear in close proximity.

[0085] The operation of the downhole tool 202 may allow the tool 202 to be quickly run to isolate one or more sections of the wellbore 206, and to drill through or dissolve quickly and easily to break or retrieve the tool 202.

[0086] Accordingly, in some embodiments, through drilling may be completely unnecessary. Thus, the downhole tool 202 may have one or more components made from a reactive material such as metal or metal alloys. The downhole tool 202 may have one or more components made from a reactive material ( eg , soluble, degradable, etc.), which may be composite or metal based.

[0087] It follows that one or more of the components of the tool according to the embodiments disclosed herein may be made from reactive materials ( e.g. , materials suitable and known to dissolve, decompose, etc. in downhole environments [ including extreme pressure, temperature, fluid properties, etc.] after a short or limited period of time (preset or otherwise), as desired). In one embodiment, the reactive material component may begin to react within about 3 hours to about 48 hours after the downhole tool 202 is installed.

[0088] In embodiments, one or more of the components may be made from a metallic material, such as an aluminum-based or magnesium-based material. The metallic material may be reactive, eg soluble, that is, under certain conditions, the respective component(s) may begin to dissolve, and thus the need for through drilling is reduced. These conditions can be foreseen and thus predetermined. In embodiments, tool components 202 may be made from a soluble aluminum, magnesium, or aluminum-magnesium (or alloy, complex, etc.) material such as that supplied by Nanjing Highsur Composite Materials Technology Co. Ltd. or Terves, Inc.

[0089] One or more components of the tool 202 may be made from insoluble materials ( e.g. , materials suitable and able to withstand downhole conditions [including extreme pressure, temperature, fluid properties, etc.] for an extended period of time (preliminary specified or otherwise) as desired).

[0090] The downhole tool 202 (and other tool implementations disclosed herein) and/or one or more of its components may be 3D printed or manufactured using other forms of additive manufacturing.

[0091] Referring now to FIG. 2C-2E together, longitudinal cross-sectional side view a system having an uninstalled downhole tool, an installed downhole tool, and an installed downhole tool disconnected from the workstring, respectively, in accordance with embodiments of this disclosure. The insertion device(s) and components of the downhole tool 202 may be coupled to each other and may move axially and/or longitudinally at least partially relative to each other.

[0092] The downhole tool 202 may include a taper mandrel 214 extending through the tool 202 (or tool body). The taper mandrel 214 may be a solid body. In other aspects, the cone mandrel 214 may include a flow path or a channel 250 formed therein ( eg , an axial channel). The channel 250 may extend partially or for a short distance through the tapered mandrel 214. Alternatively, the channel 250 may extend through the entire mandrel 214 with an opening at its proximal end 248 and, conversely, at its distal end 246 (near the downhole end of the tool 202), as shown in FIG. 2E.

[0093] the Presence of the channel 250 or other flow through the cone mandrel 214 may be indirectly determined by the operating conditions. That is, in most cases, tool 202 can be large enough in diameter ( e.g. , 4-¾ inches) that channel 250 can be correspondingly large enough ( e.g. , 1-¼ inches) to allow debris and debris to pass or flow through channel 250. no blockage problems.

[0094] In the presence of the channel 250, the cone mandrel 214 may have an inner surface 247 of the channel, which may be smooth and annular in nature. In cross section, the channel surface 247 may be flat. In embodiments, the channel surface 247 (in cross section) may be parallel to the (central) axis 258 of the tool. The outer surface 230 of the mandrel may have one or more surfaces (in cross section) offset or inclined from the axis 258 of the tool.

[0095] The channel 250 (and therefore the tool 202) can be configured to fit a portion of the setting tool assembly 217, such as a tension mandrel 216. Thus, the tension mandrel 216, which may be considered part of the setting tool assembly 217, may be configured to place the downhole tool 202 (or components thereof) around it (eg, during descent). When assembled, the downhole tool 202 may be connected to the setting tool assembly 217 (and around the tension mandrel 216), but not in a threaded fashion. In an embodiment, the downhole tool 202 (by itself, not including setting tool components) may be completely devoid of threaded connections. If a 252 adapter is used, it may have a 256 thread. This 256 thread may match the 254 mounting sleeve thread.

[0096] As shown, the lower sleeve 260 may be provided with a shear point, such as a shear tongue 261. The shear tongue 261 may engage with the installation tool assembly 217. As shown, shear tab 261 may be engaged or adjacent to each of tension mandrel 216 and nose nut 224. installation time. Thus, the shear tongue 261 may have at least one recess or groove 262 for breaking (equivalent to the predetermined and targeted break point of the lower sleeve 260).

[0097] Groove 262 may be located circumferentially around tongue 261. In embodiments, recess region 262 may be V-shaped, or other shape or configuration suitable for tongue 261 to be released from lower sleeve 260. Shear tongue 261 may be configured with the ability to cut at a predetermined point. The shear tongue 261 may be located in the inner bore 264 of the lower sleeve and protrude (or extend) radially inwards around the circumference. There may be other recessed areas 263. During installation, as tension mandrel 216 continues to be pulled in direction A, nut 224 will continue to exert force on shear tab 261, eventually shearing off the tab. The shear tongue 261 may be configured to shear at a load greater than the load for mounting the tool 206.

[0098] The downhole tool 202 may be run into the wellbore (206) to a desired depth or position using a workstring 212, which may be provided with a setting tool assembly 217. The workstring 212 and mounting sleeve 254 may be part of a tool system 200 used to run the downhole tool 202 into the wellbore and activate the tool 202 to move from an uninstalled to a set position. The set position of the tool 202 ( see FIG. 2E) may include a sealing member 222 and/or a wedge 234 engaged with the tubular member 208. In one embodiment, the mounting sleeve 254 (which may be provided as part of the setting tool assembly) may be used to forcefully or forcefully (directly or indirectly) expand the sealing element 222 into a sealed engagement with the surrounding tubular element 208.

[0099] During descent, the annulus 290 around the tool 202 may be small or narrow enough that undesirable pressure (or drag) occurs in front of the tool 202. As such, the tool 202 (together with the setting tool assembly 217) can provide a fluid (pressure) bypass 221. As shown in FIG. 2C, well fluid Fw may enter the side port 245 (for the pin) of the slip 234 and then through the lower side port 249a of the tension mandrel 216. The fluid Fw may exit the tension mandrel 216 through the upper side port 249b and then out of the side port 257 mounting sleeve back into annulus 290.

[00100] The installation device(s) and components of the downhole tool 202 may be connected to the taper mandrel 214 and may move axially and/or longitudinally along it or in a working position with it. When the installation sequence begins, the lower sleeve 260 can be pulled through the tension mandrel 216 while the installation sleeve 254 remains stationary.

[00101] When the tension mandrel 216 is pulled in the direction of arrow A, one or more of the components located around the mandrel 214 between the distal end 246 and the proximal end 248 may begin to compress relative to each other, as a result, may begin to compress relative to each other, as a result of which the mounting sleeve 254 (or end 255) is held in place on the end face 215 of the support ring. This force and the resulting motion can cause the support ring 223 to slide under pressure over the top tapered surface 230 of the tapered mandrel 214 and eventually expand (together with the sealing member 222). Thus, the anvil ring 223 can be slidably engaged with the cone mandrel 214. Although not shown here, the anvil ring can be slidably, hermetically engaged with the cone mandrel, for example by means of one or more O-rings (which may be arranged in the O-ring groove on the back of the taper mandrel).

[00102] It will be appreciated by those skilled in the art that support ring 223 may be made from a material suitable to achieve the degree of elongation required to allow sealing member 222 located within ring 223 to be hermetically engaged with tubular member 208. The amount of elongation may be in range of elongation from about 5% to about 25% - without breaking - compared to the original ring size 223.

[00103] As the lower sleeve 260 is further pulled in the direction indicated by arrow A, the lower sleeve 260 (when engaged with the slip 234) can cause the wedge 234 to slide against the lower tapered surface 231 of the taper mandrel 214. Since it is desirable that the wedge ram 234 was destroyed, and the wedge ram 234 need not have a significant elongation. When failure occurs, wedge ram (or segments thereof) 234 can also move radially outward into engagement with surrounding tubular member 208.

[00104] The wedge ram 234 may have gripping elements such as rods, ball heads, inserts, and the like. In embodiments, the gripping elements may be serrated outer surfaces, or the teeth of the wedge(s) may be designed such that said surfaces prevent the corresponding wedge (or tool) from moving ( e.g. , axially or longitudinally) within the surrounding tubular member. 208, otherwise the tool 202 may unintentionally become loose or move from its position.

[00105] From the drawings it can be seen that the sealing element 222 (or the support ring 223) should not be in contact with the wedge ram 234. There may be a mandrel rib 229, which can further prevent such contact between the wedge ram 234 and the sealing element 222. On The figures further illustrate that the wedge 234 may be located proximate the first or distal end 246 of the cone mandrel 214, while the sealing member 222 may be proximate the second or proximal end 248 of the cone mandrel 214.

[00106] Because the sleeve 254 is rigidly held in place, the sleeve 254 may engage with the load-bearing end 215 of the support ring 223, which may result in at least partial load transfer through the rest of the tool 202. The mounting sleeve 254 may have a sleeve end 255 that abuts against end 215. However, ring 223 will press against tapered mandrel 214 as mandrel 214 is pulled out.

[00107] The same effect, albeit in the opposite direction, can be felt by the wedge ram 234. That is, the taper mandrel 214 may eventually reach a (nearly) stopping point, and the easiest degree of movement (and path of least resistance) is the wedge ram 234, pressed by the lower sleeve 260 against the lower tapered surface 231. As a result, the wedge ram 234 (or segments thereof) can break out and engage with the surrounding tubular element 208.

[00108] In the case of inserts ( eg , 378, Fig. 3A), one or more may have an edge or corner suitable to provide additional cutting into the surface of the tubular element. In an embodiment, any of the inserts may be made from mild steel, such as heat treated 1018 steel, or from other materials such as ceramic. Any insert can have a hole.

[00109] In an embodiment, the wedge ram 234 may be a single wedge ram, with the wedge ram 234 having at least a partial connection around its entire circumference. This means that although the wedge ram 234 itself may have one or more grooves (or undulations, notches, etc.) formed in it, the wedge ram 234 itself does not have a starting point of circumferential separation. In an embodiment, the grooves of the wedge ram may be equally spaced or located in it.

[00110] The tool 202 may be provided with a check ball valve assembly that includes a ball seat 286. The seat 286 may be removable or integral with it. In an embodiment, the channel 250 of the taper mandrel 214 may be provided with a ball seat 286 removably formed or located therein. In some embodiments, ball seat 286 may be integral with bore 250 of mandrel 214. In other embodiments, ball seat 286 may be mounted separately or optionally within mandrel 214 as desired.

[00111] The ball seat 286 can be configured such that the ball 285 can sit or rest in it, as a result of which the flow path through the cone mandrel 214 can be blocked ( for example , the flow through the channel 250 is limited or controlled by the presence of the ball). For example, fluid flow from one direction may force the ball against seat 286 and hold it, while fluid flow from the opposite direction may push or push the ball away from seat 286. Thus, the ball may be used to prevent or otherwise control fluid flow through tool 202. The ball can be made of composite material, phenolic resin, etc., so that the ball can withstand the maximum pressure that occurs during downhole operations ( eg hydraulic fracturing).

[00112] Although not limited, the ball diameter 285 may range from about 1 inch to about 5 inches. Channel 250 may have a bore inside diameter in the bore diameter range of about 1 inch to about 5 inches. Thus, the cone mandrel 214 may have a suitable wall thickness to withstand the load and prevent breakage.

[00113] The tool 202 may be configured as a drop-ball plug so that the drop-ball can flow towards the ball seat. The ball to be dropped can be much larger in diameter than the ball seat. In one embodiment, the end 248 may be provided with a seat 286 such that the ejectable ball can stop and seat in the seat 286 at the proximal end 248. If applicable, the ejectable ball 285 may be lowered into the wellbore and flow towards the seat 286 formed inside the tool 202.

[00114] The drop ball (or "frac ball") can be any type of ball that is obvious to one of ordinary skill in the art and suitable for use in the embodiments disclosed herein. Although the term "drop" ball or "frac" ball is used, any such ball may be a ball held in place or otherwise located within the downhole tool. The ball may be tied to the tool 202 (or any of its components). The tethered ball may be as provided in US Non-Provisional Patent Application Ser. No. 16/387,985 filed April 18, 2019

[00115] The ball may be a "smart" ball (not shown here) configured to monitor or measure downhole conditions and otherwise communicate information back to the surface or operator, such as the ball(s) provided by Aquanetus Technology, Inc. or OpenField Technology.

[00116] In other aspects, the ball 285 may be made of a composite material. In an embodiment, the composite material may be filament wrapped. Other materials are possible, such as glass or carbon fiber, phenolic material, plastics, fiberglass composite (sheets), plastics, etc.

[00117] The drop ball 285 may be made from a soluble material such as that disclosed in US Patent Application Ser. No. 15/784,020. The ball can be made or designed to dissolve under certain conditions or various parameters, including those related to temperature, pressure and composition.

[00118] Although not shown here, the downhole tool 202 may have a ring for pumping tools into the well or other suitable design to facilitate or improve running. Downhole tool 202 may have a "composite element" such as described in US patent No. 8,955,605.

[00119] In other aspects, tool 202 may be configured as a baffle plug that, once installed in the wellbore, can prevent or permit flow in any direction ( e.g. , up/down, etc.) through tool 202. Accordingly, one skilled in It should be appreciated in the art that the tool 202 of the present disclosure may be configured as a fracturing plug, a drop ball plug, a bridge plug, and so on. simply by using one of the many adapters or other optional components. In either configuration, after the tool 202 is properly set, the fluid pressure in the wellbore can be increased so that further well operations can begin, such as fracturing the target zone.

[00120] Tool 202 may include a rotation prevention assembly that includes a rotation prevention device or mechanism, which may be a spring, a composite tubular member with a mechanically preloaded spring, and so on. The device may be configured and suitable to prevent unwanted or unintentional movement or untwisting of tool 202 components.

[00121] The anti-rotation mechanism can provide additional safety for the tool and operators in that it can help prevent the tool from being inoperable in situations where the tool is inadvertently misused. For example, if the tool is used at the wrong temperature, the tool components can melt, causing the device and retaining ring to help keep the rest of the tool together. Thus, the device can prevent tool components from loosening and/or unscrewing, as well as preventing tool 202 from unscrewing or falling off the work string 212.

[00122] Very importantly, the downhole tool 202 may have an assembled and uninstalled length L1 of less than about 6 inches. In embodiments, the downhole tool 202 may have a length L1 in the range of about 3.5 inches to about 15 inches. As a result of the installation sequence, the installed downhole tool 202 may have an installed length L2 that is less than the length L1.

[00123] Referring now to FIG. 3A, 3B, and 3C together show an exploded isometric view, an assembled isometric view, and a longitudinal cross-sectional view, respectively, of a downhole tool in accordance with the embodiments disclosed herein.

[00124] The downhole tool 302 may be run, installed, and operated as described herein and in other embodiments (eg, system 200, etc.), as well as otherwise understood by one of ordinary skill in the art. The components of the downhole tool 302 may be placed and positioned around the taper mandrel 314 as described herein and in other embodiments, as well as understood by one of ordinary skill in the art. Thus, the downhole tool 302 may be comparable or identical in aspects, functions, operation, components, etc., to other tool embodiments disclosed herein. Similarities may not be discussed for brevity.

[00125] The operation of the downhole tool 302 may allow the tool 302 to be quickly run to isolate one or more sections of the wellbore, as provided herein. Drilling through the tool 302 can be assisted by one or more components and subcomponents of the tool 302 made from a drillable material that can be drilled significantly faster than conventional plugs and/or made from reactive materials that can facilitate drilling or even completely eliminate any such a need.

[00126] Downhole tool 302 may have one or more components, such as slip ram 334 and back-up ring 323, which may be made from the material described herein and in accordance with embodiments of this disclosure. Such materials may include a composite material such as a filament-wound material, a reactive material (metals or composites), and so on. The filament wound material may have advantages over other composite type materials and thus is desirable over injection molded materials and the like. Other materials for tool 302 (or any of its components) may include dissolving thermoplastics such as PGA, PLL, and PLA.

[00127] One skilled in the art will appreciate that in an assembled configuration (such as in FIG. 3B) and not connected to the insertion tool (217), one or more components of the tool 302 may be subject to release from the tool. Thus, one or more components may be bonded (eg, with adhesive) to another to enable the tool 302 to be held together without the presence of an installation tool. Any such bond need not be very strong. In embodiments, the components of the tool 302 may fit closely together.

[00128] The taper mandrel 314 may extend through the tool (or tool body) 302 in the sense that components may be positioned around it. Mandrel 314 may include a flow path or channel 350 defined therein ( e.g. , an axial channel) that may correspond to tool channel 302. Channel 350 may extend partially or for a short distance through mandrel 314. Alternatively, channel 350 may extend through the entire mandrel 314 with an opening at its proximal end 348 and, conversely, at its distal end 346. Channel 350 may be configured to accommodate an insertion tool (or component thereof, such as 216, FIG. 2D).

[00129] FIG. 3C illustrates in longitudinal section how the taper mandrel 314 may have a first outer tapered surface 330 and a second outer tapered surface 331 that may be generally flat. Thus, the first outer cone surface 330 and the second outer cone surface 331 may have respective reference planes P1, P2. The planes P1, P2 (and the outer surfaces 330, 331) can be offset from the long axis 358 of the tool 302 (or the respective longitudinal axes or reference planes 358 a,b) by an angle a1 and a2, respectively. That is, plane P1 may bisect long axis 358 (or axis 358a) at an angle a1, and plane P2 may bisect long axis 358 (or axis 358b). Angles a1 and a2 can be equal and opposite to the other. For example, the second angle a2 may be negative with respect to the first angle a1 ( e.g. +10 degrees for the first, -10 degrees for the second) and thus provide a "double" conical shape of the mandrel 314. One skilled in the art will appreciate that the perpendicular bisector 358 will be the corresponding perpendicular bisector for 358 a,b.

[00130] In embodiments, the angle a1 and/or a2 may be in the angle range of about 5 degrees to about 10 degrees. The angles of the taper mandrel surface(s) described herein may be negative compared to others, with one skilled in the art understanding that a positive or negative angle does not matter, but is instead based only on the base point. An angle can be an "absolute" angle, meaning that it refers to angles of the same magnitude in degrees and does not necessarily have a direction or orientation.

[00131] In embodiments, the angles a1 and a2 may be substantially equal (though opposite) to each other in the assembled or descent configuration. Thus, each of the angles a1 and a2 may be in the range of about 5 degrees to about 10 degrees with respect to the reference axis. At the same time, a1 and a2 can be equal to each other in value (within a tolerance of less than 0.5 degrees) at about 7.5 degrees. The angles a1 and a2 may be in the range of 5 degrees to 40 degrees and may be different from each other. For example, a1 might be around 8 degrees and a2 might be -20 degrees.

[00132] Where the surfaces 330, 331 converge, there may be a ridge 329. The ridge 329 may be the outermost center point of the taper mandrel 314. Thus, the wall thickness Tw may be at the widest (thickest) point on the ridge 329. Notably that the wall thickness may be smallest at the respective ends 346, 348. Thus, the wall thickness Tw at the ridge 329 may be greater than one or both of the wall thicknesses Tw at the ends 346, 348. The ridge 329 can effectively limit any possibility of unwanted extrusion.

[00133] The downhole tool 302 may include a sealing element 322 located within and/or around the back-up ring 323. The sealing element 322 may be made of an elastomer and/or a polymaterial such as rubber, solvent rubber, nitrile rubber, viton, or polyurethane. In an embodiment, the sealing element 622 may be made from an elastomeric material with a hardness of 75 to 80 Duro A.

[00134] The sealing element 322 can be configured to expand and elongate in the radial direction to provide a sealing engagement with the surrounding tubular element (208) when the tool components are compressed. Accordingly, the sealing element 322 may provide a fluid-tight seal of the sealing surface with respect to the tubular element.

[00135] The sealing member 322 may be positioned within the annular groove 323a of the back-up ring. The sealing element 322 may be molded or glued into the groove 323a. The sealing element 322 may not only function as a seal for the tool 302 (with respect to the tubular element) and/or with respect to the cone 314, but may also act as a pseudo-piston surface. This means that as the pressure over the tool increases, the pressure may further act on the sealing member 322 and push the back-up ring 323 further up the taper mandrel 314 and thus may increase or increase the sealing efficiency of the tool 302.

[00136] The downhole tool 302 may have a slip 334 located around (at least the end 346) of the taper mandrel 314. The slip 334 may be a solid slip, with the slip 334 having at least a partial connection around its entire circumference. This means that while the wedge 334 itself may have one or more grooves 344 formed therein, the wedge 334 need not be multi-segmented with at least one split point in a predetermined configuration.

[00137] The use of a rigid, one-piece or one-piece wedge ram configuration can reduce the pre-setting associated with conventional wedge ram rings, as conventional wedge rams are known to rotate and/or expand during running. As the chance of pre-setting decreases, faster descent times are possible. Similarly, in the embodiments herein, a multi-segment wedge ram can be used.

[00138] The slip 334 may include a tool for gripping the inner wall of the tubular, casing, and/or wellbore, such as a collection of gripping features including teeth or teeth, inserts 375, and so on. The gripping members may be positioned or configured such that the wedge ram 334 can engage with a tubular member (not shown) in such a way that movement ( eg , axial movement) of the wedge rams or tool after installation is prevented. In one embodiment, the inserts 375 may be cast with epoxy or molded into the corresponding insert channels or grooves 378 formed in the slip 334.

[00139] The slip 334 may have one or more grooves 344. The grooves 344 may be longitudinal in length from the first end 341 of the wedge to the other end 343 of the wedge. In an embodiment, the grooves 344 may be equally spaced or cut into the wedge ram 334. In other embodiments, the grooves 344 may have an alternating pattern (not shown here). That is, one groove may be closer to the wedge end 341 and an adjacent groove may be closer to the opposite end 343 of the wedge. One or more grooves 344 may extend completely through the wedge ram end 341 (not shown here) so that the wedge ram end 341 (alternatively end 343) may be free of material at a point. The wedge insert 334 may have an outer wedge face 388 and an inner wedge face 389.

[00140] The location or position of the grooves 344 of the wedge ram 334 can be customized. In one embodiment, the wedge insert 334 may be constructed with grooves 344 to distribute the radial load evenly along the wedge insert 334. One or more grooves 344 may extend near or substantially near the end(s) 341, 343 of the wedge insert, but leaving they have a small amount of material 342. Having a small amount of material between the ends of the segments can provide some rigidity to prevent a tendency to expand. There may be one or more grooves 344 that form a side opening through the entire body of the wedge ram. That is, any groove 344 may extend to a depth D from the outer surface 388 of the wedge ram to the inner surface 389 of the wedge ram. Depth D may define the lateral distance or length of how far material is removed from the wedge body relative to the wedge face 388 (or also wedge face 389). Depth D does not have to pass through wedge ram (body) 334.

[00141] Although not shown here, to facilitate fracture of the wedge ram 334, there may be a first or primary break point, which may be a groove, chip, or some other form of removal of material from the wedge ram. The first break point may be configured to break the wedge 334 at that point before breaking at any other point of the wedge 334. There may be from about two to about four primary break points. There may be a second or secondary break point, which may be determined or performed by the amount of material present. The first groove 344 may be associated with the first fracture point, and the second (or adjacent) groove may be associated with the second fracture point.

[00142] The first break point may be configured to break when the tool 302 is subjected to an installation load of about 1000 lbf to about 4000 lbf. The secondary break point may be configured to break when the tool 302 is subjected to a set load ranging from about 5,000 lbf to about 10,000 lbf.

[00143] The wedge ram 334 may be used to hold the tool 302 in place during the installation process by holding the potential energy of the compressed components in place. The slip 334 may also prevent movement of the tool as a result of fluid pressure on the tool. The wedge ram 334 may have an alternating pattern of grooves/windows around its body. For example, there may be a groove 344, then a window 345, followed by adjacent grooves 344 and windows 345, respectively. In longitudinal length, window 345 may be about less than or equal to groove 344.

[00144] The wedge 334 may be connected or engaged with the lower sleeve 360. The connection may be through one or more pins 359 located in the pin window 345 (wedge 334) and corresponding grooves 366 for the pins of the lower sleeve 360. Not limited to any particular shape, the pin holes 345 may be elongated oval, cylindrical, or elliptical. The enlarged pin window 345 may provide a certain amount of movement for the associated pin 359.

[00145] FIG. 2C and 2D illustrate the degree of movement of the pin (259) relative to the window (245) between the unset/deflated and set position of the instrument (202/302). The pin 359 may require a lateral length suitable for holding the sleeve 360 with the tool 302 during assembly/running as well as in the installed position. Although pressing the pin 359 into the pin groove 366 may be sufficient, the pin 359 may be bonded or bonded to the lower sleeve 360 to ensure that the pin 359 is held in place. In embodiments, the pin 359 may be screwed into the lower sleeve 360.

[00146] Referring now to FIG. 4A and 4B together show a longitudinal sectional side view of a downhole tool having a flap and a longitudinal sectional side view of the downhole tool shown in FIG. 4A with the flap open, respectively, in accordance with the embodiments disclosed herein.

[00147] The downhole tool 402 may be run, installed, and operated as described herein and in other embodiments (eg, system 200, etc.), as well as otherwise understood by one of ordinary skill in the art. The components of the downhole tool 402 may be placed and located around the taper mandrel 414 as described herein and in other embodiments, as well as understood by a person skilled in the art. Thus, the downhole tool 402 may be comparable or identical in aspects, functions, operation, components, etc., to other tool embodiments disclosed herein. Similarities may not be discussed for brevity. For example, the installation tool assembly 317 can be used with the tool 402, as will be apparent to those skilled in the art.

[00148] The downhole tool 402 may have a flap (or flap) 470. The flap 470 may be movable between an open position 473 and a closed position 472. The flap 470 may be movably (e.g., pivotable) connected to 414. The tool 402 may include a bias member/pin 471 for connecting the flap 470 to the cone mandrel 414. The bias member 471 may be configured to bias the flap 470 to a closed position 472.

[00149] During assembly or descent, the flap 470 may be held in the open position 473 by containing a portion of the insertion tool assembly ( eg , such as [part of] the tension mandrel). The flap 470 may be configured to rest on a seat 486 provided in a mandrel 414.

[00150] Those skilled in the art will appreciate that in the closed position 472, fluid flow may be blocked from one direction while fluid flow from another direction may open flap 470. Other configurations of flap 470 are possible, and tool 402 is not limited to the embodiments. shown in FIG. 4A and 4B.

Advantages.

[00151] Downhole tool embodiments are smaller, allowing the tool to be used in wells with smaller bore diameters. The smaller size also means less material cost per tool. Since insulating tools such as plugs are used in huge quantities and are generally not reusable, small tool savings result in huge annual capital cost savings.

[00152] When downhole trips cost about $30,000 - $40,000 per hour, the savings, measured in minutes (although repeatable to scale), make a big difference.

[00153] A synergistic effect is achieved as a smaller tool makes it easy to achieve faster drilling times. Again, even a small amount of through drilling time savings for a single tool results in huge annual savings.

[00154] Since the tool can be smaller (shorter), it can move along smaller radius bends in downhole tubulars without hovering and pre-setting. Passing through a shorter tool has less hydraulic resistance and therefore can provide higher fluid flow rates with a lower pressure drop. The tool can withstand a larger pressure surge (ball ejection) when the ball is seated.

[00155] While the preferred embodiments of this disclosure have been illustrated and described, various modifications may be made by one skilled in the art without departing from the spirit and spirit of this disclosure. The embodiments of the invention in this document are illustrative only and are not limiting. Many variations and modifications of this disclosure disclosed herein are possible and are within the scope of this disclosure. It should be understood that where numerical ranges or limitations are expressly stated, such defined ranges or limitations include a plurality of ranges or limitations that fall within said ranges or limitations. The use of the term "optional" in relation to any element of the claims means that the specified element is required or, alternatively, optional. Both options are within the scope of the claims. It should be understood that the use of broader terms such as contains, includes, has, etc. provides support for narrower terms such as consisting of, consisting essentially of, made essentially of, and the like.

[00156] Accordingly, the scope of protection is not limited to the description set forth above, but is limited only by the following claims, the scope of which includes all equivalents of the subject matter of the claims. All claims without exception are included in the description as embodiments of the present disclosure. Thus, the claims are a further description and are in 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 the present application. All patents, patent applications and publications cited in the present specification are incorporated herein by reference to the extent that they state the essentials; as well as illustrative, procedural, or other details in addition to those set forth herein.

Claims (72)

1. A downhole tool for isolating a wellbore for hydraulic fracturing, comprising: conical mandrel containing: the distal end, the proximal end, the outer surface and the inner flow channel, and the conical mandrel further comprises a ball seat formed in the inner flow channel, a support ring slidably engaged with the proximal end of the cone mandrel, the support ring further comprising an outer groove for the sealing element; a sealing element located in the outer groove for the sealing element; a wedge die engaged with the distal end; and the lower bushing connected to the wedge die, wherein the wedge ram contains at least one wedge ram groove, which forms a side hole in the wedge ram, which is determined by the depth that extends from the outer surface of the wedge ram to the inner surface of the wedge ram, wherein the outer surface comprises a first inclined surface and a second inclined surface, wherein the first inclined surface contains the first plane, which in cross section is intersected in half by the longitudinal axis at the first angle in the range from 5 to 10°, and while the second inclined surface contains a second plane, which in cross section is intersected in half by the longitudinal axis at an angle negative with respect to the first angle, wherein the first ramp and the second ramp converge at a ridge, and wherein the ridge has a ridge wall thickness greater than the wall thickness of the farthest distal end and the wall thickness of the proximal end. 2. Downhole tool according to claim. 1, characterized in that any component of the downhole tool is made of a soluble metal-based material. 3. Downhole tool according to claim. 2, characterized in that the support ring is made with the possibility of stretching from 10 to 20% compared to its original shape, and while the support ring is stretched without breaking. 4. The downhole tool according to claim. 1, characterized in that the inner flow channel of the cone mandrel contains an internal diameter in the range of the channel from at least 1 inch to no more than 5 inches, while the downhole tool contains a shear tongue, and at the same time the sealing element not attached to the cone. 5. Downhole tool according to claim. 4, characterized in that the support ring is made with the possibility of stretching from 10 to 20% compared to its original shape, and while the support ring is stretched without breaking. 6. Downhole tool according to claim. 1, characterized in that the downhole tool contains a shear tongue, while the sealing element is not engaged with a cone, while the longitudinal length of the downhole tool after installation is in the installation length range from at least 5 inches to no more than 15 inches. 7. A downhole tool for isolating a wellbore for hydraulic fracturing, comprising: conical mandrel containing: distal end, proximal end and outer surface, a support ring slidably engaged with the proximal end of the cone mandrel, the support ring further comprising an outer groove for the sealing member; a sealing element located in the outer groove for the sealing element; a wedge die engaged with the distal end; and the lower bushing connected to the wedge die, wherein the wedge ram contains at least one wedge ram groove, which forms a side hole in the wedge ram, which is determined by the depth that extends from the outer surface of the wedge ram to the inner surface of the wedge ram, wherein the outer surface comprises the first inclined surface and the second inclined surface, wherein the first inclined surface contains the first plane, which in cross section is intersected in half by the longitudinal axis at the first angle in the range from 5 to 10°, while the second inclined surface contains the second plane, which in cross section is bisected by the longitudinal axis at an angle negative with respect to the first angle, wherein any component of the downhole tool is made of a soluble metal-based material, the downhole tool includes a shear tongue, the sealing element is not cone-engaged, and the longitudinal length of the downhole tool after installation is in the installation length range from at least 5 inches to no more than 15 inches. 8. Downhole tool according to claim. 7, characterized in that the support ring is made with the possibility of stretching from 10 to 20% compared to its original shape. 9. Downhole tool according to claim 8, characterized in that the support ring is stretched without breaking. 10. Downhole tool according to claim. 7, characterized in that the support ring is stretched without breaking. 11. A downhole system for installing a downhole tool for isolating a wellbore for hydraulic fracturing, comprising: working column; a setting tool assembly connected to the workstring, the setting tool assembly further comprising: a tension mandrel comprising a first end of the tension mandrel and a second end of the tension mandrel; and mounting sleeve; downhole tool, comprising: conical mandrel containing: a distal end, a proximal end, an outer surface, and an inner flow channel, the conical mandrel further comprising a ball seat formed in the inner flow channel; a support ring slidably engaged with the proximal end, the support ring further comprising an outer groove for the sealing element; a sealing element located in the outer groove for the sealing element; a wedge die engaged with the distal end; and the lower bushing connected to the wedge die, wherein the tension mandrel passes through the downhole tool, wherein the nose nut is engaged with each of the second end of the tension mandrel and the downhole tool, wherein the outer surface comprises a first inclined surface and a second inclined surface, wherein the first inclined surface contains the first plane, which in cross section is intersected in half by the longitudinal axis, while the second inclined surface contains a second plane, which in cross section is intersected in half by the longitudinal axis at an angle negative with respect to the first angle, wherein the first ramp and the second ramp converge at a ridge, and wherein the ridge has a ridge wall thickness greater than the wall thickness of the farthest distal end and the wall thickness of the proximal end. 12. Downhole system according to claim. 11, characterized in that the wedge ram contains at least one wedge ram groove, which forms a side hole in the wedge ram, which is defined by the first part of the wedge ram material at the first end of the wedge ram, the second part of the wedge ram material at the second end of the wedge ram and a depth that extends from the outer surface of the wedge ram to the inner surface of the wedge ram. 13. Downhole system according to claim. 12, characterized in that the wedge ram contains at least one hole for the pin adjacent to at least one groove of the wedge ram, while the lower sleeve contains a groove for the pin near at least one hole for the pin , and wherein the pin is located within each of at least one pin hole in the wedge die and at least one pin groove of the lower bushing. 14. Downhole system according to claim. 13, characterized in that any component of the downhole tool is made of a soluble metal-based material. 15. Downhole system according to claim. 14, characterized in that the support ring is made with the possibility of stretching from 10 to 20% compared to its original shape, and while the support ring is stretched without breaking. 16. Downhole system according to claim 15, characterized in that the lower sleeve contains a shear tongue, while the sealing element is not engaged with a cone, while the longitudinal length of the downhole tool after installation is in the installation length range from at least 5 inches to no more than 15 inches. 17. A downhole system for installing a downhole tool for isolating a wellbore for hydraulic fracturing, comprising: working column; a setting tool assembly connected to the workstring, the setting tool assembly further comprising: a tension mandrel comprising a first end of the tension mandrel and a second end of the tension mandrel; and mounting sleeve; downhole tool, comprising: conical mandrel containing: distal end, proximal end and outer surface, a support ring slidably engaged with the proximal end, the support ring further comprising an outer groove for the sealing element; a sealing element located in the outer groove for the sealing element; a wedge die engaged with the distal end; and the lower bushing connected to the wedge die, any downhole tool component is made of a soluble metal-based material, wherein the tension mandrel passes through the downhole tool, wherein the nose nut is engaged with each of the second end of the tension mandrel and the downhole tool, wherein the outer surface comprises a first inclined surface and a second inclined surface, wherein the first inclined surface comprises a first plane, which is transversely cross section is bisected by the longitudinal axis at a first angle in the range from 5 to 10°, and the second inclined surface contains a second plane, which in cross section is bisected by the longitudinal axis at an angle negative with respect to the first angle, wherein the downhole tool includes a shear tongue, the sealing element is not engaged by the cone, and the longitudinal length of the downhole tool after installation is in the installation length range from at least 5 inches to no more than 15 inches. 18. Downhole system according to claim 17, characterized in that the wedge ram contains at least one wedge ram groove, which forms a side hole in the wedge ram, which is defined by the first part of the wedge ram material at the first end of the wedge ram and the depth that extends from outer surface of the wedge ram to the inner surface of the wedge ram. 19. Downhole system according to claim 18, characterized in that the support ring is made with the possibility of stretching from 10 to 20% compared to its original shape, and at the same time the support ring is stretched without breaking. 20. Downhole system according to claim 19, characterized in that the conical mandrel further comprises a ball seat formed in the internal flow channel.

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