Patent Application
20250043655
Not applicable.
This disclosure generally relates to downhole tools or devices and related systems and methods used in oil and gas wellbores. More specifically, the disclosure relates to a downhole system and tool(s) or devices that may be run into a wellbore and useable for wellbore isolation, and methods pertaining to the same. In particular embodiments, the disclosure presents a system and method (and related device(s), tool(s), etc.) for stimulating a formation in one or more stages while providing an operator with flexibility in the stages that are to be stimulated or isolated from stimulation. In still other embodiments, a single plugging device may be used to activate one or more frac sleeves.
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 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. One form of a frac operation may be a ‘plug and perf’ type, such as described or otherwise disclosed in U.S. Pat. No. 8,955,605, incorporated by reference herein in its entirety for all purposes.
In this type of operation, the tubestring does not have any openings through its sidewalls; instead, perforations are created by so-called perforation guns which discharge shaped charges through the tubestring and, if present, adjacent cement. The zone near the perf is then hydraulicly fractured, followed by the setting of a new plug, re-perf, etc. That process is repeated until all zones in the well are fractured.
The plug and perf method is widely practiced, but it has a primary drawback of being time consuming. Other problems include: plug defects (such as slippage, presets, hang ups, and drillout issues), perf erosion, wireline and drillout crew resource requirements, and the plug run times associated with wireline, especially during single well operations.
Multistage fracturing is another form of frac operation that also enjoys popularity. In this type of frac operation, multi-stage wells require the stimulation and production of one or more zones of a formation. Conventionally, a liner, casing, or other type of tubestring is downhole, in which the tubestring includes one or more downhole frac valves (any may further include, but not be limited to, ported sleeves or collars) at spaced intervals along the wellbore.
Such frac valves typically include a cylindrical housing that may be threaded into and forms a part of the tubestring. The housing defines a flowbore through which fluids may flow. Ports are provided in the housing (e.g., sidewall) that may be opened by actuating a sliding sleeve. Once opened, fluids are able to flow through the ports and fracture the formation in the vicinity of the valve, and vice versa.
The location of the frac valves is commonly set to align with the formation zones to be stimulated or produced. The valves must be manipulated in order to be opened or closed as required. In the case of multistage fracking, multiple frac valves are used in a sequential order to frac sections of the formation, typically starting at a toe end of the wellbore and moving progressively towards a heel end of the wellbore. It is crucial that the frac valves be triggered to open in the desired order, and also that they do not open earlier than desired.
By way of example,
The wellbore 106 may be serviced by a derrick 103 and various other surface equipment (not shown). The wellbore 106 may be provided with a casing string 105, which may be part of tubular 104. The tubular 104 may include or be coupled with the casing string 105 via a hanger 101. It will be noted that part of the wellbore 106, and part of the wellbore may be generally horizontal. The tubular 104 may be cemented in place via cement 107.
A typical frac operation will generally proceed from the lowermost zone in the wellbore (sometimes the ‘toe’) to the uppermost zone (sometimes the ‘heel’).
In some instances (not viewable here), the tubular 104 is arranged with valves having seats of increasing inside diameter progressing from toe to heel. The valves are manipulated by pumping multiple plug devices, such as balls, plugs or darts, each having sequentially increasing outside diameters, down the tubestring. The first plug, having the smallest outside diameter passes through all frac valves until it seats on the first (or furthermost) valve seat, having the smallest inside diameter.
When a plug lands on a respective seat, fluid pressure uphole of the plug urges the plug downhole, which causes it to induce analogous movement of a sleeve of the valve downhole, which exposes the ports of the frac valve. In this arrangement, each valve must be uniquely built with a specific seat size and must be arranged on the tubestring in a specific order. Additionally, a stock of plug devices of all sizes of diameter must always be maintained to be able to manipulate all of the unique valve seats.
In other cases, opening of the frac valve is achieved by running a bottom hole assembly, also known as an intervention tool, down on a workstring through the tubestring, locating in the frac valves to be manipulated and manipulating the valve by any number of means including use of mechanical force on the intervention tool, or by hydraulic pressure. However, the use of an intervention tool is not always desirable; the workstring on which the intervention tool is run presents a flow restriction within the tubestring and prevents the full-bore fluid flow required within the tubestring to achieve the needed stimulation pressure.
Despite popularity, multistage fracturing with frac valves has its own share of problems. Sleeve design problems include: limited number of stages per well, the need for coiled tubing in the hole during operations, and the need for drilling out seats post operations. Many conventional systems utilize a ball drop process that requires a high amount of precision not always achievable. Modern designs that attempt to solve these issues are overly complex, and require a wide array of varied tools (which corresponds to high manufacture costs).
A need exists for simple but robust system in which one or more frac valves (one or more of which may be identical) may be run or disposed downhole, and may be opened in any sequence by a single device.
There is a need for a frac valve system that does not require the use of an intervention tool or of unique frac valves and dedicated balls or plugs. There is a need for a system that may be operable to open one or more frac valves in any order desired, and may provide for repeated opening and closing one or more frac valves within a tubestring for varying purposes.
There are needs in the art for 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 contain less materials, less parts, have reduced or eliminated removal time, and are easier to deploy, even in the presence of extreme wellbore conditions. The ability to save cost on materials and/or operational time (and those saving operational costs) leads to considerable competition in the marketplace. Achieving any ability to save time, or ultimately cost, leads to an immediate competitive advantage.
Embodiments of the disclosure pertain to a downhole system for stimulating one or more stages of a downhole wellbore. The system may include one or more frac valves arranged on a tubular; any of such frac valves presenting a comparable or identical inside profile to another, and any of which may be openable for providing fluid communication between internal and external of the tubular.
Further embodiments pertain to an at least one dart or plugging device that may be deployable into a tubular, and operably configured to pass through one or more frac valves without opening one or more frac valves, and yet may be able to engage and open one or more other frac valves.
Other embodiments of the disclosure pertain to a system for stimulating a subterranean formation that may include a wellbore formed within the subterranean formation; and a tubular disposed within the wellbore.
The plugging device may have a plug body. The plug body may have a distal end, a proximate end, and an outer surface.
The plugging device may not open any valves of one or more initial cluster of valves, but opens every valve of a subsequent cluster of valves.
One or more valves of any cluster of valves may include a flex valve. Any flex valve may include a respective flex sleeve. The flex sleeve may be configured with rigid portion and/or a flexible portion. The flexible portion may include a plurality of fingers. In aspects, the plugging may not be able to engage the plurality of fingers unless it is in the plugging position (or set configuration).
The outer surface of the plugging device may include an outermost ridge or rib suitable to engage the valve when in the set configuration.
One or more valves of any cluster of valves may be a frac valve comprising a respective solid sleeve. The solid sleeve may be configured with an inner sleeve shoulder. Any cluster of valves may have a single frac valve. In certain aspects, there may not be ‘clusters’, and instead, the tubular may have one or more frac valves disposed therein. This may coincide with the lack of any flex valves.
Embodiments herein may utilize a plugging device that includes a cone or cone mandrel, and an expansion sleeve slidingly engaged with the conc.
There may be a lower sleeve, such as proximate with the expansion sleeve. The plugging device may have a run-in (or unset) and set configuration. The run-in configuration may have the cone not engaged with the lower sleeve. In the set configuration, the cone may be engaged with the lower sleeve. In aspects, setting of the plugging device to the set configuration may result in expansion of the expansion sleeve, but the plugging remains free to move or be moved to engage a profile or profile sub of a surrounding tubular in the wellbore.
In the set configuration the plugging device may result in establishing a plug in support of a fracturing operation once a ball is seated in the cone.
The profile or profile sub of any embodiment may include that of a frac valve and/or a flex valve. For example, a shoulder or other type of surface. The profile or profile sub of any embodiment may have an inner diameter larger or smaller than the surrounding tubular.
Other embodiments of the disclosure pertain to a downhole setting system for use in a wellbore that may include a workstring; and a setting tool assembly coupled to the workstring. The setting tool assembly may include any of: a tension mandrel comprising a first tension mandrel end and a second tension mandrel end; and a setting sleeve. In aspects, the tension mandrel may be disposed through the plugging device.
Yet other embodiments of the disclosure pertain to a downhole system for multistage fracturing a subterranean formation that may include a first valve or a first cluster of valves. There may be a plugging device according to embodiments herein.
The system may include the plugging device set to a set configuration before entering the first cluster of valves. The first cluster of valves may include a flex valve that may have a flex sleeve configured with a rigid portion and/or a flexible portion. The plugging device need not engage the plurality of fingers unless it is in the set configuration. The first cluster of valves may include a frac valve comprising a solid sleeve configured with an inner sleeve shoulder.
These and other embodiments, features and advantages will be apparent in the following detailed description and drawings.
A full understanding of embodiments disclosed herein is obtained from the detailed description of the disclosure presented herein below, and the accompanying drawings, which are given by way of illustration only and are not intended to be limitative of the present embodiments, and wherein:
Herein disclosed are novel apparatuses, assemblies, systems, and methods that pertain to and are usable for wellbore operations, and aspects (including components) related thereto, the 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, unless expressly indicated otherwise.
Connection(s), couplings, or other forms of contact between parts, components, and so forth may include conventional items, such as lubricant, additional sealing materials, such as a gasket between flanges, PTFE between threads, and the like. The make and manufacture of any particular component, subcomponent, etc., may be as would be apparent to one of skill in the art, such as molding, forming, press extrusion, machining, or additive manufacturing. Embodiments of the disclosure provide for one or more components that may be new, used, and/or retrofitted.
Various equipment may be in fluid communication directly or indirectly with other equipment. Fluid communication may occur via one or more transfer lines and respective connectors, couplings, valving, and so forth. Fluid movers, such as pumps, may be utilized as would be apparent to one of skill in the art.
Numerical ranges in this disclosure may be approximate, and thus may include values outside of the range unless otherwise indicated. Numerical ranges include all values from and including the expressed lower and the upper values, in increments of smaller units. As an example, if a compositional, physical or other property, such as, for example, molecular weight, viscosity, temperature, pressure, distance, melt index, etc., is from 100 to 1,000, it is intended that all individual values, such as 100, 101, 102, etc., and sub ranges, such as 100 to 144, 155 to 170, 197 to 200, etc., are expressly enumerated. It is intended that decimals or fractions thereof be included. For ranges containing values which are less than one or containing fractional numbers greater than one (e.g., 1.1, 1.5, etc.), smaller units may be considered to be 0.0001, 0.001, 0.01, 0.1, etc. as appropriate. These are only examples of what is specifically intended, and all possible combinations of numerical values between the lowest value and the highest value enumerated, are to be considered to be expressly stated in this disclosure. Others may be implied or inferred.
Embodiments herein may be described at the macro level, especially from an ornamental or visual appearance. Thus, a dimension, such as length, may be described as having a certain numerical unit, albeit with or without attribution of a particular significant figure. One of skill in the art would appreciate that the dimension of “2 centimeters” may not be exactly 2 centimeters, and that at the micro-level may deviate. Similarly, reference to a “uniform” dimension, such as thickness, need not refer to completely, exactly uniform. Thus, a uniform or equal thickness of “1 millimeter” may have discernable variation at the micro-level within a certain tolerance (e.g., 0.001 millimeter) related to imprecision in measuring and fabrication.
The term “connected” as used herein may refer to a connection between a respective component (or subcomponent) and another component (or another subcomponent), which can be fixed, movable, direct, indirect, and analogous to engaged, coupled, disposed, etc., and can be by screw, nut/bolt, weld, and so forth. Any use of any form of the terms “connect”, “engage”, “couple”, “attach”, “mount”, etc. or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described.
The term “fluid” as used herein may refer to a liquid, gas, slurry, multi-phase, etc. and is not limited to any particular type of fluid such as hydrocarbons.
The term “fluid connection”, “fluid communication,” “fluidly communicable,” and the like, as used herein may refer to two or more components, systems, etc. being coupled whereby fluid from one may flow or otherwise be transferrable to the other. The coupling may be direct or indirect. For example, valves, flow meters, pumps, mixing tanks, holding tanks, tubulars, separation systems, and the like may be disposed between two or more components that are in fluid communication.
The term “pipe”, “conduit”, “line”, “tubular”, or the like as used herein may refer to any fluid transmission means, and may be tubular in nature.
The term “tubestring” or the like as used herein may refer to a tubular (or other shape) that may be run into a wellbore. The tubestring may be casing, a liner, production tubing, combinations, and so forth. A tubestring may be multiple pipes (and the like) coupled together.
The term “workstring” as used herein may refer to a tubular (or other shape) that is operable to provide some kind of action, such as drilling, running a tool, or any other kind of downhole action, and combinations thereof. In some instances, the workstring may be further defined, such as being void of any type of perforating device or electrical current conveyance (sometimes “slickline). Pump down devices are not necessary, as the device may be run in via workstring, such as a slickline. This means there may be a workstring without perforating guns. Embodiments may use a workstring that is a wireline and/or braided lines (with or without perforating guns).
The term “frac operation” as used herein may refer to fractionation of a downhole well that has already been drilled. ‘Frac operation’ can also be referred to and interchangeable with the terms fractionation, hydrofracturing, hydrofracking, fracking, fracing, frack, frac, etc. A frac operation can be land or water based. The frac operation may be further defined, such as being void of using perforations or a perforating gun.
The term “mounted” as used herein may refer to a connection between a respective component (or subcomponent) and another component (or another subcomponent), which can be fixed, movable, direct, indirect, and analogous to engaged, coupled, disposed, etc., and can be by screw, nut/bolt, weld, and so forth.
The term “machined” can refer to a computer numerical control (CNC) process whereby a robot or machinist runs computer-operated equipment to create machine parts, tools and the like.
The term “parallel” as used herein may refer to any surface or shape that may have a reference plane lying in the same direction or vector as that of another. It should be understood that parallel need not refer to exact mathematical precision, but instead be contemplated as visual appearance to the naked eye.
The term “cluster of valves” as used herein may refer to a grouping of at least one flex sleeve valve in proximity or association with a solid sleeve valve. For example, there may be a cluster of valves that includes a solid sleeve valve and a number of flex sleeve valves in a range of about one flex sleeve valve to about one hundred flex sleeve valves.
The term “stage” as used herein may refer to consideration of at least one fracturing job associated with an area of a zone or formation proximate a (armed or set) plugging device landed or seated in a solid sleeve valve.
The term “zone” as used herein may refer to an area of interest in a subterranean formation.
The term “reactive material” as used herein may refer a material with a composition of matter having properties and/or characteristics that result in the material responding to a change over time and/or under certain conditions. The term reactive material may encompass degradable, dissolvable, disassociatable, dissociable, and so on.
The term “degradable material” as used herein may refer to a composition of matter having properties and/or characteristics that, while subject to change over time and/or under certain conditions, lead to a change in the integrity of the material. As one example, the material may initially be hard, rigid, and strong at ambient or surface conditions, but over time (such as within about 12-36 hours) and under certain conditions (such as wellbore conditions), the material softens.
The term “dissolvable material” may be analogous to degradable material. The term as used herein may refer to a composition of matter having properties and/or characteristics that, while subject to change over time and/or under certain conditions, lead to a change in the integrity of the material, including to the point of degrading, or partial or complete dissolution. As one example, the material may initially be hard, rigid, and strong at ambient or surface conditions, but over time (such as within about 12-36 hours) and under certain conditions (such as wellbore conditions), the material softens. As another example, the material may initially be hard, rigid, and strong at ambient or surface conditions, but over time (such as within about 12-36 hours) and under certain conditions (such as wellbore conditions), the material dissolves at least partially, and may dissolve completely. The material may dissolve via one or more mechanisms, such as oxidation, reduction, deterioration, go into solution, or otherwise lose sufficient mass and structural integrity.
The term “breakable material” as used herein may refer to a composition of matter having properties and/or characteristics that, while subject to change over time and/or under certain conditions, lead to brittleness. As one example, the material may be hard, rigid, and strong at ambient or surface conditions, but over time and under certain conditions, becomes brittle. The breakable material may experience breakage into multiple pieces, but not necessarily dissolution.
For some embodiments, a material of construction may include a composition of matter designed or otherwise having the inherent characteristic to react or change integrity or other physical attribute when exposed to certain wellbore conditions, such as a change in time, temperature, water, heat, pressure, solution, combinations thereof, etc. Heat may be present due to the temperature increase attributed to the natural temperature gradient of the earth, and water may already be present in existing wellbore fluids. The change in integrity may occur in a predetermined time period, which may vary from several minutes to several weeks. In aspects, the time period may be about 12 to about 36 hours.
The term “machined” can refer to a computer numerical control (CNC) process whereby a robot or machinist runs computer-operated equipment to create machine parts, tools and the like.
Referring now to
The wellbore 206 may be an open hole, a cased hole, or a hybrid thereof, with a portion cased and a portion open. The wellbore 206 may be vertical, horizontal, deviated or of any orientation. Embodiments herein may pertain to offshore or onshore operations. The wellbore 206 may be serviced by a derrick 203 and various other surface equipment (pumps, production string, drill string, etc.—not shown).
Components of system 200 may be operable separately or together to provide fluid communication between an inside 212 of the tubular 204 and outside thereof, such as to an annulus 215 or to a surrounding surface 210. The surrounding surface 210 may be (at least a portion of) a subterranean formation.
One or more frac valves 202 may be installed at any point along a length L of the tubular 204. Frac valves 202 may be installed onto or otherwise with the tubular 204, and along the length L at strategic of predetermined points. As the tubular 204 is disposed within the wellbore 206, sections of the tubular 204 may be coupled together, such as when stands of pipe have box and pin ends that are engaged. Valves 202 may be installed between joints of the tubular 204. A lower toe valve 216 may be placed near the lower, or toe end 204a of the tubular 204. Any (frac) valve 202 along the length L of the tubular 204 may be contemplated as a restriction sub, in that there is a restricted or reduced diameter associated therewith. The restriction sub may be configured to receive and seat a plugging device 214.
A plugging device 214 may be used to shift a sleeve of the frac valve 202 from a first position to a second position. The first position may have ports of the valve closed by the sleeve, and a second position may have ports of the valve opened as the sleeve is shifted. A ball 217 may be used with or be part of the plugging device 214. In embodiments the plugging device 214 may be a dart or other form of downhole tool, which may be configured with a ball seat for the ball 217 to seat thereon. The plugging device 214 may have one or more dissolvable components. The plugging device 214 may be deployed via workstring in a run-in configuration. Prior to engaging a target surface (such as a shoulder or profile), the plugging device 214 may be moved from the run-in configuration to a set configuration. In the set configuration, the plugging device 214 may be disconnected from the workstring. The workstring may be void of perforating devices.
Embodiments herein may entail use of two main components. The aforementioned plugging device 214 and frac valve 202. Alas, various types and configurations of the plugging device 214 and frac valve 202 may be utilized. For example, there may be a first configuration of a frac valve 202 having a solid sleeve. There may be a second configuration of a frac valve 202a having a flex sleeve (or collet sleeve). To provide the reader with case in distinguishing, the first configuration may simply be referred to as frac valve, whereas the second configuration may be referred to as a ‘flex valve’ (or ‘flex frac valve’, ‘flex sleeve valve, and the like).
The plugging device 214 may be configured to engage either type or both of the frac valve 202 and the flex valve 202a. A plurality of valves 202, 202a may be referred to as a ‘cluster’ of valves (or ‘valve cluster’). The plugging device 214 may be configured to engage and open a frac valve 202, and also engage and open a flex valve 202a. A valve cluster may include at least one frac valve and one flex valve. There may be a plurality of valve clusters. The number of clusters may coincide to the number of stages for completion. For example, if desired to fracture one stage, one cluster of valves may be utilized.
In embodiments, there may be a first frac valve fluster having a first frac valve and first flex valve, and a second valve cluster having a second frac valve and a second flex valve. The plugging device may be configured to engage, but not open the first frac valve, pass through the first flex valve, and engage and open the second frac valve. Other valves 202, 202a may be therebetween.
The plurality of valves 202, 202a may be installed on, and/or as part of, the tubular 204, and spaced apart as desired or otherwise mentioned herein. The plugging device 214 may be deployed into the tubular 204, and run down (such as via pumping, workstring, or combinations thereof) therein towards the valves 202, 202a. Although one or more plugging devices 214 may be utilized, it is within the scope of the disclosure that embodiments herein need only utilize a single plugging device 214 to open multiple valves. The number of plugging devices 214 desired or used may relate to the number of stages of the formation 210 to be stimulated. For example, a first plugging device may be used to open all the valves 202, 202a of a first or lower cluster, while a second plugging device may be used to open all the valves 202, 202a of a second or upper cluster.
The valves of any cluster need not be identical. With that said, valves 202, 202a may have identical (within high tolerance) diameter seat sizes. The frac valves 202 do not need to be installed in any particular order. However, it is within the scope of the disclosure that two or more valves 202, 202a may have similar or identical: (within reasonable machine tolerance) end connections (fittings), outside diameter (O.D.), and inside profile. The frac valve 202 may have a valve sleeve (or seat) of the same profile as any other frac valve 202. The sleeve may be shiftable sleeve to expose ports in order to facilitate or allow for fluid communication between an inside of the valve 202 (or tubular 204) and formation 210 surrounding it.
The opening pressure required to shift the sleeve may be adjustable via adjustment or configuration of one or more retainer members. The retainer member may be configured to hold the sleeve in an initial or first closed position. In aspects, any valve 202, 202a may be configured with the same opening pressure or force requirement to shift a respective sleeve.
Any cluster of valves may include at least one solid sleeve valve and one or more flex sleeve valves.
Referring now to
The frac valve 302 may have a main valve body 320. The frac valve 302 may include one or more end fittings 321a and 321b (such as shown on 3B), which may be on either or each end of the main body 320. As such, the end fittings 321a, 321b may be integral with the main body 320, or be coupled therewith, such as threadingly, via the use of one or more respective securing members 322 (e.g., pins, set screws, or the like), or combinations thereof. The use of separate end fittings 321a, 321b may allow for case of manufacture of the main body 320, and at the same time allow for the frac valve 302 to be configured for coupling with varied joints. The end fittings 321a, 321b may be configured for coupling respective ends (e.g., one for box end, other for pin end, etc.) of the tubular (204) joints. As mentioned, the frac valve 302 may be contemplated as a restriction sub.
The main body 320 may have an inner bore 325, which may be at least partially open through an entire body length of the valve 302. There may be a valve sleeve (or seat) 324 disposed therein. The valve sleeve 324 may be shiftable. The valve sleeve 324 may be shiftable from a first position to a second position. The first position of the sleeve 324 may be where the ports 323 are closed (e.g., blocked) by the sleeve 324. The second position of the sleeve 324 may be any position thereof whereby the sleeve 324 no longer blocks, at least partially, the ports 323. The second position may include or be related to the breakage at least one retainer member 326. The second position of the sleeve 324 may be a fully open position, which may coincide with the ports 323 being completely unblocked. The second position may include a bias member 328 expanded into a receptacle 329.
The first position may correspond to a lack of communication between the bore 325 and the external side of the valve 302. The second position may correspond to the ability to have fluid communication between the bore 325 and the external side of the valve 302.
The valve sleeve 324 may be held temporarily in place in the first position via one or more retainer members 326. The main body 320 may have a retainer member receptable 327 for the respective member 326 to engage therewith. The retainer member 326 may be a shear screw, pin, etc. As such, the amount of force needed to move the valve sleeve 324 may be predetermined. Once the member(s) 326 breaks, the valve sleeve 324 may freely move. The valve sleeve 324 may also be sealingly engaged with the main body 320 via one or more seals, o-rings, etc. 330.
The valve sleeve 324 may sealingly and slidingly move downward until a sleeve groove 331 may be laterally proximate a main body receptacle 329. The sleeve groove 331 may be circumferential around the outside surface of the sleeve 324. In a comparable manner, the main body receptacle 329 may be circumferential around the inside surface of the main body 320. A biased member, such as a snap ring, 328 may be disposed within the sleeve groove 331. As one of skill would appreciate, as the groove 331 and the receptacle 329 align, the bias member 328 may expand outward, which may then provide an added shoulder or stop for the sleeve 324. The expansion of the bias member 328 into the receptacle 329 may help keep the valve sleeve 324 in place without any further sliding upward or downward.
The sleeve 324 may have an inner sleeve surface 332, which may be defined by a continuous sleeve inner diameter D1. The inner sleeve surface 332 may have an annular sleeve shoulder (or rib, protrusion, catch, seat, restriction, profile, etc.) 333, which may be defined with an inner (most) shoulder having a diameter D2. In embodiments, D1 may be greater than D2. The sleeve shoulder 333 may be configured for part of a plugging device (e.g., 214) to engage therewith. In the event the sleeve 324 is shifted, the plugging device may be configured to disengage with the shoulder 333, such as from at least partially dissolving.
An upper end of the inner sleeve surface 332 may form a sleeve seal shoulder 334. The plugging device may also be configured to engage the sleeve seal shoulder 334.
Referring now to
By way of comparing
The flex valve 402a may be run, positioned, and opened as described herein and in other embodiments (such as in system 200, and so forth), and as otherwise understood to one of skill in the art. The flex valve 402a may be comparable or identical in aspects, function, operation, components, etc. as that of other valve embodiments disclosed herein. Similarities may not be discussed for the sake of brevity. The flex valve 402a may be part of a valve-plugging device assembly.
For the sake of case to the reader, components of the flex valve 402a may be described in a manner comparable to that of the frac valve 302. As such, the flex valve 402a may have a main flex valve body 420. The flex valve 402 may include one or more end fittings 421a (or comparable to 321b on
The main body 420 may have an inner flex bore 425, which may be at least partially open through an entire body length of the valve 402a. There may be a flex valve sleeve (or seat) 424 disposed therein. The flex valve sleeve 424 may have a rigid portion 437 and a flex portion 438, the flex portion 438 essentially a plurality of fingers 440 (with respective slots 441 therebetween) that may be flexible. As shown in
The flex valve sleeve 424 may be shiftable. The valve sleeve 424 may be shiftable from a first position shown in
The first position may correspond to a lack of communication between the bore 425 and the external side of the flex valve 402a. The second position may correspond to the ability to have fluid communication between the bore 425 and the external side of the flex valve 402a.
The flex valve sleeve 424 may be held temporarily in place in the first position via one or more retainer members 426. The main body 420 may have a retainer member receptable 427 for the respective member 426 to engage therewith. The retainer member 426 may be a shear screw, pin, etc. As such, the amount of force needed to move the flex valve sleeve 424 may be predetermined. Once the member(s) 426 breaks, the flex valve sleeve 424 may freely move. The flex valve sleeve 424 may also be sealingly engaged with the main body 420 via one or more seals, o-rings, etc. 430.
As one of skill would appreciate, as end(s) 442 of respective fingers 440 and the receptacle 429 align, the ends 442 may expand outward. The expansion of the ends 442 into the receptacle 429 may help keep the flex valve sleeve 424 in place without any further sliding upward or downward (and thus the valve 402a may be opened, and kept open).
The sleeve 424 may have an inner sleeve surface, which may be defined by a continuous sleeve inner diameter. The inner sleeve surface may be configured for part of a plugging device (e.g., 214) to engage therewith. In embodiments, an inner edge of finger ends 442 (which may be a restriction or profile) may be configured for part of the plugging device to engage therewith. In the event the sleeve 424 is shifted, the plugging device may be configured to disengage therefrom.
Referring now to
As mentioned, the sub or profile 505 may be or may be associated with a valve (e.g., 202) or other comparable sleeve. As would be apparent while the valves described herein may be stationary as part of the tubular 504, a plugging device 514 may be disposed within the tubular and run downhole therethrough (such as via pumping, workstring 501 [only partial view], or the like). A valve (e.g., 202, 302, 402a, etc.) of the present disclosure may have the plugging device 514 engaged therewith, and thus forming a valve-plugging device assembly. The plugging device 514 may be configured to engage the sub 505 only once the plugging device is moved or placed in a set configuration, and subsequently moved or urged thereagainst.
The plugging device 514 may be run, positioned, and operated as described herein and in other embodiments (such as in system 200, and so forth), and as otherwise understood to one of skill in the art. The plugging device 514 may be comparable or identical in aspects, function, operation, components, etc. as that of other embodiments disclosed herein. Similarities may not be discussed for the sake of brevity.
The workstring 501 (which may include a setting tool [or a part 508 of a setting tool] configured with an adapter 552) may be used to position or run the device 514 into and through the wellbore 506 to a desired location. One of skill would appreciate the setting tool may be like that provided by Baker or Owen. The setting tool assembly 508 may include or be associated with a setting sleeve 554. The setting sleeve 554 may be engaged with the plugging device (or a component thereof) 514.
The setting tool may include a tension mandrel 574 associated (e.g., coupled) with the adapter 552. In an embodiment, the adapter 552 may be coupled with the setting tool (or part thereof) 508, and the tension mandrel 574 may be coupled with the device 514. The coupling may be a threaded connection (such as via threads on setting tool 508 and corresponding threads of the tension mandrel 574—not shown here). The tension mandrel 574 may extend, at least partially, out of the (bottom/downhole/distal end) device 514.
An end or extension 574a of the tension mandrel 574 may be coupled with a nose sleeve or nut 577. The nut 577 may have a threaded connection with the end 574a (and thus corresponding mating threads), although other forms of coupling may be possible. For additional securing, one or more set screws (not viewable here) may be disposed through set screw hole 675 and screwed into or tightened against the end 574a. The nut 577 may engage or abut against a shear feature (such as of a lower sleeve 560). The shear feature may be a ring, tab, threads, pin, etc.
The plugging device 514, as well as its components, may be annular in nature, and thus centrally disposed or arranged with respect to a longitudinal axis 558. In accordance with embodiments of the disclosure, the device 514 may be configured as a plugging tool, which may be set within the tubular 504, albeit not in the traditional sense of a plugging tool.
That is, instead of the device 514 being set in a manner whereby the it expands to engage the casing, the device 514 may be activated, but not to the point of engagement with the surrounding tubular surface 512. As shown here, the restriction sub 505 may be configured with an extension or profile 533 that is tantamount to a narrowing of the tubular 504. For example, the tubular 504 may have a tubular inner diameter 551, whereas the profile has a profile inner diameter 553. The profile inner diameter 553 may be smaller than the tubular inner diameter 551, and thus provide the narrowance or smaller passageway. In other aspects, the profile inner diameter 551 may be larger than the tubular inner diameter 551. The profile inner diameter 553 is not shown to scale here. In some embodiments, the workstring 501 may be moved through the profile 533, whereby the device 514 may be activated once passed. The plugging device 514 may then be free to move toward a further or another restriction sub thereafter (not shown here).
In an embodiment, the device 514 may be configured to provide a plug, whereby flow from one section of the wellbore to another (e.g., above and below the device 514) is controlled. In other embodiments, once a ball or other obstruction is seated in the device 514, flow into one section of the wellbore 506 may be blocked and otherwise diverted into the surrounding formation or reservoir 510.
Once the device 514 reaches the activated position (or sometimes the set configuration) within the tubular 504, the setting mechanism or workstring 501 may be detached from the device 514 by various methods, resulting in the device 514 left freely afloat and movable in the surrounding tubular 504.
In an embodiment, once the plugging device 514 is in the desired position, tension may be applied to the setting tool 508 until a shearable connection (or feature) between the device 514 and the workstring 508 is broken. However, the plugging device 514 may have other forms of disconnect. The amount of load applied to the setting tool and the shearable connection may be in the range of about, for example, 20,000 to 55,000 pounds force.
In embodiments the tension mandrel 574 may separate or detach from a lower sleeve 560 (directly or indirectly)), resulting in the workstring 508 being able to separate from the device 514, which may be at a predetermined moment. The loads provided herein are non-limiting and are merely exemplary. The setting force may be determined by specifically designing the interacting surfaces of the plugging device 514 and the respective device surface angles.
Operation of the plugging device 514 may allow for fast run in of the device 514 to isolate one or more sections of the wellbore 506, as well as quick and simple drill-through or dissolution to destroy or remove the device 514.
Accordingly, in some embodiments, drill-through may be completely unnecessary. As such the plugging device 514 may have one or more components made of a reactive material, such as a metal or metal alloys. The plugging device 514 may have one or more components made of a reactive material (e.g., dissolvable, degradable, etc.), which may be plastic, composite- or metal-based.
It follows then that one or more components of a tool or device of embodiments disclosed herein may be made of reactive materials (e.g., materials suitable for and are known to dissolve, degrade, etc. in downhole environments [including extreme pressure, temperature, fluid properties, etc.] after a brief or limited period of time (predetermined or otherwise) as may be desired). In an embodiment, a component made of a reactive material may begin to react at first contact with the dissolving fluid, and remain viable about 3 to about 48 hours after setting of the plugging device 514.
In embodiments, one or more components may be made of a metallic material, such as an aluminum-based or magnesium-based material. The metallic material may be reactive, such as dissolvable, which is to say under certain conditions the respective component(s) may begin to dissolve, and thus alleviating the need for drill thru. These conditions may be anticipated and thus predetermined. In embodiments, one or more components of the device 514 may be made of dissolvable aluminum-, magnesium-, or aluminum-magnesium-based (or alloy, complex, etc.) material, such as that provided by Nanjing Highsur Composite Materials Technology Co. LTD or Terves, Inc.
One or more components of device 514 may be made of non-dissolvable materials (e.g., materials suitable for and are known to withstand downhole environments [including extreme pressure, temperature, fluid properties, etc.] for an extended period of time (predetermined or otherwise) as may be desired).
The plugging device 514 (and other tool embodiments disclosed herein) and/or one or more of its components may be 3D-printed or made with other forms of additive manufacturing.
Referring now to
Embodiments herein provide for a plugging device that may have as few as two or three basic parts, plus a (dissolvable) seating device, such as a ball. An expanding sleeve may be machined to an OD which easily passes through a restriction(s) in the wellbore, of which the restriction may be configured to provide a seat for the device. When at setting depth (which may be predetermined), the expandable sleeve may be expanded in diameter suitable to engage than the restriction or profile diameters in the surrounding tubular or sub (e.g., casing string).
This may occur by urging a cone member into the sleeve, such as via the use of a wireline setting tool, until the two parts locate on corresponding shoulders in both parts. Once expanded, the sleeve and cone may be locked together via friction, press- or interference-fit, or comparable. These parts may be secured to the setting tool with a lower sleeve, which may be configured as a shear ring. Once adequate force is generated to shear the lower sleeve, the plugging device (and its components) may be released from the setting tool. The setting tool (and workstring) may then be retrieved from the well. In aspects, the workstring may be void of a perforating gun. The plugging device, in the expanded condition, need not (sealingly or securingly) engage the tubular ID, and instead may be free floating therein.
Other embodiments herein pertain to a plugging device that may include an expandable sleeve or ring (such as a seal ring), which may be urged or otherwise driven up or against a cone member (or outer conical surface) during setting. This may provide the interference with the restriction sub. Releasing from the setting tool may be comparable to other embodiments described herein. The length of the expandable sleeve or ring may dictate how much differential pressure the device can withstand. The outer cone surface (or ‘ramp angle’) may dictate the setting force required to fully expand the sleeve.
A (dissolvable) ball or other type of obstruction may be pumped to its seat in the device (any embodiment), and may push the device downhole until plugging device lands on the next lower profile sub in the well. The device may seat on the restriction or profile forming a pressure barrier for the subsequent frac job. Profile subs may be installed in the tubular string when the tubular is run. The profile sub may be a valve, such as a frac valve and/or a flex valve.
Advantageously, a plugging device embodiment of the present disclosure need not anchor to the surrounding tubular, such as with traditional plugs-thus there is no damage to the tubular from hardened slip teeth or buttons. The device location during the fracturing operation may be defined by the location of the restriction subs run in the tubular string.
Once expanded using the setting tool, and then disconnected, the plugging device may be akin to a plug/ball, and may seats on the next lower restriction or profile sub in the wellbore. The interface geometry between the cone/expansion sleeve/ring may be configured to allow expansion to the desired outer diameter while staying within the operational force output of the setting tool (e.g., 55,000 lbf. for the size 20 tool). The end of the cone may be rounded to provide the ultimate contact area with the sleeve. Having a slightly recessed diameter behind the ball may prevent friction from the previously expanded section of the sleeve, thus preventing accumulation of force as the entire length of the sleeve expands. The plugging device may be configured with a ramp angle between the cone and expandable sleeve to control setting force. Having the sleeve/ring bottom-out on the external upset in the cone may put the sleeve/ring material in compression when pressuring against the tool from above, which may reduce shear stress in the material.
Embodiments herein may pertain to a downhole system 600 that includes a wellbore 606 having a tubular (such as a casing string or the like) 604 disposed therein. A workstring 601 (shown only in part here) may be used to run a plugging device 614 into the tubular 604 to a desired position. The plugging device 614 may have a run-in (or unset, first, etc.) configuration of
The plugging device 614 may include a mandrel 614a, which may be a cone (or conical shaped member) that extends through the device 614 (or device body). Although mandrel 614a may be referenced or viewed as a ‘cone’, other shapes or configurations are possible. The cone 614a may have one or more ‘conical’ (frustoconical, etc.) surfaces 655 (e.g., a surface off-axis to long axis 658). The cone 614a may include a flowpath or bore 650 formed therein (e.g., an axial bore). The bore 650 may extend partially or for a short distance through the cone 614a. Alternatively, the bore 650 may extend through the entire cone 614a, with an opening at its proximate end 659 and oppositely at its distal end 657 (near downhole or bottom end of the device 614).
The presence of the bore 650 or other flowpath through the cone 614a may indirectly be dictated by operating conditions. That is, in most instances the device 614 may be large enough in diameter (e.g., 4¾ inches) that the bore 650 may be correspondingly large enough (e.g., 1¼ inches) so that debris and junk may pass or flow through the bore 650 without plugging concerns. Diameters greater than 4¾ inches and less than 1¼ inches may be used in certain instances, where desired.
With the presence of the bore 650, the cone 614a may have an inner bore surface 647, which may be smooth and annular in nature. In cross-section, the bore surface 647 may be planar. In embodiments, the bore surface 647 (in cross-section) may be parallel to the (central) device axis 658. As mentioned, the outer cone surface 655 may have one or more surfaces (in cross-section) offset or angled to the device axis 658.
The bore 650 (and thus the device 614) may be configured for part of a setting tool assembly 608 (shown only in part here) to fit therein, such as a tension mandrel 674. Thus, the tension mandrel 674, which may be contemplated as being part of the setting tool assembly 608, may be configured for the plugging device 614 (or components thereof) to be disposed (at least partially) therearound (such as during run-in). In assembly, as well as for the run-in configuration, the plugging device 614 may be coupled with the setting tool assembly 608 (and around, at least in part, the tension mandrel 674), but need not be in a threaded manner. In an embodiment, the plugging device 614 (by itself, and not including setting tool components) may be completely devoid of threaded connections. If used, an adapter 652 may include threads thereon. Such threads (not shown here) may correspond to mate with threads of the setting sleeve 654.
As shown, a lower sleeve 660 may be configured or associated with a shear feature, such as shear threads or tab 661. The shear feature 661 may be engaged with the setting tool assembly 608. As shown, the shear feature 661 may be engaged or proximate to each of the tension mandrel 674 and a nose nut 677. The lower sleeve 660 (or the shear feature) may be configured to facilitate or promote deforming, and ultimately shearing/breaking, during setting. As such, the shear feature 661 may have at least one recess region or fracture groove 662 (tantamount to a predetermined and purposeful failure point of the lower sleeve 660).
The groove 662 may be circumferential around the feature 661. In embodiments the recess region/groove 662 may be in the form of a v-notch or other shape or configuration suitable to allow the feature 661 to break free from the lower sleeve 660. The shear feature 661 may be configured to shear at a predetermined point. The shear feature may be disposed within an inner lower sleeve bore or recess (not numbered), and protrude (or extend) radially inward in a circumferential manner. There may be other recessed regions. There shear feature 661 may be anything suitable to provide a predetermined point of failure for the connection of the device 614 with the setting tool 608, and may be in one or more other locations (not shown here).
During setting, as the tension mandrel 674 (and thus tension mandrel end 674a) continues to be pulled in direction A, the nut 677 may continue to exert force on the shear feature 661, ultimately resulting in shearing the feature 661. The shear feature 661 may be configured to shear at a load greater than the load for setting the device 614. Once sheared, the lower sleeve 660 may fall away from the device 614; however, in the set or now-expanded state in a position beyond first profile 633, the device 614 may not fall any further than respective profile 633a of the lower restriction or profile sub 605a (as illustrated in
The plugging device 614 may be run into wellbore 606 to a desired depth or position by way of the workstring 601 (shown in part) that may be configured with the setting tool assembly 608. The workstring 601 and setting tool 608 may be part of the plugging system 600 utilized to run the plugging device 614 into the wellbore 606 and activate the device 614 to move from an unset to set position (or sometimes unset configuration to set configuration, first configuration to second configuration, etc.). The plugging device 614 may be run toward and through a first profile or profile sub 605. For any and all embodiments of the disclosure, the profile sub 605 may be a solid sleeve valve or flex sleeve valve (with a respective shoulder or profile structure for the plugging device 614 to engage therewith).
Once past or through the profile sub 605, the plugging device 614 may be set or moved to the set configuration, whereby the plugging device 614 may now be able to engage any respective lower or next sub 605a.
The set or activated position of the plugging device 614 may include components of the device 614 compressed together, but the device 614 need not be set or engaged against the tubular 604 (which may be defined by a tubular inner diameter 651 of an inner tubular surface 612. Instead, the device 614 may free float (i.e., move freely) unless and until it may be urged into engagement with a shoulder 633b of profile 633a (see 3C). The profile 633, 633a may have an inner profile diameter 653, 653a, respectively. The tubular 604 may be run in the wellbore with one or more profile subs disposed therewith. Although described or shown as ‘restriction’, it is withing the scope of the disclosure that the profile may be inverse or negative. Meaning, the profile diameter(s) 653, 653a, etc. may be larger than the tubular inner diameter 651.
The setting device(s) 608 and components of the plugging device 614 may be coupled with, and axially and/or longitudinally movable along or in a working relationship with the cone 614a. When the setting sequence begins, the lower sleeve 660 may be pulled via tension mandrel 674 while the setting sleeve 654 remains stationary.
As the tension mandrel 674 is pulled in the direction of Arrow A, one or more the components may begin to compress against one another as a result of the setting sleeve 654 (or end its end) held in place against an end surface of the proximate end 659 of the cone 614a.
This force and resultant movement may urge an expansion sleeve or ring 641 to compressively slide against an upper cone surface 651 of the cone 614a, and ultimately expand. Thus, the expansion ring 641 may be slidingly engaged with the cone mandrel 614a.
As the lower sleeve 660 is pulled further in the direction of Arrow A, the lower sleeve 660 (being engaged with the expansion sleeve 641) may urge the sleeve 641 to compressively slide against the cone surface 655. As expansion occurs, the sleeve 641 may move radially outward, but will not expand into engagement with the surrounding tubular 604; at least not the degree that the device 614 may not move.
In an embodiment, the cone 614a may be configured with a ball seat 686 formed or removably disposed therein. In some embodiments, the ball seat 686 may be integrally formed within the bore 650 of the cone 614a. In other embodiments, the ball seat 686 may be separately or optionally installed within the cone 614a, as may be desired.
The ball seat 686 may be configured in a manner so that a ball 617 or other form of plug/obstruction may seat or rest therein, whereby the flowpath through the cone 614a may be closed off (e.g., flow through the bore 650 is restricted or controlled by the presence of the ball or plug 617). In this respect, once the setting tool 608 and the workstring 601 are disconnected from the device 614, the ball 617 may be free to seat thereagainst.
For example, fluid flow from one direction may urge and hold the ball 617 against the seat 686, whereas fluid flow from the opposite direction may urge the ball 617 off or away from the seat 686. As such, the ball may 617 be used to prevent or otherwise control fluid flow through the device 614. The ball 617 may be conventionally made of a composite material, dissolvable material, phenolic resin, etc., whereby the ball may be capable of holding maximum pressures experienced during downhole operations (e.g., fracing).
While not limited, a diameter of the ball 617 may be in in a ball diameter range of about 1 inch to about 5 inches. The bore 650 may have an inner bore diameter in a bore diameter range of about 1 inch to about 5 inches. As such, the cone 614a may have suitable wall thickness to handle load and prevent collapse.
The ball 617 may be any type of ball apparent to one of skill in the art and suitable for use with embodiments disclosed herein, including any such ball may be a ball held in place or otherwise positioned within a plugging device. The ball 617 may be a “smart” ball configured to monitor or measure downhole conditions, and otherwise convey information back to the surface or an operator, such as the ball(s) provided by Aquanetus Technology, Inc. or OpenField Technology
In other aspects, the ball 617 may be made from a composite or dissolvable material. Other materials are possible, such as glass or carbon fibers, phenolic material, plastics, fiberglass composite (sheets), plastic, etc. The ball 617 may be configured or otherwise designed to dissolve (at least partially) under certain conditions or various parameters, including those related to temperature, pressure, and composition.
Although not shown here, the plugging device 614 may have a pumpdown ring or other suitable structure to facilitate or enhance run-in. The plugging device 614 may have a ‘composite member’ like that described in U.S. Pat. No. 8,955,605, incorporated by reference herein in its entirety for all purposes, particularly as it pertains to the composite member.
Referring briefly to
The sequence of setting (opening) sleeves of a valve of any respective cluster may be repeated with a new device 614 for any preceding clusters. For example, after the first stage is stimulated, a second device 614 may be pumped from the surface downhole. The second device 614 may travel through any predetermined number of valves (202, 202a) without opening them. Although not shown here, there may be a secondary device or tool used to close any valve previously opened by the device 614.
Referring now to
In an analogous manner, the lower sleeve 760 may have an inner sleeve body configured with one or more annular ridges or recesses, such as recess or groove 763. In inner sleeve recess surface 763a may be configured to engage the cone tip outer surface 764a (see by way of example, first contact point 666,
The lower sleeve 760 may have another sleeve surface 763b configured to engage the cone 714a. For example, the another sleeve surface 763b may engage the cone outer surface 755 (see by way of example, second contact point 667,
Upon activation, compression force generated by the setting tool may urge the expansion ring up/against the ramped or angled surface 755 of the cone 714a via the lower sleeve 760 until the sleeve locates on or proximate shoulder end 755a. Or until the cone tip 764 extends all the way into the recess 763. After shearing and setting, the cone tip 764 remains engaged against the recess 763 via interference or tolerance fit.
Any tool or device of the disclosure or claimed invention may be coupled with a workstring. The workstring may be contemplated as a mode of conveyance for the tool to a predetermined or desired location within the wellbore. The workstring may be general in nature as would be known to one of ordinary skill in the art. On the other hand, the workstring may be configured for particular use for embodiments herein. The workstring may be void of a perforating gun.
One or more components of any device of embodiments disclosed herein may be made of reactive materials (e.g., materials suitable for and are known to dissolve, degrade, etc. in downhole environments [including extreme pressure, temperature, fluid properties, etc.] after a brief or limited period of time (predetermined or otherwise) as may be desired). In an embodiment, a component made of a reactive material may begin to react within about 3 to about 48 hours after exposure to a reaction-inducing stimulant.
In embodiments, one or more components may be made of a metallic material, such as an aluminum-based or magnesium-based material. The metallic material may be reactive, such as dissolvable, which is to say under certain conditions the respective component(s) may begin to dissolve, and thus alleviating the need for drill thru. These conditions may be anticipated and thus predetermined. In embodiments, the components may be made of dissolvable aluminum-, magnesium-, or aluminum-magnesium-based (or alloy, complex, etc.) material, such as that provided by Nanjing Highsur Composite Materials Technology Co. LTD or Terves, Inc.
One or more components may be made of non-dissolvable materials (e.g., materials suitable for and are known to withstand downhole environments [including extreme pressure, temperature, fluid properties, etc.] for an extended period of time (predetermined or otherwise) as may be desired). Components may be 3D-printed or made with other forms of additive manufacturing.
Embodiments herein may advantageously solve the problem of pumping efficiency, cost, and water usage by allowing a user to hydraulic fracture one or more pin point locations in time. Systems and methods of the disclosure may reduce displacement water, perf erosion, and significant time on location. This may beneficially allow for reduced personal and services on site, and may thereby provide a simpler install and safer work environment for operators. This system also addresses all problems associated with legacy sleeves designs and plug and perf operations
Other advantages pertain to use of an identical plugging device, which may reduce risk associated with machining and of installation, as well as reduce quality control risk. In a similar manner, the frac valve (with solid sleeve) and the frac valve (with flex sleeve) may also be manufactured identically, with similar benefits. Saving water, time on location, risk, personal on location, and service company costs (such as for wireline, pump down crew, and drillout) are a huge competitive advantage. When downhole operations run about $30,000-$40,000 per hour, a savings measured in minutes (albeit repeated in scale) is of significance. Again, even a small savings per stage results in an enormous savings on an annual basis.
Embodiments of the plugging device are smaller in size, which allows the device to be used in slimmer bore diameters. Smaller in size also means there is a lower material cost per tool. Because isolation tools, such as plugs, are used in vast numbers, and are generally not reusable, a small cost savings per tool results in enormous annual capital cost savings.
Objectives achievable include ability to use a device of the disclosure inside of a sleeve, such as a frac sleeve (valve). Pump down devices are not necessary, as the device may be run in via wireline or workstring, such as a slickline. This means there may be a workstring without perforating guns. Embodiments may use wireline and braided lines without perforating guns.
Running a device of the disclosure inside of a frac sleeves, means it is not necessary to deploy perforating device. Instead, slickline may be used. The workstring may be simple, and unnecessary to have the ability to send electrical current (very cost effective). The device of the disclosure may open or shift a sleeve. Then it may dissolve sufficiently to establish a flowpath.
While preferred embodiments of the disclosure have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the disclosure disclosed herein are possible and are within the scope of the disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations. The use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, and the like.
Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present disclosure. Thus, the claims are a further description and are an addition to the preferred embodiments of the present disclosure. The inclusion or discussion of a reference is not an admission that it is prior art to the present disclosure, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent they provide background knowledge; or exemplary, procedural or other details supplementary to those set forth herein.
| Number | Date | Country | |
|---|---|---|---|
| 63545307 | Oct 2023 | US | |
| 63144677 | Feb 2021 | US | |
| 63089631 | Oct 2020 | US | |
| 63125024 | Dec 2020 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 17591364 | Feb 2022 | US |
| Child | 18629206 | US | |
| Parent | 17496717 | Oct 2021 | US |
| Child | 18197965 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 18629206 | Apr 2024 | US |
| Child | 18923147 | US | |
| Parent | 18197965 | May 2023 | US |
| Child | 18923147 | US |
