AU2015414757A1

AU2015414757A1 - Sharp and erosion resistance degradable material for slip buttons and sliding sleeve baffles

Info

Publication number: AU2015414757A1
Application number: AU2015414757A
Authority: AU
Inventors: Michael L. Fripp; Thomas FROSELL; Zach WALTON
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2015-11-18
Filing date: 2015-11-18
Publication date: 2018-03-08
Also published as: US20180238133A1; WO2017086955A1; GB201802870D0; PL425262A1; GB2557104A; NO20180259A1; RO133676A2; AR106749A1; MX2018004423A; CA2998846A1

Abstract

A sharp and erosion resistant degradable material used in a component in a downhole tool and a method of using said degradable material. More particularly, the sharp and erosion resistant degradable material includes dissolvable metal matrix composite which includes a dissolvable metal and a dispersed reinforcement material wherein the dissolvable metal is capable of dissolving via galvanic corrosion. The dissolvable metal may include at least one of aluminum alloy, magnesium alloy, zinc alloy, bismuth alloy, tin alloy, or any combination thereof. The dispersed reinforcement material may include a ceramic or a hardened metal. The ceramic may include at least one of: zirconia (including zircon), alumina (including fused alumina, chrome-alumina, and emery), carbide (including tungsten carbide, silicon carbide, titanium carbide, and boron carbide), boride (including boron nitride, osmium diboride, rhenium boride, titanium boride, and tungsten boride), nitride (silicon nitride and aluminum nitride), synthetic diamond, silica, and any combination thereof.

Description

BACKGROUND [0001] The present disclosure generally relates to a sharp and erosion-resistant degradable material used in a component in a downhole tool, and a method of using said degradable material. More particularly, the sharp and erosion-resistant degradable material includes a dissolvable metal matrix composite wherein the dissolvable metal matrix composite includes a dissolvable metal and a dispersed reinforcement material wherein the dissolvable metal is capable of dissolving via galvanic corrosion.

[0002] In the drilling, completion and stimulation of hydrocarbon-producing wells, a variety of downhole tools are used. For example, it is often desirable to seal portions of a wellbore, such as during fracturing operations when various fluids and slurries are pumped from the surface into a casing string that lines the wellbore, and forced out into a surrounding subterranean formation through the casing string. Sealing the wellbore may become necessary to provide zonal isolation at the location of the desired subterranean formation. Wellbore isolation devices, such as packers, baffle seats, bridge plugs, and fracturing plugs (i.e., “frac” plugs), are designed for these general purposes and are well known in the art of producing hydrocarbons, such as oil and gas. Such wellbore isolation devices may be used in direct contact with the formation face of the wellbore, with a casing string extended and secured within the wellbore, or with a screen or wire mesh.

[0003] After the desired downhole operation is complete, the seal formed by the wellbore isolation device must be broken and the tool itself removed from the wellbore. Removing the wellbore isolation device may allow hydrocarbon production operations to commence without being hindered by the presence of the downhole tool. Removing wellbore isolation devices, however, is traditionally accomplished by a complex retrieval operation that involves milling or drilling out a portion of the wellbore isolation device, and subsequently mechanically retrieving its remaining portions. To accomplish this, a tool string having a mill or drill bit attached to its distal end is introduced into the wellbore and conveyed to the wellbore isolation device to mill or drill out the wellbore isolation device. After drilling out the wellbore

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PCT/US2015/061365 isolation device, the remaining portions of the wellbore isolation device may be grasped onto and retrieved back to the surface with the tool string for disposal. As can be appreciated, this retrieval operation can be a costly and time-consuming process.

[0004] There exists a need for a novel method of removing parts or the entire wellbore isolation device in a less expensive and efficient manner with a controlled or predictable dissolution rate.

BRIEF DESCRIPTION OF THE DRAWINGS [0005] The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, without departing from the scope of this disclosure.

[0006] FIG. 1 is a well system that employs the metal matrix composite in accordance with the principles of the present disclosure.

[0007] FIG. 2 is a cross-sectional side view of an exemplary frac plug that can employ the metal matrix composite in accordance with the principles of the present disclosure;

[0008] FIG. 3 is an example of a sliding sleeve that employs the metal matrix composite in accordance with the principles of the present disclosure;

[0009] FIG. 4 is an example of a metal matrix composite in accordance with the principles of the present disclosure.

[0010] FIG. 5 is a micrograph of an example of a metal matrix composite in accordance with the principles of the present disclosure.

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DETAILED DESCRIPTION [0011] In the following detailed description of the illustrative embodiments, reference is made to the accompanying drawings that form a part hereof. These embodiments are described in sufficient detail to enable those skilled in the art to practice the invention, and it is understood that other embodiments may be utilized and that logical structural, mechanical, electrical, and chemical changes may be made without departing from the spirit or scope of the invention. To avoid detail not necessary to enable those skilled in the art to practice the embodiments described herein, the description may omit certain information known to those skilled in the art. The following detailed description is, therefore, not to be taken in a limiting sense, and the scope of the illustrative embodiments is defined only by the appended claims.

[0012] Unless otherwise specified, any use of any form of the terms connect, engage, couple, attach, or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. In the following discussion and in the claims, the terms including and comprising are used in an open-ended fashion, and thus should be interpreted to mean including, but not limited to. Unless otherwise indicated, as used throughout this document, or does not require mutual exclusivity.

[0013] As used herein, the phrase consisting essentially of' shall be used as a transitional phrase, and will leave the entire phrase including “consisting essentially of’ as being open to include additional elements, but only if those additional elements do not materially affect the basic and novel characteristics of the claimed combination [0014] As used herein, the phrases hydraulically coupled, hydraulically connected, in hydraulic communication, fluidly coupled, fluidly connected, and in fluid communication refer to a form of coupling, connection, or communication related to fluids, and the corresponding flows or pressures associated with these fluids. In some embodiments, a hydraulic coupling, connection, or communication between two components describes components that are associated in such a way that fluid pressure may be transmitted between or among the components. Reference to a fluid coupling, connection, or communication between two components describes components that are associated in such a way that a fluid may flow

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PCT/US2015/061365 between or among the components. Hydraulically coupled, connected, or communicating components may include certain arrangements where fluid does not flow between the components, but fluid pressure may nonetheless be transmitted such as via a diaphragm or piston. The present disclosure generally relates to a sharp and erosion resistant degradable material used in a component in a downhole tool and a method of using said degradable material, and more particularly, to a dissolvable metal matrix composite.

[0015] As used herein, “about” may mean that the value is within +/-5% of the measurement.

[0016] As used herein, a “fluid” may include a substance having a continuous phase that tends to flow and to conform to the outline of its container when the substance is tested at a temperature of 71 °F (22 °C) and a pressure of one atmosphere atm (0.1 megapascals MPa). A fluid may be a liquid or gas. A homogenous fluid has only one phase, whereas, a heterogeneous fluid has more than one distinct phase. A heterogeneous fluid may be: a slurry, which includes a continuous liquid phase and undissolved solid particles as the dispersed phase; an emulsion, which includes a continuous liquid phase and at least one dispersed phase of immiscible liquid droplets; a foam, which includes a continuous liquid phase and a gas as the dispersed phase; or a mist, which includes a continuous gas phase and a liquid as the dispersed phase. A heterogeneous fluid will have only one continuous phase, but may have more than one dispersed phase. It is to be understood that any of the phases of a heterogeneous fluid (e.g., a continuous or dispersed phase) may contain dissolved or undissolved substances or compounds. As used herein, the phrase “base fluid” is the liquid that is in the greatest concentration in the wellbore fluid and is the solvent of a solution or the continuous phase of a heterogeneous fluid.

[0017] A well can include, without limitation, an oil, gas, or water production well, or an injection well. As used herein, a “well” includes at least one wellbore. A wellbore can include vertical, inclined, and horizontal portions, and it can be straight, curved, or branched. As used herein, the term “wellbore” includes any cased, and any uncased, open-hole portion of the wellbore. A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. As used herein, a “well” also includes the near-wellbore region. The near-wellbore region is generally considered to be the region within approximately

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100 feet radially of the wellbore. As used herein, “into a well” means and includes into any portion of the well, including into the wellbore or into the near-wellbore region via the wellbore.

[0018] A portion of a wellbore may be an open hole or cased hole. In an open-hole wellbore portion, a tubing string may be placed into the wellbore. The tubing string allows fluids to be introduced into or flowed from a remote portion of the wellbore. In a cased-hole wellbore portion, a casing is placed into the wellbore that can also contain a tubing string. A wellbore can contain an annulus. Examples of an annulus include, but are not limited to: the space between the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wellbore and the outside of a casing in a cased-hole wellbore; and the space between the inside of a casing and the outside of a tubing string in a cased-hole wellbore.

[0019] It is not uncommon for a wellbore to extend several hundreds of feet or several thousands of feet into a subterranean formation. The subterranean formation can have different zones. A zone is an interval of rock differentiated from surrounding rocks on the basis of its fossil content or other features, such as faults or fractures. For example, one zone can have a higher permeability compared to another zone. It is often desirable to treat one or more locations within multiples zones of a formation. One or more zones of the formation can be isolated within the wellbore via the use of an isolation device to create multiple wellbore intervals. At least one wellbore interval corresponds to a formation zone. The isolation device can be used for zonal isolation and functions to block fluid flow within a tubular, such as a tubing string, or within an annulus. The blockage of fluid flow prevents the fluid from flowing across the isolation device in any direction and isolates the zone of interest. In this manner, treatment techniques can be performed within the zone of interest. As used herein, the term “sealing ball,” and grammatical variants thereof, refers to a spherical or spheroidal element designed to seal perforations of a wellbore isolation device that are accepting fluid, thereby diverting reservoir treatments to other portions of a target zone. An example of a sealing ball is a frac ball in a frac plug wellbore isolation device. As used herein, the term “packer element” refers to an expandable, inflatable, or swellable element that expands against a casing or wellbore to seal the wellbore.

[0020] As used herein, the term “wellbore isolation device,” and grammatical variants thereof, is a device that is set in a wellbore to isolate a portion of the wellbore thereabove from a

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PCT/US2015/061365 portion therebelow so that fluid can be forced into the surrounding subterranean formation above the device. Common wellbore isolation devices include, but are not limited to, a ball and a seat, a bridge plug, a packer, and a plug. It is to be understood that reference to a baU is not meant to limit the geometric shape of the ball to spherical, but rather is meant to include any device that is capable of engaging with a seat. A ball can be spherical in shape, but can also be a dart, a bar, or any other shape. Zonal isolation can be accomplished via a ball and seat by dropping or flowing the ball from the wellhead onto the seat that is located within the wellbore. The ball engages with the seat, and the seal created by this engagement prevents fluid communication into other wellbore intervals downstream of the ball and seat. As used herein, the relative term downstream means at a location further away from a wellhead. In order to treat more than one zone using a ball and seat, the wellbore can contain more than one ball seat. For example, a seat can be located within each wellbore interval. Generally, the inner diameter (I.D.) of the ball seats is different for each zone. For example, the I.D. of the ball seats sequentially decreases at each zone, moving from the wellhead to the bottom of the well. In this manner, a smaller ball is first dropped into a first wellbore interval that is the farthest downstream; the corresponding zone is treated; a slightly larger ball is then dropped into another wellbore interval that is located upstream of the first wellbore interval; that corresponding zone is then treated; and the process continues in this fashion - moving upstream along the wellbore - until all the desired zones have been treated. As used herein, the relative term “upstream” means at a location closer to the wellhead.

[0021] A bridge plug is composed primarily of slips, a plug mandrel, and a rubber sealing element. A bridge plug can be introduced into a wellbore and the sealing element can be caused to block fluid flow into downstream intervals. A packer generally consists of a sealing device, a holding or setting device, and an inside passage for fluids. A packer can be used to block fluid flow through the annulus located between the outside of a tubular and the wall of the wellbore or inside of a casing [0022] The use of directional terms such as above, below, upper, lower, upward, downward, left, right, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding

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PCT/US2015/061365 figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well.

[0023] As used herein, the term “dissolvable” and all of its grammatical variants (e.g., “degrade,” “degradation,” “degrading,” “dissolve,” dissolving,” and the like), refers to the dissolution or chemical conversion of solid materials such that reduced-mass solid end products by at least one of solubilization, hydrolytic degradation, chemical reactions (including electrochemical and galvanic reactions), thermal reactions, reactions induced by radiation, or combinations thereof.

[0024] As used herein, a “degradable or dissolvable metal” may refer to a metal that has a certain rate of dissolution, and the rate of dissolution may correspond to a rate of material loss at a particular temperature and within particular wellbore conditions.

[0025] As used herein, an “electrolyte” is any substance containing free ions (i.e., a positively or negatively charged atom or group of atoms) that make the substance electrically conductive. The electrolyte can be selected from the group consisting of, solutions of an acid, a base, a salt, and combinations thereof. A salt can be dissolved in water, for example, to create a salt solution. Common free ions in an electrolyte include, but are not limited to, sodium (Na+), potassium (K⁺), calcium (Ca²⁺⁾, magnesium (Mg²⁺⁾, chloride (Cf), bromide (B) hydrogen phosphate (HPO4 ’), hydrogen carbonate (HCO3 ), and any combination thereof. Preferably, the electrolyte contains chloride ions.

[0026] Galvanic corrosion occurs when two different metals or metal alloys are in electrical connectivity with each other and both are in contact with an electrolyte. As used herein, the phrase electrical connectivity means that the two different metals or metal alloys are either touching or in close enough proximity to each other such that when the two different metals are in contact with an electrolyte, the electrolyte becomes electrically conductive and ion migration occurs between one of the metals and the other metal, and is not meant to require an actual physical connection between the two different metals, for example, via a metal wire.

[0027] It is to be understood that as used herein, the term metal is meant to include pure metals and also metal alloys without the need to continually specify that the metal can also be a metal alloy. Moreover, the use of the phrase metal or metal alloy in one sentence or paragraph does not mean that the mere use of the word metal in another sentence or paragraph

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PCT/US2015/061365 is meant to exclude a metal alloy. As used herein, the term metal alloy means a mixture of two or more elements, wherein at least one of the elements is a metal. The other element(s) can be a non-metal or a different metal. An example of a metal and non-metal alloy is steel, comprising the metal element iron and the non-metal element carbon. An example of a metal and metal alloy is bronze, comprising the metallic elements copper and tin.

[0028] In some instances, the degradation of the dissolvable metal matrix composite or dissolvable metal may be sufficient for the mechanical properties of the metal to be reduced to a point that the metal no longer maintains its integrity and, in essence, falls apart or sloughs off into its surroundings. The conditions for degradation are generally wellbore conditions where an external stimulus may be used to initiate or effect the rate of degradation, where the external stimulus is naturally occurring in the wellbore (e.g., pressure, temperature) or introduced into the wellbore (e.g., fluids, chemicals). For example, the pH of the fluid that interacts with the material may be changed by introduction of an acid or a base. The term “wellbore environment” includes both naturally occurring wellbore environments and materials or fluids introduced into the wellbore. The term “at least a portion” with reference to degradation (e.g., “at least a portion of the mandrel is degradable” or “at least a portion of the degradable packer element is degradable,” and variants thereof) refers to degradation of at least about 80% of the volume of that part.

[0029] The present disclosure describes embodiments of a component in a downhole tool (e.g., wellbore isolation device) that is made of a dissolvable metal matrix composite. In particular, the present disclosure describes having a variety of components including, e.g., a baffle seats, a shear pin, a slip button, a mandrel, a sealing ball, and an expandable or inflatable packer element. The degradable wellbore isolation devices may include e.g., frac plugs. Having a component for wellbore isolation device be made out of a dissolvable metal matrix composite would facilitate an easier disposal of the component without an expensive or labor intensive procedure to remove said component from the wellbore system.

[0030] The dissolvable metal matrix composite consists essentially of a dissolvable metal and a dispersed reinforcement material wherein the dissolvable metal is capable of dissolving via galvanic corrosion when the dissolvable metal is in presence of an electrolyte. The dispersed reinforcement material may include a ceramic or a hardened metal. In an alternative

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PCT/US2015/061365 embodiment, the dissolvable metal matrix composite consists essentially of a dissolvable metal and a disperse reinforcement material wherein the dissolvable metal is capable of dissolving via dissolution when the dissolvable metal is in the presence of water. In another example, the dissolvable metal forms a galvanic couple with the dispersed reinforcement material.

[0031] The dissolvable metal that may be used in accordance with the embodiments of the present disclosure includes galvanically-corrodible or degradable metals and metal alloys. Such metals and metal alloys may be configured to degrade via an electrochemical process in which the galvanically-corrodible metal corrodes in the presence of an electrolyte (e.g., brine or other salt-containing fluids present within the wellbore). The electrolyte can be a fluid that is introduced into the wellbore or a fluid emanating from the wellbore, such as from a surrounding subterranean formation.

[0032] In an embodiment of the present disclosure, the degradability of the dissolvable metal matrix composite can be accelerated by creating galvanic couples within the dissolvable metal matrix composite. There are two paths for accelerating the corrosion: 1) alloying the dissolvable metal with copper, nickel, carbon, or iron, or 2) replacing part of the ceramic with cathodic nuggets.

[0033] The dissolvable metal may be alloyed with copper, nickel, or iron as a solid solution. The copper, nickel, or iron creates inclusions that have a galvanic potential that accelerates the corrosion of the metal.

[0034] A part of the ceramic may be replaced with a cathodic component that creates a galvanic potential with the metal matrix. The galvanic coupling may be generated by embedding or attaching a cathodic substance or piece of material into an anodic component. The cathodic component could be a nugget, a spheroid, a sliver, a fiber, or a weave. In theory, the cathodic component could be any material that creates a galvanic potential with the metal matrix. In a preferred embodiment of the present disclosure, the cathodic components include copper, nickel, steel, or graphite (carbon). Other options may include platinum, silver, zirconium, titanium, iron, bronze, chromium, tin, or their alloys. In at least one embodiment of the present disclosure, the galvanic coupling may be generated by dissolving aluminum in gallium.

[0035] The metal that is less noble, compared to the other metal, will dissolve in the electrolyte. The less noble metal is often referred to as the anode, and the more noble metal is

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PCT/US2015/061365 often referred to as the cathode. Galvanic corrosion is an electrochemical process whereby free ions in the electrolyte make the electrolyte electrically conductive, thereby providing a means for ion migration from the anode to the cathode - resulting in deposition formed on the cathode. Metals can be arranged in a galvanic series. The galvanic series lists metals in order of the most noble to the least noble. An anodic index lists the electrochemical voltage (V) that develops between a metal and a standard reference electrode (gold (Au)) in a given electrolyte. The actual electrolyte used can affect where a particular metal or metal alloy appears on the galvanic series and can also affect the electrochemical voltage. For example, the dissolved oxygen content in the electrolyte can dictate where the metal or metal alloy appears on the galvanic series and the metal's electrochemical voltage. The anodic index of gold is -0 V; while the anodic index of beryllium is -1.85 V. A metal that has an anodic index greater than another metal is more noble than the other metal and will function as the cathode. Conversely, the metal that has an anodic index less than another metal is less noble and functions as the anode. In order to determine the relative voltage between two different metals, the anodic index of the lesser noble metal is subtracted from the other metal's anodic index, resulting in a positive value.

[0036] There are several factors that can affect the rate of galvanic corrosion. One of the factors is the distance separating the metals on the galvanic series chart or the difference between the anodic indices of the metals. For example, beryllium is one of the last metals listed at the least noble end of the galvanic series and platinum is one of the first metals listed at the most noble end of the series. By contrast, tin is listed directly above lead on the galvanic series. Using the anodic index of metals, the difference between the anodic index of gold and beryllium is 1.85 V; whereas, the difference between tin and lead is 0.05 V. This means that galvanic corrosion will occur at a much faster rate for magnesium or beryllium and gold compared to lead and tin.

[0037] Another factor that can affect the rate of galvanic corrosion is the temperature and concentration of the electrolyte. The higher the temperature and concentration of the electrolyte, the faster the rate of corrosion In an embodiment of the present disclosure, the temperature of the wellbore system may be increased or decreased based on volume of the wellbore fluid being pumped into the wellbore system.

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PCT/US2015/061365 [0038] Yet another factor that can affect the rate of galvanic corrosion is the total amount of surface area of the least noble (anodic metal). The greater the surface area of the anode that can come in contact with the electrolyte, the faster the rate of corrosion. The cross-sectional size of the anodic metal pieces can be decreased in order to increase the total amount of surface area per total volume of the material. The anodic metal or metal alloy can also be a matrix in which pieces of cathode material is embedded in the anode matrix.

[0039] Yet another factor that can affect the rate of galvanic corrosion is the ambient pressure. Depending on the electrolyte chemistry and the two metals, the corrosion rate can be slower at higher pressures than at lower pressures if gaseous components are generated. Yet another factor that can affect the rate of galvanic corrosion is the physical distance between the two different metal and/or metal alloys of the galvanic system.

[0040] In an embodiment of the present disclosure, the dissolvable metal may include gold, gold-platinum alloys, silver, nickel, nickel-copper alloys, nickel-chromium alloys, copper, copper alloys (e.g., brass, bronze, etc.), chromium, tin, aluminum, aluminum alloys, iron, zinc, magnesium, magnesium alloys, beryllium, any alloy of the aforementioned materials, and any combination thereof.

[0041] In another embodiment of the present disclosure, the dissolvable metal may include an aluminum alloy that is alloyed with gallium. The gallium acts as a depassivating agent and prevents the formation of a protective passivation layer on the surface of the aluminum. Indium and tin also act as depassivating agents and help to prevent passivation on the aluminum. Examples of aluminum-gallium alloys include 80% aluminum-20% gallium, 80%Al-10%Ga10%In, 75%Al-5%Ga-5%Zn-5%Bi-5%Sn-5%Mg, and 90%Al-2.5%Ga-2.5%Zn-2.5%Bi2.5%Sn. Another example is 99.8%Al-0.1%In-0.1%Ga.

[0042] In another embodiment of the present disclosure, the dissolvable metal may include an aluminum alloy that is alloyed with copper, with manganese, with silicon, with magnesium, with iron, with lithium, carbon, and/or with zinc. Example of aluminum alloy with copper is a 2024 aluminum which includes 92%Al-.5%Si-.5%Fe-4.5%Cu-.5%Mn-1.5%Mg,l%Cr-.25%Zn-.15%Ti.

[0043] In yet another embodiment of the present disclosure, the dissolvable metal may include a magnesium alloy that is alloyed with zinc, aluminum, yttrium, copper, nickel, cerium,

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PCT/US2015/061365 and/or iron. Example of a magnesium alloy that is alloyed with aluminum is AZ91 magnesium which includes 90.8%Mg-8.25%Al-0.63%Zn-0.035%Si-0.22%Mn. Another example of a magnesium alloy that is alloyed with zinc is ZK61 which includes 95%Mg-5%Zn-.3%Zr.

[0044] Magnesium alloys may include at least one other ingredient besides the magnesium. The other ingredients can be selected from one or more metals, one or more nonmetals, or a combination thereof. Suitable metals that may be alloyed with magnesium include, but are not limited to, lithium, sodium, potassium, rubidium, cesium, beryllium, calcium, strontium, barium, aluminum, gallium, indium, tin, thallium, lead, bismuth, scandium, titanium, vanadium, chromium, manganese, iron, cobalt, nickel, copper, zinc, yttrium, zirconium, niobium, molybdenum, ruthenium, rhodium, palladium, praseodymium, silver, lanthanum, hafnium, tantalum, tungsten, terbium, rhenium, osmium, iridium, platinum, gold, neodymium, gadolinium, erbium, oxides of any of the foregoing, and any combinations thereof.

[0045] Suitable non-metals that may be alloyed with magnesium include, but are not limited to, graphite, carbon, silicon, boron nitride, and combinations thereof. The carbon can be in the form of carbon particles, fibers, nanotubes, fullerenes, and any combination thereof. The graphite can be in the form of particles, fibers, weaves, graphene, and any combination thereof. The magnesium and its alloyed ingredient(s) may be in a solid solution and not in a partial solution or a compound where inter-granular inclusions may be present. In some embodiments, the magnesium and its alloyed ingredient(s) may be uniformly distributed throughout the magnesium alloy but, as will be appreciated, some minor variations in the distribution of particles of the magnesium and its alloyed ingredient(s) can occur. In other embodiments, the magnesium alloy is a sintered construction.

[0046] In some embodiments, the magnesium alloy may have a yield stress in the range of from about 10,000 pounds per square inch (psi) to about 50,000 psi, encompassing any value and subset therebetween. For example, in some embodiments, the magnesium alloy may have a yield stress of about 20,000 psi to about 30,000 psi, or about 30,000 psi to about 40,000 psi, or about 40,000 psi to about 50,000 psi, encompassing any value and subset therebetween.

[0047] Suitable aluminum alloys may include alloys having aluminum at a concentration in the range of from about 40% to about 99% by weight of the aluminum alloy, encompassing any value and subset therebetween. For example, suitable aluminum alloys may have aluminum

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PCT/US2015/061365 concentrations of about 40% to about 50%, or about 50% to about 60%, or about 60% to about 70%, or about 70% to about 80%, or about 80% to about 90%, or about 90% to about 99% by weight of the aluminum alloy, encompassing any value and subset therebetween.

[0048] The aluminum alloys may be wrought or cast aluminum alloys and comprise at least one other ingredient besides the aluminum. The other ingredients can be selected from one or more any of the metals, non-metals, and combinations thereof described above with reference to magnesium alloys, with the addition of the aluminum alloys additionally being able to comprise magnesium.

[0049] The degradable or dissolvable metal for use in the embodiments described herein may also include micro-galvanic metals or materials, such as, for example, solution-structured galvanic materials. An example of a solution-structured galvanic material is a magnesium alloy containing zinc (Zn), where different domains within the alloy contain different percentages of Zn. This leads to a galvanic coupling between these different domains, which cause microgalvanic corrosion and degradation. Micro-galvanically corrodible magnesium alloys could also be solution structured with other elements such as zinc, aluminum, manganese, nickel, cobalt, calcium, iron, carbon, tin, silver, copper, titanium, rare earth elements, etc. Examples of solution-structured micro-galvanically-corrodible magnesium alloys include ZK60, which includes about 4% to about 7% zinc, about 0% to about 1% zirconium, about 0% to about 3% other, and balance magnesium; AZ80, which includes 7% to 10% aluminum, 0% to 1% zinc, 0% to 1% manganese, 3% other, and balance magnesium; and AZ31, which includes 2% to 5% aluminum, 0% to 2% zinc, 0% to 1% manganese, 3% other, and the balance magnesium. Each of these examples is % by weight of the metal alloy. In some embodiments, “other” may include unknown materials, impurities, additives, any elements on the periodic table, and any combination thereof.

[0050] The dispersed reinforcement material may include ceramic components or particles. The ceramic components may be constructed from zirconia (including zircon), alumina (including fused alumina, chrome-alumina, and emery), carbide (including tungsten carbide, silicon carbide, titanium carbide, and boron carbide), boride (including boron nitride, osmium diboride, rhenium boride, titanium boride, and tungsten boride), nitride (silicon nitride and aluminum nitride), synthetic diamond, and silica. The ceramic may be an oxide (like the alumina

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PCT/US2015/061365 and zirconia) or a non-oxide (like the carbide, nitride, and boride). The dispersed reinforcement material may include e.g., a particle, a fiber, a weave, a nugget, and the like.

[0051] In an alternative embodiment of the present disclosure, the dissolvable metal matrix composite may be considered to be a cermet.

[0052] In another alternative embodiment of the present disclosure, a hardened metal may be used instead of the ceramic. A medium or high carbon steel with a carbon content in excess of 0.25% could be used. A maraging steel, a stainless steel, Inconel, tool steel, titanium, nickel, tungsten, chromium, or alloys of any of these materials may also be used.

[0053] In a preferred embodiment of the present disclosure, the dissolvable metal matrix composite includes a dispersed reinforcement material and a dissolvable metal wherein the dispersed reinforcement material may include tungsten carbide ceramic with graphite particles in a mold, and the dissolvable metal may include aluminum. As the mold is infiltrated with high pressure liquid aluminum, the aluminum alloy will be a degradable alloy that binds together the tungsten carbide and the graphite particles. Upon exposure to an electrolyte, the graphite will galvanically react with the aluminum, and the aluminum will disappear, leaving behind a ceramic dust and graphite dust. This degradable or dissolvable metal matrix composite is best suited for slip buttons on dissolvable frac plugs as well as for baffle seat on sliding sleeves. The dissolvable metal matrix composite of the present disclosure fulfills the need for the slip buttons to have the sharpness and the baffle seat to have the erosion resistance while facilitating easier and cost efficient degradation of the slip buttons and baffle seat in the wellbore system.

[0054] In another preferred embodiment of the present disclosure, the dissolvable metal matrix composite may include about 20 to about 95 weight percent of the dispersed reinforcement material, and may be most typically about 50 to about 70 weight percent of the dispersed reinforcement material. The dissolvable metal matrix composite may include up to about 95 weight percent of the dissolvable metal.

[0055] In yet another preferred embodiment of the present disclosure, the dissolvable metal matrix composite may include a dissolvable metal that exhibits a degradation rate in an amount greater than 10 mg/cm per hour at a temperature of 200°F (93.3°C) while exposed to a 15% potassium chloride (KCI) solution.

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PCT/US2015/061365 [0056] In another embodiment of the present disclosure, the degradation rate of the dissolvable metal may be somewhat slower, such that the dissolvable metal exhibits a degradation rate in an amount of less than about 10 mg/cm per hour at 200°F (93.3°C) in 15% KCI solution. In other embodiments, the dissolvable metal exhibits a degradation rate such that lower than about 10% but greater than 1% of its total mass is lost per day at 200°F (93.3°C) in 15% KCI solution.

[0057] The degradation of the dissolvable metal may be in the range of from about 1 day to about 120 days, encompassing any value or subset therebetween. For example, the degradation may be about 5 days to about 10 days, or about 10 days to about 20 days, or about 20 days to about 30 days, or about 30 days to about 120 days, encompassing any value and subset therebetween. Each of these values representing the degradable metal may depend on a number of factors including, but not limited to, the type of degradable or dissolvable metal, the wellbore environment, and the like.

[0058] According to an embodiment of the present disclosure, the dissolvable metal matrix composite may include at least one tracer. The tracer(s) can be, without limitation, radioactive, chemical, electronic, physical, or acoustic. A tracer can be useful in determining real-time information on the rate of dissolution dissolvable metal. For example, a dissolvable metal containing a tracer, upon dissolution can be flowed through the wellbore and towards the wellhead or into the subterranean formation. By being able to monitor the presence of the tracer, workers at the surface can make on-the-fly decisions that can affect the rate of dissolution of the remaining dissolvable metal. Such decisions might include to increase or decrease the concentration of the electrolyte or to increase or decrease the pH of the electrolyte.

[0059] Additionally, the dissolution of the dissolvable metal may also be accelerated by hydraulically fracturing with an acid or otherwise augmenting the wellbore fluid with an acid. For example, all or a portion of the outer surface of a given component of the wellbore isolation device may be treated or coated with a substance configured to enhance degradation of the dissolvable metal Such a treatment or coating may be configured to remove a protective coating or treatment or otherwise accelerate the degradation of the dissolvable metal. An example is a galvanically-corroding metal coated with a layer of polyglycolic acid (PGA). In this example,

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PCT/US2015/061365 the PGA would undergo hydrolysis and cause the surrounding fluid to become more acidic, which would accelerate the degradation of the underlying dissolvable metal.

[0060] Referring to FIG. 1, illustrated is a well system 100 that may embody or otherwise employ one or more principles of the present disclosure, according to one or more embodiments. As illustrated, the well system 100 may include a service rig 102 (also referred to as a “derrick”) that is positioned on the earth’s surface 104 and extends over and around a wellbore 106 that penetrates a subterranean formation 108. The service rig 102 may be a drilling rig, a completion rig, a workover rig, or the like. In some embodiments, the service rig 102 may be omitted and replaced with a standard surface wellhead completion or installation, without departing from the scope of the disclosure. While the well system 100 is depicted as a landbased operation, it will be appreciated that the principles of the present disclosure could equally be applied in any sea-based or sub-sea application where the service rig 102 may be a floating platform or sub-surface wellhead installation, as generally known in the art.

[0061] The wellbore 106 may be drilled into the subterranean formation 108 using any suitable drilling technique and may extend in a substantially vertical direction away from the earth’s surface 104 over a vertical wellbore portion 110. At some point in the wellbore 106, the vertical wellbore portion 110 may deviate from vertical relative to the earth’s surface 104 and transition into a substantially horizontal wellbore portion 112, although such deviation is not required. That is, the wellbore 106 may be vertical, horizontal, or deviated, without departing from the scope of the present disclosure. In some embodiments, the wellbore 106 may be completed by cementing a string of casing 114 within the wellbore 106 along all or a portion thereof. As used herein, the term “casing” refers not only to casing as generally known in the art, but also to borehole liner, which comprises tubular sections coupled end to end but not extending to a surface location. In other embodiments, however, the string of casing 114 may be omitted from all or a portion of the wellbore 106 and the principles of the present disclosure may equally apply to an “open-hole” environment.

[0062] The well system 100 may further include a wellbore isolation device 116 that may be conveyed into the wellbore 106 on a conveyance 118 (also referred to as a “tool string”) that extends from the service rig 102. The wellbore isolation device 116 may include or otherwise comprise any type of casing or borehole isolation device known to those skilled in the

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PCT/US2015/061365 art including, but not limited to, a frac plug, a deployable baffle, a wellbore packer, a wiper plug, a cement plug, or any combination thereof. The conveyance 118 that delivers the wellbore isolation device 116 downhole may be, but is not limited to, wireline, slickline, an electric line, coiled tubing, drill pipe, production tubing, or the like.

[0063] The wellbore isolation device 116 may be conveyed downhole to a target location (not shown) within the wellbore 106. At the target location, the wellbore isolation device may be actuated or “set” to seal the wellbore 106 and otherwise provide a point of fluid isolation within the wellbore 106. In some embodiments, the wellbore isolation device 116 is pumped to the target location using hydraulic pressure applied from the service rig 102 at the surface 104. In such embodiments, the conveyance 118 serves to maintain control of the wellbore isolation device 116 as it traverses the wellbore 106 and provides the necessary power to actuate and set the wellbore isolation device 116 upon reaching the target location. In other embodiments, the wellbore isolation device 116 freely falls to the target location under the force of gravity to traverse all or part of the wellbore 106.

[0064] It will be appreciated by those skilled in the art that even though FIG. 1 depicts the wellbore isolation device 116 as being arranged and operating in the horizontal portion 112 of the wellbore 106, the embodiments described herein are equally applicable for use in portions of the wellbore 106 that are vertical, deviated, or otherwise slanted. It should also be noted that a plurality of wellbore isolation devices 116 may be placed in the wellbore 106. In some embodiments, for example, several (e.g., six or more) wellbore isolation devices 116 may be arranged in the wellbore 106 to divide the wellbore 106 into smaller intervals or “zones” for hydraulic stimulation.

[0065] Referring now to FIG. 2, with continued reference to FIG. 1, illustrated is a crosssectional view of an exemplary wellbore isolation device 200 that may employ one or more of the principles of the present disclosure, according to one or more embodiments. The wellbore isolation device 200 may be similar to or the same as the wellbore isolation device 116 of FIG. 1. Accordingly, the wellbore isolation device 200 may be configured to be extended into and seal the wellbore 106 at a target location, and thereby prevent fluid flow past the wellbore isolation device 200 for wellbore completion or stimulation operations. In some embodiments, as illustrated, the wellbore 106 may be lined with the casing 114 or another type of wellbore liner or

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PCT/US2015/061365 tubing in which the wellbore isolation device 200 may suitably be set. In other embodiments, however, the casing 114 may be omitted and the wellbore isolation device 200 may instead be set or otherwise deployed in an uncompleted or “open-hole” environment.

[0066] The wellbore isolation device 200 is generally depicted and described herein as a hydraulic fracturing plug or “frac” plug. It will be appreciated by those skilled in the art, however, that the principles of this disclosure may equally apply to any of the other aforementioned types of casing or borehole isolation devices, without departing from the scope of the disclosure. Indeed, the wellbore isolation device 200 may be any of a frac plug, a bridge plug, a wellbore packer, a deployable baffle, a ball and seat, a cement plug, or any combination thereof in keeping with the principles of the present disclosure.

[0067] As illustrated, the wellbore isolation device 200 may include a ball cage 204 extending from or otherwise coupled to the upper end of a mandrel 206. A sealing ball 208 (e.g., a frac ball) is disposed in the ball cage 204 and the mandrel 206 defines a longitudinal central flow passage 210. The mandrel 206 also defines a ball seat 212 at its upper end. One or more spacer rings 214 (one shown) may be secured to the mandrel 206 and otherwise extend thereabout. The spacer ring 214 provides an abutment, which axially retains a set of upper slips 216a that are also positioned circumferentially about the mandrel 206. As illustrated, a set of lower slips 216b may be arranged distally from the upper slips 216a. The lower slips 216b may include a lower slip button 215b wherein the slip button 215b may include a sharp edge 217b which is configured to bite into the casing 114. The upper slips 216a may include an upper slip button 215a wherein the slip button 215a may include a sharp edge 217a which is configured to bite into the casing 114. In other embodiments, the sealing ball 208 may be dropped into the conveyance 118 (FIG. 1) to land on top of the wellbore isolation device 200 rather than being carried within the ball cage 204.

[0068] In an embodiment of the present disclosure, the slip buttons 215a and 215b may be composed of the dissolvable (or degradable) metal matrix composite in accordance with the principles of the present disclosure, thereby allowing an easier and cost efficient disposal of the slip buttons 215a and 215b in the wellbore.

[0069] One or more slip wedges 218 (shown as upper and lower slip wedges 218a and 218b, respectively) may also be positioned circumferentially about the mandrel 206, and a

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PCT/US2015/061365 packer assembly consisting of one or more expandable or inflatable packer elements 220 may be disposed between the upper and lower slip wedges 218a,b and otherwise arranged about the mandrel 206. It will be appreciated that the particular packer assembly depicted in FIG. 2 is merely representative as there are several packer arrangements known and used within the art. For instance, while three packer elements 220 are shown in FIG. 2, the principles of the present disclosure are equally applicable to wellbore isolation devices that employ more or less than three packer elements 220, without departing from the scope of the disclosure.

[0070] A mule shoe 222 may be positioned at or otherwise secured to the mandrel 206 at its lower or distal end. As will be appreciated, the lower most portion of the wellbore isolation device 200 need not be a mule shoe 222, but could be any type of section that serves to terminate the structure of the wellbore isolation device 200, or otherwise serves as a connector for connecting the wellbore isolation device 200 to other tools, such as a valve, tubing, or other downhole equipment. In some embodiments of the present disclosure, at least a portion of the mandrel 206 (such as the interior surface) or at least a portion of the spacer ring 214 or mule shoe 222 (such as the exterior surface) may be composed of the dissolvable (or degradable) metal matrix composite in accordance with the principles of the present disclosure, thereby allowing more erosion resistance or abrasion resistance of the component.

[0071] In some embodiments, a spring 224 may be arranged within a chamber 226 defined in the mandrel 206 and otherwise positioned coaxially with and fluidly coupled to the central flow passage 210. At one end, the spring 224 biases a shoulder 228 defined by the chamber 226 and at its opposing end the spring 224 engages and otherwise supports the sealing ball 208. The ball cage 204 may define a plurality of ports 230 (three shown) that allow the flow of fluids therethrough, thereby allowing fluids to flow through the length of the wellbore isolation device 200 via the central flow passage 210.

[0072] As the wellbore isolation device 200 is lowered into the wellbore 106, the spring 224 prevents the sealing ball 208 from engaging the ball seat 212. As a result, fluids may pass through the wellbore isolation device 200; i.e., through the ports 230 and the central flow passage 210. The ball cage 204 retains the sealing ball 208 such that it is not lost during translation into the wellbore 106 to its target location. Once the wellbore isolation device 200 reaches the target location, a setting tool (not shown) of a type known in the art can be used to

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PCT/US2015/061365 move the wellbore isolation device 200 from its unset position (shown in FIG. 2) to a set position. The setting tool may operate via various mechanisms to anchor the wellbore isolation device 200 in the wellbore 106 including, but not limited to, hydraulic setting, mechanical setting, setting by swelling, setting by inflation, and the like. In the set position, the slips 216a,b and the packer elements 220 expand and engage the inner walls of the casing 114.

[0073] When it is desired to seal the wellbore 106 at the target location with the wellbore isolation device 200, fluid is injected into the wellbore 106 and conveyed to the wellbore isolation device 200 at a predetermined flow rate that overcomes the spring force of the spring 224 and forces the sealing ball 208 downwardly until it sealingly engages the ball seat 212. When the sealing ball 208 is engaged with the ball seat 212 and the packer elements 220 are in their set position, fluid flow past or through the wellbore isolation device 200 in the downhole direction is effectively prevented. At that point, completion or stimulation operations may be undertaken by injecting a treatment or completion fluid into the wellbore 106 and forcing the treatment/completion fluid out of the wellbore 106 and into a subterranean formation above the wellbore isolation device 200.

[0074] Following completion and/or stimulation operations, the wellbore isolation device 200 must be removed from the wellbore 106 in order to allow production operations to effectively occur without being excessively hindered by the emplacement of the wellbore isolation device 200. According to the present disclosure, various components of the wellbore isolation device 200 may be made of one or more degrading or dissolving materials, e.g., dissolvable metal matrix composite.

[0075] As at least the mandrel 206 (and, in some embodiments, at least the sealing ball 208, or any other component) are made of dissolvable metal matrix composite, it may be desirable that the wellbore isolation device 200 have a greater flow area or flow capacity through and/or around the wellbore isolation device 200. According to the present disclosure, in some embodiments the wellbore isolation device 200 may exhibit a large flow area or flow capacity through and/or around the wellbore isolation device 200 so that it does not unreasonably impede, obstruct, or inhibit production operations while the wellbore isolation device 200 degrades. As a result, production operations may be undertaken while the wellbore isolation device 200

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PCT/US2015/061365 proceeds to dissolve and/or degrade, and without creating a significant pressure restriction within the wellbore 106.

[0076] According to the present disclosure, at least the mandrel 206 (and, in some embodiments, at least the sealing ball 208, or any other component) may be made of or otherwise include a dissolvable metal matrix composite which includes a dissolvable metal that is configured to degrade or dissolve within a wellbore environment. In other embodiments, other components of the wellbore isolation device 200 may also be made of or otherwise comprise a dissolvable metal including, but not limited to, the upper and lower slips 216a,b, the upper and lower slip wedges 218a,b, and the mule shoe 222.

[0077] In addition to the foregoing, other components of the wellbore isolation device 200 that may be made of or otherwise comprise a dissolvable metal to include extrusion limiters and shear pins associated with the wellbore isolation device 200.

[0078] FIG. 3 shows an example of a sliding sleeve 300 that employs metal matrix composite in accordance with the present disclosure. The sliding sleeve 300 may include baffle portion 310 on top and sliding sleeve portion 315 on bottom. The sliding sleeve 300 may further include dissolvable metal matrix composite that degrades in a wellbore fluid. The dissolvable metal matrix composite includes dissolvable metal and a dispersed reinforcement material. The dispersed reinforcement material provides sharpness and the erosion resistance needed in a baffle (or baffle seat) while the metal provides toughness. The erosion resistance also provides resistance to the proppant and flow that passes by the baffles. When the metal dissolves in a wellbore fluid, all that remains is, e.g., the ceramic dust. The dissolvable metal matrix composite enables dissolvable baffle or baffle seats which in turn facilitates easier removal of the baffle from the wellbore system.

[0079] The degradable material may be configured to be encapsulated in a metallic or polymeric coating. The coating prevents dissolution until the coating is removed. This prevents premature degradation. The coating may be removed by erosion during the hydraulic fracturing operation. There may be different diameter baffles at different locations in the wellbore.

[0080] The sliding sleeve 300 may be used to block access to a flow port. The sliding sleeve 300 may be held in place at the flow port by a shear pin. When a ball 325 lands on the

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PCT/US2015/061365 sliding sleeve portion 315, the hydraulic force breaks the shear pin and the siding sleeve portion 315 shifts towards the right. The flow ports are now open and the frac can commence.

[0081] As shown in FIG. 3, the baffle 310 where the ball 325 has landed is the erosion resistant metal matrix composite. The sliding sleeve 300 may include a supporting component 320 that supports the baffle 310. The supporting component 320 may include a degradable material.

[0082] In alternative embodiments, the baffle 310 and the supporting component 320 may be configured as a single piece and composed entirely of the degradable metal matrix composite.

[0083] FIG. 4 shows an example of a metal matrix composite that is constructed in accordance with the principles of the present disclosure. The dissolvable or degradable metal matrix composite of the present disclosure includes dissolvable metal and a dispersed reinforcement material wherein the reinforcement material is a ceramic or a hardened metal.

[0084] As shown in FIG. 4, a mold may be filled with reinforcement material and then infiltrated with dissolvable metal (e.g., aluminum alloy or magnesium alloy). The dissolvable metal then glues all the reinforcement material together (as shown in e.g., FIG. 5). Any component or part of the downhole component may include such mold. The dissolvable metal may degrade in a wellbore fluid under certain conditions. In one embodiment of the present disclosure, the dissolvable metal matrix composite includes connecting together an element that is and not degradable (e.g., ceramic or hardened metal) with an element that is degradable (e.g., dissolvable metal) with a degradable metal glue. The rate of degradation of the dissolvable metal may depend on a number of factors including, but not limited to, the type of dissolvable metal selected and the conditions of the wellbore environment.

[0085] Referring to FIGS. 1-2 and 4 together, the degradable or dissolvable metal matrix composite for use in forming components of the wellbore isolation device 200 may degrade, at least in part, in the presence of an aqueous fluid (e.g., a treatment fluid, wellbore fluid, acid, chemical, and the like). The aqueous fluid that may degrade the dissolvable metal may include, but is not limited to, fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), seawater, or combinations thereof. Accordingly, the aqueous fluid may comprise ionic salts that trigger galvanic corrosion. The aqueous fluid may

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PCT/US2015/061365 come from the wellbore 106 itself /i.e., the subterranean formation) or may be introduced by a wellbore operator.

[0086] The following clauses represent additional embodiments of the disclosure:

Clause 1. A component for a downhole tool comprising:

a dissolvable metal matrix composite, wherein the dissolvable metal matrix composite comprises:

a dissolvable metal that is configured to partially or wholly dissolve when in contact with the electrolyte; and a dispersed reinforcement material that is at least one of: a ceramic or a hardened metal.

Clause 2. The component according to Clause 1, wherein the component is at least one of mandrel, a sealing ball, a slip, a slip button, a baffle seat, or a shear pin.

Clause 3. The component according to Clauses 1 or 2, wherein the downhole tool comprises a wellbore isolation device that is selected from the group consisting of a frac plug, a wellbore packer, a deployable baffle, and any combination thereof.

Clause 4. The component according to Clauses 1 or 2, wherein the dissolvable metal comprises at least one of aluminum alloy, magnesium alloy, zinc alloy, bismuth alloy, tin alloy, or any combination thereof.

Clause 5. The component according to Clause 4, wherein the dissolvable metal further comprises the aluminum alloy that is alloyed with indium or gallium wherein the indium or gallium acts as a depassivating agent and prevents formation of a protective passivation layer on a surface of the aluminum alloy.

Clause 6. The component according to Clause 5, wherein the aluminum and the gallium is alloyed together in a ratio that comprises at least one of the following: 80% Al-20% Ga, 80%Al10%Ga-10%In, 75%Al-5%Ga-5%Zn-5%Bi-5%Sn-5%Mg, 90%Al-2.5%Ga-2.5%Zn-2.5%Bi2.5%Sn, 99.8%Al-0.1%In-0.1%Ga.

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Clause 7. The component according to Clause 1, wherein the dissolvable metal further comprises at least one of the following: the magnesium alloy that is alloyed with zinc, aluminum, zirconium, yttrium, copper, nickel, or with iron.

Clause 8. The component according to Clause 7 further comprises at least one of the following ratio: about 4% to 7% zinc, about 0% to 1% zirconium, and balance magnesium, or 7% to 10% aluminum, 0% to 1% zinc, 0% to 1% manganese, and balance magnesium, or 2% to 5% aluminum, 0% to 2% zinc, 0% to 1% manganese, and balance magnesium.

Clause 9. The component according to Clause 1, wherein the ceramic comprises at least one of: zirconia (including zircon), alumina (including fused alumina, chrome-alumina, and emery), carbide (including tungsten carbide, silicon carbide, titanium carbide, and boron carbide), boride (including boron nitride, osmium diboride, rhenium boride, titanium boride, and tungsten boride), nitride (silicon nitride and aluminum nitride), synthetic diamond, silica, and any combination thereof.

Clause 10. The component according to Clause 9, wherein the ceramic comprises an oxide or a non-oxide.

Clause 11. The component according to Clauses 9 or 10, wherein the hardened metal comprises at least one of: medium or high carbon steel with a carbon content in excess of 0.25%, a maraging steel, stainless steel, Inconel, tool steel, titanium, nickel, tungsten, chromium, or any combination thereof.

Clause 12. The component according to Clause 1, wherein the dissolvable metal is alloyed with at least one of copper, nickel, iron, or any combination thereof, which in turn creates inclusions that have a galvanic potential that accelerates dissolution of the dissolvable metal.

Clause 13. The component according to Clause 1, wherein a portion of the ceramic is replaced with a cathodic component which in turn creates a galvanic potential with the dissolvable metal.

Clause 14. The component according to Clause 13, wherein the cathodic component comprises at least one of a nugget, a spheroid, a silver, a fiber, a weave, or any combination thereof.

Clause 15. A method of removing a component for a wellbore isolation device comprising:

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PCT/US2015/061365 contacting or allowing the component to come in contact with an electrolyte, the component consists essentially of:

a dissolvable metal and a dispersed reinforcement material, the dissolvable metal:

(A) is a metal or a metal alloy, (B) forms a matrix of a portion of the wellbore isolation device, and (C) partially or wholly dissolves when an electronically conductive path exists between the dissolvable metal and the dispersed reinforcement material and at least a portion of the dissolvable metal is in contact with electrolyte, and the dispersed reinforcement material comprises at least one of:

(A) a ceramic; or (B) a hardened metal.

Clause 16. The method according to Clause 15, wherein the wellbore isolation device is a ball and a seat, a plug, a bridge plug, a wiper plug, a packer, or a plug for a base pipe.

Clause 17. The method according to Clauses 15 or 16, wherein the wellbore isolation device is capable of restricting or preventing fluid flow between a first wellbore interval and a second wellbore interval.

Clause 18. The method according to Clauses 15 or 16, further comprising the step of placing the wellbore isolation device into a portion of the wellbore, wherein the step of placing is performed prior to the step of contacting or allowing the wellbore isolation device to come in contact with the electrolyte.

Clause 19. The method according to Clauses 15 or 16, further comprising the step of removing all or a portion of the dissolved dissolvable metal, wherein the step of removing is performed after the step of allowing at least the portion of the dissolvable metal to dissolve.

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Clause 20. A method of removing a component for a downhole tool comprising introducing the downhole tool into a wellbore, the downhole tool comprising a wellbore isolation device that provides a plurality of components including a mandrel, a packer element, and a sealing ball, the mandrel defines a central flow passage that allows fluid flow in at least one direction through the wellbore isolation device, at least a portion of the plurality of components comprises a dissolvable metal matrix component and the dissolvable metal matrix component comprises a dissolvable metal, and dispersed reinforcement material;

anchoring the downhole tool within the wellbore at a target location;

performing at least one downhole operation; and dissolving the dissolvable metal upon exposure to an electrolyte in a wellbore environment.

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Claims

CLAIMS What is claimed is:

1 of 5

FIG. 1

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1. A component for a downhole tool comprising:

2 of 5

204

230 .22-4

220

114

214 217 a 21 SB 106

20»

206

210

216b

FIG. 2

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2. The component according to claim 1, wherein the component is at least one of mandrel, a sealing ball, a slip, a slip button, a baffle seat, or a shear pin.

3 of 5

FIG. 3

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3. The component according to claim 1, wherein the downhole tool comprises a wellbore isolation device that is selected from the group consisting of a frac plug, a wellbore packer, a deployable baffle, and any combination thereof.

4 of 5

FIG. 4

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4. The component according to claim 1, wherein the dissolvable metal comprises at least one of aluminum alloy, magnesium alloy, zinc alloy, bismuth alloy, tin alloy, or any combination thereof.

5. The component according to claim 4, wherein the dissolvable metal further comprises the aluminum alloy that is alloyed with indium or gallium wherein the indium or gallium acts as a depassivating agent and prevents formation of a protective passivation layer on a surface of the aluminum alloy.

6. The component according to claim 5, wherein the aluminum and the gallium is alloyed together in a ratio that comprises at least one of the following: 80% Al-20% Ga, 80%Al-10%Ga10%In, 75%Al-5%Ga-5%Zn-5%Bi-5%Sn-5%Mg, 90%Al-2.5%Ga-2.5%Zn-2.5%Bi-2.5%Sn, 99.8%A1-0.1 %In-0.1 %Ga.

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7. The component according to claim 1, wherein the dissolvable metal further comprises at least one of the following: the magnesium alloy that is alloyed with zinc, aluminum, zirconium, yttrium, copper, nickel, or with iron.

8. The component according to claim 7 further comprises at least one of the following ratio: about 4% to 7% zinc, about 0% to 1% zirconium, and balance magnesium, or 7% to 10% aluminum, 0% to 1% zinc, 0% to 1% manganese, and balance magnesium, or 2% to 5% aluminum, 0% to 2% zinc, 0% to 1% manganese, and balance magnesium.

9. The component according to claim 1, wherein the ceramic comprises at least one of: zirconia (including zircon), alumina (including fused alumina, chrome-alumina, and emery), carbide (including tungsten carbide, silicon carbide, titanium carbide, and boron carbide), boride (including boron nitride, osmium diboride, rhenium boride, titanium boride, and tungsten boride), nitride (silicon nitride and aluminum nitride), synthetic diamond, silica, and any combination thereof.

10. The component according to claim 9, wherein the ceramic comprises an oxide or a nonoxide.

11. The component according to claim 1, wherein the hardened metal comprises at least one of: medium or high carbon steel with a carbon content in excess of 0.25%, a maraging steel, stainless steel, Inconel, tool steel, titanium, nickel, tungsten, chromium, or any combination thereof.

12. The component according to claim 1, wherein the dissolvable metal is alloyed with at least one of copper, nickel, iron, or any combination thereof, which in turn creates inclusions that have a galvanic potential that accelerates dissolution of the dissolvable metal.

13. The component according to claim 1, wherein a portion of the ceramic is replaced with a cathodic component which in turn creates a galvanic potential with the dissolvable metal.

14. The component according to claim 13, wherein the cathodic component comprises at least one of a nugget, a spheroid, a silver, a fiber, a weave, or any combination thereof.

15. A method of removing a component for a wellbore isolation device comprising:

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a dissolvable metal and a dispersed reinforcement material, the dissolvable metal (A) is a metal or a metal alloy, (B) forms a matrix of a portion of the wellbore isolation device, and (C) partially or wholly dissolves when an electronically conductive path exists between the dissolvable metal and the dispersed reinforcement material and at least a portion of the dissolvable metal is in contact with electrolyte, and the dispersed reinforcement material comprises at least one of:

(D) a ceramic, or (E) a hardened metal.

16. The method according to claim 15, wherein the wellbore isolation device is a ball and a seat, a plug, a bridge plug, a wiper plug, a packer, or a plug for a base pipe.

17. The method according to claim 15, wherein the wellbore isolation device is capable of restricting or preventing fluid flow between a first wellbore interval and a second wellbore interval.

18. The method according to claim 15, further comprising the step of placing the wellbore isolation device into a portion of the wellbore, wherein the step of placing is performed prior to the step of contacting or allowing the wellbore isolation device to come in contact with the electrolyte.

19. The method according to Claim 15, further comprising the step of removing all or a portion of the dissolved dissolvable metal, wherein the step of removing is performed after the step of allowing at least the portion of the dissolvable metal to dissolve.

20. A method of removing a component for a downhole tool comprising

WO 2017/086955

PCT/US2015/061365 introducing the downhole tool into a wellbore, the downhole tool comprising a wellbore isolation device that provides a plurality of components including a mandrel, a packer element, and a sealing ball, the mandrel defines a central flow passage that allows fluid flow in at least one direction through the wellbore isolation device, at least a portion of the plurality of components comprises a dissolvable metal matrix component and the dissolvable metal matrix component comprises a dissolvable metal, and dispersed reinforcement material;

anchoring the downhole tool within the wellbore at a target location;

WO 2017/086955

PCT/US2015/061365

5 of 5

FIG. 5