Downhole tool including a sacrificial conductive protection layer positioned about a material to be protected

Abstract

Provided is a downhole tool, a well system, and a method. The downhole tool, in one aspect, includes a protective housing, as well as a sacrificial conductive protection layer sealing against the protective housing, the protective housing and sacrificial conductive protection layer forming a sealed chamber. The downhole tool, in this aspect, further includes material to be protected disposed within the sealed chamber, and a trigger device positioned proximate the sacrificial conductive protection layer. In one aspect, the trigger device includes a positive electrode coupled to the sacrificial conductive protection layer and a negative electrode coupled to a separate downhole conductive layer, the trigger device configured to apply a voltage to the sacrificial conductive protection layer to trigger a corrosion thereof based upon a triggering event.

Description

CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims the benefit of U.S. Provisional Application Ser. No. 63 / 781,649, filed on Apr. 1, 2025, entitled “DOWNHOLE TOOL INCLUDING A TRIGGER DEVICE CONFIGURED TO APPLY A VOLTAGE TO A SACRIFICIAL CONDUCTIVE PROTECTION LAYER TO TRIGGER A CORROSION THEREOF BASED UPON A TRIGGERING EVENT,” commonly assigned with this application and incorporated herein by reference in its entirety.BACKGROUND

[0002] Wellbores are drilled into the earth for a variety of purposes including accessing hydrocarbon bearing formations. A variety of downhole tools may be used within a wellbore in connection with accessing and extracting such hydrocarbons. Throughout the process, it may become necessary to isolate sections of the wellbore for a number of different reasons, such as fluid control, production optimization, well integrity, etc. Downhole tools, such as frac plugs, bridge plugs, packers, and other suitable tools, may be used to isolate wellbore sections.

[0003] The aforementioned downhole tools are commonly run into the wellbore on a conveyance, such as a wireline, work string or production tubing. Such tools often have either an internal or external setting tool, which is used to set the downhole tool within the wellbore and hold the tool in place, and thus function as a wellbore anchor. The wellbore anchors typically include a plurality of slips, which extend outwards when actuated to engage and grip a casing within a wellbore or the open hole itself, and a sealing assembly, which can be made of rubber and extends outwards to seal off the flow of liquid around the downhole tool.BRIEF DESCRIPTION

[0004] Reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:

[0005] FIG. 1A illustrates a perspective view of a well system including an exemplary operating environment that the apparatuses, systems and methods disclosed herein may be employed;

[0006] FIG. 1B illustrates a zoomed in cross-sectional view of a portion of FIG. 1A;

[0007] FIGS. 2A through 2C illustrate Pourbaix diagrams for Mg, Al, and Zn, respectively;

[0008] FIG. 3 illustrates a galvanic series chart;

[0009] FIG. 4 illustrates one embodiment of a downhole tool designed, manufactured and / or operated according to one or more embodiments of the disclosure;

[0010] FIGS. 5A through 5D illustrate various different perspective views of different sacrificial conductive protection layers, as might be used with the downhole tool of FIG. 4;

[0011] FIGS. 6A through 6D illustrate different cross-sectional views of a downhole tool designed, manufactured and / or operated at different stages of use;

[0012] FIG. 7 illustrates one embodiment of a downhole tool designed, manufactured and / or operated according to one or more embodiments of the disclosure;

[0013] FIG. 8 illustrates one embodiment of a downhole tool designed, manufactured and / or operated according to one or more embodiments of the disclosure;

[0014] FIG. 9 illustrates one embodiment of a downhole tool designed, manufactured and / or operated according to one or more embodiments of the disclosure;

[0015] FIG. 10 illustrates one embodiment of a downhole tool designed, manufactured and / or operated according to one or more embodiments of the disclosure; and

[0016] FIG. 11 illustrates one embodiment of a downhole tool designed, manufactured and / or operated according to one or more embodiments of the disclosure.DETAILED DESCRIPTION

[0017] In the drawings and descriptions that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawn figures are not necessarily to scale. Certain features of the disclosure may be shown exaggerated in scale or in somewhat schematic form and some details of certain elements may not be shown in the interest of clarity and conciseness. The present disclosure may be implemented in embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results.

[0018] Unless otherwise specified, use of the terms “connect,”“engage,”“couple,”“attach,” or any other like 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. Furthermore, unless otherwise specified, use of the terms “up,”“upper,”“upward,”“uphole,”“upstream,” or other like terms shall be construed as generally toward the surface of the subterranean formation; likewise, use of the terms “down,”“lower,”“downward,”“downhole,”“downstream,” or other like terms shall be construed as generally toward the bottom, terminal end of a well, regardless of the wellbore orientation. Use of any one or more of the foregoing terms shall not be construed as denoting positions along a perfectly vertical axis. Additionally, unless otherwise specified, use of the term “subterranean formation” shall be construed as encompassing both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.

[0019] Various values and / or ranges are explicitly disclosed in certain embodiments herein. However, values / ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited. Similarly, values / ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited. In the same way, values / ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited. Similarly, an individual value disclosed herein may be combined with another individual value or range disclosed herein to form another range.

[0020] The term “approximately XYZ,” as used herein, means that it is within plus or minus 20percent of perfectly XYZ. The term “substantially XYZ,” as used herein, means that it is within plus or minus 10 percent of perfectly XYZ. The term “significantly XYZ,” as used herein, means that it is within plus or minus 5 percent of perfectly XYZ. The term “ideally XYZ,” as used herein, means that it is within plus or minus 1 percent of perfectly XYZ. The monicker “XYZ” could refer to parallel, perpendicular, alignment, or other relative features disclosed herein.

[0021] Turning to FIG. 1A, illustrated is a perspective view of a well system 100 including an exemplary operating environment that the apparatuses, systems and methods disclosed herein may be employed. For example, the well system 100 could use a downhole tool designed, manufactured and / or operated according to any of the embodiments, aspects, applications, variations, designs, etc. disclosed in the following paragraphs. The term downhole tool, as used herein and without limitation, includes frac plugs, bridge plugs, packers, and other tools for fluid isolation, as well as wellbore anchors, among any other downhole tool that may employ one or more inventive aspects of the disclosure.

[0022] The well system 100 illustrated in the embodiment of FIG. 1A includes a wellbore 120 extending through one or more subterranean formations 130. As those skilled in the art appreciate, the wellbore 120 may be fully cased, partially cased, or an open hole wellbore. In the illustrated embodiment of FIG. 1A, the wellbore 120 is partially cased, and thus includes a cased region 140 and an open hole region 145. The cased region 140, as is depicted, may employ casing 150 that is held into place by cement 160. Any type of casing 150 may be used and remain within the scope of the disclosure, including conductor casing, surface casing, intermediate casing, production casing, other liners, including production liners, etc..

[0023] The well system 100 illustrated in FIG. 1A may additionally include a downhole conveyance 170 deploying a downhole tool 180 within the wellbore 120. The downhole conveyance 170 can be, for example, tubing-conveyed, wireline, slickline, work string, or any other suitable means for conveying the downhole tool 180 into the wellbore 120. In one particular advantageous embodiment, the downhole conveyance 170 is American Petroleum Institute “API” pipe.

[0024] As shown in the zoomed in cross-sectional view of FIG. 1B, the downhole tool 180, in at least one embodiment, includes a material to be protected 185, as well as a sacrificial conductive protection layer 190 protecting and / or isolating the material to be protected 185 from undesirable fluids and / or solids. In the illustrated embodiment, the sacrificial conductive protection layer 190 is disposed on (e.g., directly on) the material to be protected 185, although other configurations are within the scope of the disclosure (e.g., as will be discussed below). Further to the embodiment of FIG. 1B, in one or more embodiments, a trigger device 195 may be positioned proximate the sacrificial conductive protection layer 190, the trigger device 195 for example configured to apply a voltage to the sacrificial conductive protection layer 190 to trigger a corrosion thereof based upon a triggering event, as discussed further below.

[0025] The present disclosure has recognized that certain features (e.g., referred to as “material(s) to be protected”) need protection and / or isolation from other features, whether from other fluids or solids (e.g., from other reactive fluids or solids), until such time there is a desire for the originally separated features to be able to come together. For example, expandable metal (e.g., as further understood below) and swell elastomers (e.g., as further understood below), among others, are often used to provide sealing and zonal isolation. Such materials, however, expand when exposed to wellbore fluids, and any premature exposure could interfere with the running-in-hole of the sealing and / or zonal isolation device, or alternatively could result in the sealing and / or zonal isolation device having insufficient expanding material to form a good seal (e.g., in the case of expandable metal). As a result, there is a desire to isolate and / or protect the material to be protected (e.g., from reactive fluids in one example embodiment) during run-in-hole and during wellbore cleanup (e.g., among others), but have the ability to initiate a triggering event that subsequently no longer isolates and / or protects the material to be protected from the other material. Accordingly, in at least one embodiment, the present disclosure envisions protecting the material to be protected with a sacrificial conductive protection layer, and at a subsequent point in time initiating a triggering event that triggers the corrosion (e.g., partial or full corrosion) of the sacrificial protection layer to expose the material to be protected to the feature it was previously isolated and / or protected from.

[0026] The mechanism for protecting the material to be protected using the sacrificial protection layer may take on many different forms. In at least one embodiment, the material to be protected comprises solids (e.g., as opposed to a liquid). For example, the material to be protected in this example embodiment is a piece of the material, regardless of shape (e.g., a tubular, a mandrel, a solid rod, etc.) having the sacrificial protection layer is disposed thereon. In at least one embodiment, the sacrificial conductive protection layer is disposed directly on the material to be protected, but in yet another embodiment one or more solid material layers are physically disposed between the sacrificial conductive protection layer and the material to be protected. In yet even another embodiment, the material to be protected is located in a cavity in or formed by a protective housing, and the sacrificial conductive protection layer seals against the protective housing to form a sealed chamber. In this embodiment, fluid (e.g., air or liquid) could be located in the sealed chamber surrounding the material to be protected.

[0027] Given the foregoing, the present disclosures has recognized that various different forms of electrochemistry may be used to trigger the corrosion of the sacrificial conductive protection layer to expose the material to be protected, for example based upon a triggering event. In one embodiment, the present disclosure has recognized that the application of certain voltages (e.g., provided via a power source, whether uphole or downhole) to the sacrificial conductive protection layer may be used to trigger the corrosion of the sacrificial conductive protection layer to expose the material to be protected. Accordingly, the applied voltage may be used to trigger a corrosion of the sacrificial conductive protection layer upon a triggering event.

[0028] Turning briefly to FIGS. 2A through 2C, illustrated are Pourbaix diagrams for Mg, Al, and Zn, respectively, which happen to be three materials (e.g., of many others) that the sacrificial conductive protection layer may comprise in one or more embodiments. FIGS. 2A through 2C illustrate the voltages required for various different pH values for each of the Mg, Al, and Zn to go between immunity and corrosion states. With reference to FIG. 2A, assuming a fixed pH value of 2 for the moment, the Mg would go from an immunity state to a corrosion state by applying greater than −2.6 volts. For the purpose of this analysis, the term “greater” means a value greater on a number scale (e.g., in this example, this would include −2.0 volts, −1.0 volts, 1.0 volts, 2.0 volts, etc.). With reference to FIG. 2B, assuming a fixed pH value of 2 for the moment, the Al would go from an immunity state to a corrosion state by applying greater than −1.8 volts. With reference to FIG. 2C, assuming a fixed pH value of 2 for the moment, the Zn would go from an immunity state to a corrosion state by applying greater than −1.0 volts. It should be noted that the same principle could be used with many other conductive materials that the sacrificial conductive protection layer may comprise. Accordingly, the present disclosure is not limited to just Mg, Al, and Zn sacrificial conductive protection layers, but could include others known in the art.

[0029] Given the foregoing, the present disclosure envisions positioning a trigger device proximate the sacrificial conductive protection layer, the trigger device configured to apply a voltage to the sacrificial conductive protection layer to trigger a corrosion thereof based upon a triggering event. The term “proximate,” as used herein with regard to the placement of the trigger device, means that the trigger device is located within 1000 m of the protective housing. In yet another embodiment, however, the trigger device is located within 100 m of the protective housing, if not withing 10 m of the protective housing, if not within 1 m of the protective housing, if not within 0.5 m of the protective housing, if not within 0.1 m of the protective housing. In at least one embodiment, the trigger device includes a positive electrode coupled to the sacrificial conductive protection layer and a negative electrode coupled to a separate downhole conductive layer. Out of an abundance of caution, in at least one embodiment a positive voltage may be applied to the sacrificial conductive protection layer, such that the sacrificial conductive protection layer spends at least part of its time as an anode of the circuit. The voltage applied to the sacrificial conductive protection layer, in at least one embodiment, is between 0.01 volts and 200 volts. In yet another embodiment, the voltage applied to the sacrificial conductive protection layer is between 0.5 volts and 10 volts. In at least one embodiment, the electrical current applied to the sacrificial conductive protection layer is between 0.5 milliamps and 100 amps, and in yet another embodiment is between 0.05 amps and 5 amps. In one embodiment, the positive voltage accelerates the corrosion process by up to at least 2× (e.g., in comparison to applying no voltage at all). In another embodiment, the positive voltage accelerates the corrosion process by up to at least 5×. In yet another embodiment, the positive voltage accelerates the corrosion process by up to at least 10×, and in yet another embodiment of 20× or 100×, or more. Those skilled in the art understand there may be an inherent limit on the amount that the positive voltage may speed up the corrosion process, but in at least one embodiment that limit is about 100,000×.

[0030] The voltage being applied to the sacrificial conductive protection layer may come from an AC power source or a DC power source, whether located proximate the sacrificial conductive protection layer (e.g., as that term is defined above with regard to the location of the trigger device and the sacrificial conductive protection layer), within 100 m, 10 m, 1 m, 0.5 m or 0.1 m of the sacrificial conductive protection layer, uphole of the sacrificial conductive protection layer, or for that matter outside of the wellbore. Nevertheless, in at least one embodiment, the power source is a collection of one or more batteries located downhole proximate (e.g., as that term is defined herein) the sacrificial conductive protection layer. In at least one other embodiment, the power source is a downhole power generator, such as a fluid flow turbine, among others.

[0031] The trigger device of the downhole tool may trigger the corrosion of the sacrificial conductive protection layer based upon a variety of different triggering events. In at least one embodiment, the triggering event is a lack of movement of the downhole tool. For example, when trigger circuitry of the trigger device senses the absence of movement of the downhole tool, the trigger circuitry may start a triggering sequence that will lead up to the trigger of the corrosion of the sacrificial conductive protection layer (e.g., in this embodiment the application of a voltage to the sacrificial conductive protection layer). In at least one embodiment, the sequence is an immediate application of the voltage to the sacrificial conductive protection layer, and thus an immediate trigger of the corrosion. In yet another embodiment, the sequence is a timed delay of the application of the voltage to the sacrificial conductive protection layer, and thus a timed delay of the trigger of the corrosion. In yet another embodiment, the sequence of the timed delay of the application of the voltage may commence, but if a movement of the downhole tool is sensed in the interim, the timed delay would be reset. In yet another embodiment, changes in fluid flow, temperature (e.g., through fluid swapping), pressure, etc. surrounding the trigger device may be used to start the triggering sequence. In yet another embodiment, the triggering sequence may be based upon a timer (e.g., a specific period of time after a given occurrence), a transmitted signal through a wire, a transmitted signal sent wirelessly, or from a sensing of the operation of the wellbore, among other mechanisms.

[0032] In even yet another embodiment, the downhole tool may additionally take advantage of the galvanic corrosion effect (e.g., another electrochemical process) to trigger the corrosion of the sacrificial conductive protection layer. Turning briefly to FIG. 3, illustrated is a galvanic series chart. The galvanic series (e.g., also called the electropotential series) determines the nobility of metals and semi-metals. When two metals are submerged in an electrolyte, while also electrically connected by some external conductor, the less noble (base) will experience galvanic corrosion. The rate of corrosion is determined by the electrolyte, the difference in nobility, and the relative areas of the anode and cathode exposed to the electrolyte. The difference can be measured as a difference in voltage potential: the less noble metal is the one with a lower (e.g., more negative) electrode potential than the more noble one, and will function as the anode (electron or anion attractor) within the electrolyte device functioning as a galvanic cell.

[0033] Given the foregoing, the materials for the sacrificial conductive protection layer and the separate downhole conductive layer may be chosen to further take advantage of the galvanic corrosion effect. Accordingly, those skilled in the art understand that so long as the sacrificial conductive protection layer is chosen such that its electrode potential is lower than that of the separate downhole conductive layer, the galvanic corrosion effect may also be taken advantage of. For example, the sacrificial conductive protection layer could be any one of the Mg, Al, or Zn discussed above, so long as the separate downhole conductive layer has an electrode potential of greater than −0.06, if not greater than −0.04, if not greater than −0.02, or even a positive electrode potential. Again, the present disclosure is not limited to any specific materials for the sacrificial conductive protection layer and the separate downhole conductive layer, and the present disclosure may choose to take advantage of galvanic corrosion, or choose not to take advantage of galvanic corrosion, simply based upon the specific materials chosen.

[0034] Turning to FIG. 4, illustrated is one embodiment of a downhole tool 400 designed, manufactured and / or operated according to one or more embodiments of the disclosure. The downhole tool 400, in the illustrated embodiment, includes a downhole feature 410. The downhole feature 410, in the given embodiment, is a tubular as might be used in a well system (e.g., the well system 100). Nevertheless, in yet other embodiments, the downhole feature 410 is not a tubular, but another well system feature. In the illustrated embodiment of FIG. 4, the downhole tool 400 additionally includes a protective housing 420 coupled with the downhole feature 410. In the illustrated embodiment, the protective housing 420 is positioned radially about the downhole feature 410 and forms a cavity 425. Nevertheless, other embodiments may exist wherein the protective housing 420 does not extend radially about the downhole feature 410.

[0035] In one or more embodiments, such as that shown in FIG. 4, the downhole tool 400 additionally includes a sacrificial conductive protection layer 430 sealing against the protective housing 420 around the cavity 425. For example, in at least the embodiment shown, the protective housing 420 and sacrificial conductive protection layer 430 form a sealed chamber 440. In one or more embodiments, one or more seal members 445 (e.g., O-rings) may be used to assist in the sealing of the protective housing 420 and seal chamber 440.

[0036] In accordance with one embodiment, a material to be protected 450 is located at least partially within the cavity 425 of the protective housing 420, in this embodiment disposed within the sealed chamber 440. The material to be protected 450 may comprise a variety of different materials, whether in solid form or liquid form, that one desires to keep isolated (e.g., temporarily keep isolated), for example within the sealed chamber 440 in the embodiment of FIG. 4. In at least one embodiment, a desire may exist to isolate the material to be protected 450 from features and / or substances outside of the sealed chamber 440, such as reactive solids / fluids, caustic materials, etc. In yet one other embodiment, a desire may exist to isolate features and / or substances and / or locations outside of the sealed chamber 440 from the material to be protected 450. Accordingly, unless otherwise required, the present disclosure is not limited to one or the other of these situations.

[0037] Notwithstanding the foregoing, in the embodiment of FIG. 4, the material to be protected 450 is a metal configured to expand in response to hydrolysis, also referred to as an expandable metal. The term expandable metal, as used herein, refers to the expandable metal in a pre-expansion form. Similarly, the term expanded metal, as used herein, refers to the resulting expanded metal after the expandable metal has been subjected to reactive fluid, as discussed below. The expanded metal, in accordance with one or more aspects of the disclosure, comprises a metal that has expanded in response to hydrolysis. In certain embodiments, the expanded metal includes residual unreacted metal. For example, in certain embodiments the expanded metal is intentionally designed to include the residual unreacted metal. The residual unreacted metal has the benefit of allowing the expanded metal to self-heal if cracks or other anomalies subsequently arise, or for example to accommodate changes in the tubular or mandrel diameter due to variations in temperature and / or pressure. Nevertheless, other embodiments may exist wherein no residual unreacted metal exists in the expanded metal. In at least one embodiment, the residual unreacted metal exists when the expandable metal has expanded into contact with another feature, such as another wellbore tubular, prior to all of the expanded metal reacting into expanded metal. Once the expanded metal has sealed against this wellbore tubular, the reactive fluid may no longer reach the expandable metal, and the hydrolysis essentially ends. Similarly, if all of the expandable metal has reacted into expanded metal prior to sealing against the wellbore tubular, the expanded metal may ultimately wash away.

[0038] The expandable metal, in some embodiments, may be described as expanding to a cement like material. In other words, the expandable metal goes from metal to micron-scale particles and then these particles expand and lock together to, in essence, seal two or more surfaces together. The reaction may, in certain embodiments, occur in less than 2 days in a reactive fluid and in certain temperatures. Nevertheless, the time of reaction may vary depending on the reactive fluid, the expandable metal used, the downhole temperature, surface-area-to-volume ratio (SA:V) of the expandable metal, and any dissimilar cathodic electric conductors that may be included therein (e.g., as discussed herein).

[0039] In some embodiments, the reactive fluid may be a brine solution such as may be produced during well completion activities, and in other embodiments, the reactive fluid may be one of the additional solutions discussed herein (e.g., water-based mud). The expandable metal is electrically conductive in certain embodiments. The expandable metal, in certain embodiments, has a yield strength greater than about 8,000 psi, e.g., 8,000 psi + / −50%. The expandable metal, in at least one embodiment, has a minimum dimension greater than about 1.25 mm (e.g., approximately 0.05 inches).

[0040] The hydrolysis of the expandable metal can create a metal hydroxide. The formative properties of alkaline earth metals (Mg—Magnesium, Ca—Calcium, etc.) and transition metals (Zn—Zinc, Al—Aluminum, etc.) under hydrolysis reactions demonstrate structural characteristics that are favorable for use with the present disclosure. Hydration results in an increase in size from the hydration reaction and results in a metal hydroxide that can precipitate from the fluid.

[0041] It should be noted that the starting expandable metal, unless otherwise indicated, is not a metal oxide (e.g., an insulator). In contrast, the starting expandable metal has, in certain embodiments, the properties of traditional metals: 1) Highly conductive to both electricity and heat (e.g., greater than 1,000,000 siemens per meter); 2) Contains a metallic bond (e.g., the outermost electron shell of each of the metal atoms overlaps with a large number of neighboring atoms). As a consequence, the valence electrons are allowed to move from one atom to another and are not associated with any specific pair of atoms. This gives metals their conductive nature; 3) Malleable and ductile, for example deforming under stress without cleaving; and 4) Tend to be shiny and lustrous with high density.

[0042] The hydration reactions for magnesium is:where Mg(OH)2 is also known as brucite. Another hydration reaction uses aluminum hydrolysis. The reaction forms a material known as Gibbsite, bayerite, boehmite, aluminum oxide, and norstrandite, depending on form. The possible hydration reactions for aluminum are:Another hydration reaction uses calcium hydrolysis. The hydration reaction for calcium is:Where Ca(OH)2 is known as portlandite and is a common hydrolysis product of Portland cement. Magnesium hydroxide and calcium hydroxide are considered to be relatively insoluble in water. Aluminum hydroxide can be considered an amphoteric hydroxide, which has solubility in strong acids or in strong bases. Alkaline earth metals (e.g., Mg, Ca, etc.) work well for the expandable metal, but transition metals (Al, etc.) also work well for the expandable metal. In one embodiment, the metal hydroxide is dehydrated by the swell pressure to form a metal oxide.In at least one embodiment, the expandable metal is a non-graphene based expandable metal. By non-graphene based material, it is meant that is does not contain graphene, graphite, graphene oxide, graphite oxide, graphite intercalation, or in certain embodiments, compounds and their derivatized forms to include a function group, e.g., including carboxy, epoxy, ether, ketone, amine, hydroxy, alkoxy, alkyl, aryl, aralkyl, alkaryl, lactone, functionalized polymeric or oligomeric groups, or a combination comprising at least one of the forgoing functional groups. In at least one other embodiment, the expandable metal does not include a matrix material or an exfoliatable graphene-based material. By not being exfoliatable, it means that the expandable metal is not able to undergo an exfoliation process. Exfoliation as used herein refers to the creation of individual sheets, planes, layers, laminae, etc. (generally, “layers”) of a graphene-based material; the delamination of the layers; or the enlargement of a planar gap between adjacent ones of the layers, which in at least one embodiment the expandable metal is not capable of.In yet another embodiment, the expandable metal does not include graphite intercalation compounds, wherein the graphite intercalation compounds include intercalating agents such as, for example, an acid, metal, binary alloy of an alkali metal with mercury or thallium, binary compound of an alkali metal with a Group V element (e.g., P, As, Sb, and Bi), metal chalcogenide (including metal oxides such as, for example, chromium trioxide, PbO2, MnO2, metal sulfides, and metal selenides), metal peroxide, metal hyperoxide, metal hydride, metal hydroxide, metals coordinated by nitrogenous compounds, aromatic hydrocarbons (benzene, toluene), aliphatic hydrocarbons (methane, ethane, ethylene, acetylene, n-hexane) and their oxygen derivatives, halogen, fluoride, metal halide, nitrogenous compound, inorganic compound (e.g., trithiazyl trichloride, thionyl chloride), organometallic compound, oxidizing compound (e.g., peroxide, permanganate ion, chlorite ion, chlorate ion, perchlorate ion, hypochlorite ion, As2O5, N2O5, CH3DlO4, (NH4)2S2O8, chromate ion, dichromate ion), solvent, or a combination comprising at least one of the foregoing. Thus, in at least one embodiment, the expandable metal is a structural solid expanded metal, which means that it is a metal that does not exfoliate and it does not intercalate. In yet another embodiment, the expandable metal does not swell by sorption.In an embodiment, the expandable metal used can be a metal alloy. The expandable metal alloy can be an alloy of the base expandable metal with other elements in order to either adjust the strength of the expandable metal alloy, to adjust the reaction time of the expandable metal alloy, or to adjust the strength of the resulting metal hydroxide byproduct, among other adjustments. The expandable metal alloy can be alloyed with elements that enhance the strength of the metal such as, but not limited to, Al—Aluminum, Zn—Zinc, Mn—Manganese, Zr—Zirconium, Y—Yttrium, Nd—Neodymium, Gd—Gadolinium, Ag—Silver, Ca—Calcium, Sn—Tin, and Re—Rhenium, Cu—Copper. In some embodiments, the expandable metal alloy can be alloyed with a dopant that promotes corrosion, such as Ni—Nickel, Fe—Iron, Cu—Copper, Co—Cobalt, Ir—Iridium, Au—Gold, C—Carbon, Ga—Gallium, In—Indium, Mg—Mercury, Bi—Bismuth, Sn—Tin, and Pd—Palladium. The expandable metal alloy can be constructed in a solid solution process where the elements are combined with molten metal or metal alloy. Alternatively, the expandable metal alloy could be constructed with a powder metallurgy process. The expandable metal can be cast, forged, extruded, sintered, welded, mill machined, lathe machined, stamped, eroded or a combination thereof. The metal alloy can be a mixture of the metal and metal oxide. For example, a powder mixture of aluminum and aluminum oxide can be ball-milled together to increase the reaction rate.Optionally, non-expanding components may be added to the starting metallic materials. For example, ceramic, elastomer, plastic, epoxy, glass, or non-reacting metal components can be embedded in the expandable metal or coated on the surface of the expandable metal. In yet other embodiments, the non-expanding components are metal fibers, a composite weave, a polymer ribbon, or ceramic granules, among others. In one variation, the expandable metal is formed in a serpentinite reaction, a hydration and metamorphic reaction. In one variation, the resultant material resembles a mafic material. Additional ions can be added to the reaction, including silicate, sulfate, aluminate, carbonate, and phosphate. The metal can be alloyed to increase the reactivity or to control the formation of oxides.The expandable metal can be configured in many different fashions, as long as an adequate volume of material is available for supporting the necessary features. For example, the expandable metal may be formed into a single long member and / or layer, multiple short members and / or layers, rings, among others. In another embodiment, the expandable metal may be formed into a long wire of expandable metal, which can be in turn be wound around a mandrel as a sleeve. The wire diameters do not need to be of circular cross-section, but may be of any cross-section. For example, the cross-section of the wire could be oval, rectangle, star, hexagon, keystone, hollow braided, woven, twisted, among others, and remain within the scope of the disclosure. In certain other embodiments, the expandable metal is a collection of individual separate chunks of the metal held together with a binding agent. In yet other embodiments, the expandable metal is a collection of individual separate chunks of the metal that are not held together with a binding agent, but held in place using one or more different techniques, including an enclosure (e.g., an enclosure that could be crushed to expose the individual separate chunks to the reactive fluid), a cage, etc.

[0048] Additionally, a delay coating or protective layer may be applied to one or more portions of the expandable metal to delay the expanding reactions. In one embodiment, the material configured to delay the hydrolysis process is a fusible alloy. In another embodiment, the material configured to delay the hydrolysis process is a eutectic material. In yet another embodiment, the material configured to delay the hydrolysis process is a wax, oil, or other non-reactive material. The delay coating or protective layer may be applied to any of the different expandable metal configurations disclosed above.

[0049] Returning back to FIG. 4, the protective housing 420 and the sacrificial conductive protection layer 430 may shield (e.g., temporally shield) the material to be protected 450, in this instance the expandable metal, from reactive fluids located outside of the sealed chamber 440. In at least one other embodiment, a non-reactive fluid 460 is located within the sealed chamber 440 and surrounding the material to be protected 450. The non-reactive fluid 460, in one embodiment, is deionized water, oil, or another non-reactive fluid. The non-reactive fluid 460, when used, may protect the sacrificial conductive protection layer 430 against the pressure of the wellbore, and thus prevent the sacrificial conductive protection layer 430 from failing under the pressure of the wellbore.

[0050] The downhole tool 400, in one or more embodiments, further includes a trigger device 470 positioned proximate the sacrificial conductive protection layer 430. For example, in at least one embodiment, a positive electrode 475a of the trigger device 470 is coupled to the sacrificial conductive protection layer 430 and a negative electrode 475b of the trigger device 470 is coupled to a separate downhole conductive layer 480. In at least this one embodiment, the trigger device 470 is configured to apply a voltage to the sacrificial conductive protection layer 430 to trigger a corrosion thereof based upon a triggering event, as discussed above. In the illustrated embodiment, the trigger device 470 additionally includes trigger circuitry 485, for example located in a second separate sealed chamber 490 in one or more embodiments.

[0051] Further to the embodiment of FIG. 4, in one or more embodiments, the separate downhole conductive layer 480 forms at least a portion of the second separate sealed chamber 490. For example, the separate downhole conductive layer 480 may function as the seal to the second separate sealed chamber 490. Additionally, in at least one embodiment, a trigger circuitry power source 495 may be located within the second separate sealed chamber 490. In at least this one embodiment, the trigger circuitry 485 is configured to apply the voltage to the sacrificial conductive protection layer 430 to trigger a corrosion thereof based upon a triggering event, and receiving power from the trigger circuitry power source 495. In at least one embodiment, the trigger circuitry power source 495 is an AC power source. In at least one other embodiment, such as shown, the trigger circuitry power source 495 is a DC power source, for example including one or more batteries. While not shown, in certain embodiments it is advantageous to include a fluid (e.g., non-reactive fluid) within the second separate sealed chamber 490 as well, for example to also protect the trigger circuitry 485 and trigger circuitry power source 495 from the effects of the wellbore pressure.

[0052] Turning to FIGS. 5A through 5D, illustrated are various different perspective views of different sacrificial conductive protection layers, as might be used with the downhole tool 400 of FIG. 4. Within initial reference to FIG. 5A, illustrated is a sacrificial conductive protection layer 500a. The sacrificial conductive protection layer 500a, in the illustrated embodiment, includes one or more corrodible portions 510 (e.g., exposed to an outside of the sealed chamber, such as the sealed chamber 440 of FIG. 4) and one or more non-corrodible portions 520 (e.g., exposed to an inside and / or outside of the sealed chamber, such as the sealed chamber 440 of FIG. 4). In the illustrated embodiment of FIG. 5A, the sacrificial conductive protection layer 500a is a tubular 530 of conductive material having an inside surface 540 and an outside surface 550. The sacrificial conductive protection layer 500a, in the illustrated embodiment, further includes a layer of protective material 560 disposed on the tubular 530. In at least this one embodiment, the layer of protective material 560 is precisely formed (e.g., deposited or coated) on the tubular 530 to expose portions thereof (e.g., forming the one or more corrodible portions 510) and cover other portions thereof (e.g., forming the one or more non-corrodible portions 520). Stated another way, a desired pattern of corrodible portions 510 and non-corrodible portions 520 may be formed by precisely depositing and / or coating a certain pattern of the layer of protective material 560 on the tubular 530, wherein the resulting corrodible portions 510 are those portions / sections of the tubular 530 that are not covered by the layer of protective material 560, and the resulting non-corrodible portions 520 are those portions / sections of the tubular 530 covered by the layer of protective material 560.

[0053] It should additionally be noted that in other embodiments, rather than the layer of protective material 560 originally being precisely deposited or coated at specific locations, an entirety of the tubular 530 might be coated with the layer of protective material 560, and then subsequent thereto portions of the layer of protective material 560 modified and / or removed to form the pattern of corrodible portions 510 and non-corrodible portions 520. For example, in at least one embodiment the blanket layer of protective material 560 may be modified and / or removed with a subtractive manufacturing step, such as machining, abrading etc., to form the resulting pattern of corrodible portions 510 and non-corrodible portions 520. Alternatively, a masking agent could first be applied to the tubular 530 (e.g., in regions where it is desired for the corrodible portions 510 to be located), but as the blanket layer of protective material 560 is subsequently deposited or coated on the entirety of the tubular 530, it would not adhere to those portions covered by the masking agent (e.g., thereby forming the corrodible portions 510) but would only adhere to those portions not covered by the masking agent (e.g., thereby forming the non-corrodible portions 520). Similarly, a photolithography process, for example similar to that often used in the manufacture of semiconductors, could be used to deposit, pattern, and etch the layer of protective material 560 to form the pattern of corrodible portions 510 and non-corrodible portions 520. Those skilled in the art, particularly given the new teachings herein, would understand other ways to form the corrodible portions 510 and non-corrodible portions 520, and thus unless otherwise required, any specific method could be used.

[0054] Given the foregoing, in at least one embodiment, the layer of protective material 560 may be formed on the tubular 530 of conductive material in any pattern, regardless of shape, size, or location. For example, in at least one embodiment, the layer of protective material 560 is located on one or more of the inside surface 540 (e.g., inside diameter (ID)), outside surface 550 (e.g., outside diameter (OD)), and edges 555 of the tubular 530, whether patterned or not. For example, in one embodiment, the layer of protective material 560 entirely covers the inside surface 540 (e.g., inside diameter (ID)) and edges 555 of the tubular 530, while covers less than an entirety of the outside surface 550 (e.g., outside diameter (OD)) (e.g., is patterned on the outside surface 550 in one or more different configurations, such as to form the corrodible portion 510). In yet another embodiment, the layer of protective material 560 entirely covers the outside surface 550 (e.g., outside diameter (OD)) and edges of the tubular 530, while covers less than an entirety of the inside surface 540 (e.g., inside diameter (ID)) (e.g., is patterned on the inside surface 540 in one or more different configurations, such as to form the corrodible portion 510). In even yet another embodiment, the layer of protective material 560 entirely covers the inside surface 540 (e.g., inside diameter (ID)) and outside surface 550 (e.g., outside diameter (OD)) of the tubular 530, while covers less than an entirety of the edges 555. In even yet another embodiment, any combination of the foregoing is possible, depending on the design of the device and desired location for the corrodible portions 510. It should further be understood that the corrodible portions 510 need not completely transect the thickness of the tubular 530 (e.g., the pattern on the inside surface 540 need not mirror that on the outside surface 550). Similarly, the corrodible portions 510 could be a small section of the tubular 530 that would ultimately allow the material to be protected (e.g., material to be protected 450) and an exterior of the protective housing (e.g., protective housing 420) to have access to one another, without entirely separating the tubular 530 into individual separate pieces (e.g., a plurality of centralized holes could be formed through the thickness of the sacrificial conductive protection layer 430 to provide such access).

[0055] In the illustrated embodiment of FIG. 5A, the layer of protective material 560 forms one or more rings 570a (e.g., exposed rings) of corrodible portions 510 on the outside surface 550. In accordance with one or more embodiments, the one or more corrodible portions 510 are electrically coupled with the trigger device of the downhole tool (e.g., with regard to FIG. 4, electrically coupled with the positive electrode 475a of the trigger circuitry 485). It should be noted that in one or more embodiments, such as that shown, the one or more corrodible portions extend through a thickness of the tubular. In at least one embodiment, the layer of protective material 560 includes a polymer. In yet another embodiment, the layer of protective material 560 includes an epoxy, a ceramic coating, or any other material that is suitable for creating the one or more corrodible portions 510 and one or more non-corrodible portions 520. Accordingly, unless otherwise states, the layer of protective material 560 is not limited to any specific material.

[0056] Turning to FIG. 5B, illustrated is a sacrificial conductive protection layer 500b. The sacrificial conductive protection layer 500b of FIG. 5B is similar in many respects to the sacrificial conductive protection layer 500a of FIG. 5A. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The sacrificial conductive protection layer 500b differs, for the most part, from the sacrificial conductive protection layer 500a, in that the layer of protective material 560 of the sacrificial conductive protection layer 500b forms one or more axial lines 570b of corrodible portions 510 on the outside surface 550. In at least this one embodiment, the triggering process would result in four separate remaining tubular portions that are entirely free to move relative to one another.

[0057] Turning to FIG. 5C, illustrated is a sacrificial conductive protection layer 500c. The sacrificial conductive protection layer 500c of FIG. 5C is similar in many respects to the sacrificial conductive protection layer 500a of FIG. 5A and the sacrificial conductive protection layer 500b of FIG. 5B. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The sacrificial conductive protection layer 500c, in the illustrated embodiment, includes both the one or more rings 570a and one or more axial lines 570b of corrodible portions 510, thereby forming a checkerboard pattern of corrodible portions 510 on the outside surface 550. In at least this one embodiment, the triggering process would result in approximately twenty separate remaining tubular portions that are entirely free to move relative to one another.

[0058] Turning to FIG. 5D, illustrated is a sacrificial conductive protection layer 500d. The sacrificial conductive protection layer 500d of FIG. 5D is similar in many respects to the sacrificial conductive protection layer 500a of FIG. 5A. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The sacrificial conductive protection layer 500d differs, for the most part, from the sacrificial conductive protection layer 500a, in that the layer of protective material 560 of the sacrificial conductive protection layer 500d forms one or more helical lines 570d of corrodible portions 510 on the outside surface 550. In at least this one embodiment, contrary to FIGS. 5A through 5C, the triggering process would result in a single tubular portion with a single continuous spiral gap.

[0059] The embodiments of FIGS. 5A through 5D illustrate that upon subjecting the sacrificial conductive protection layer 500c to a voltage, they may corrode, and for example provide access between an inside surface 540 of the tubular 530 and an outside surface 550 of the tubular 530, whether that through one or more holes or slots in the tubular 530 exposing the material to be protected, or allowing the tubular 530 to break into smaller pieces exposing the material to be protected. Furthermore, given the lesser surface area of a combination of the corrodible portions in one or more embodiments, less power (e.g., wattage) is needed to expose the material to be protected. For example, in at least one embodiment, a combined surface area of the one or more corrodible portions is less than 1000 percent of a combined surface area of the one or more non-corrodible portions. For example, in at least one other embodiment, the combined surface area of the one or more corrodible portions is less than 200 percent of the combined surface area of the one or more non-corrodible portions. In yet another embodiment, the combined surface area of the one or more corrodible portions is less than the combined surface area of the one or more non-corrodible portions. In yet another embodiment, the combined surface area of the one or more corrodible portions is less than 50 percent of the combined surface area of the one or more non-corrodible portions. In yet another embodiment, the combined surface area of the one or more corrodible portions is less than 10 percent of the combined surface area of the one or more non-corrodible portions. In yet another embodiment, the combined surface area of the one or more corrodible portions is less than 5 percent of the combined surface area of the one or more non-corrodible portions. In yet another embodiment, the combined surface area of the one or more corrodible portions is less than 1 percent of the combined surface area of the one or more non-corrodible portions. In yet another embodiment, such as when a trigger circuitry power source 495 is employed downhole, the combined surface area of the one or more corrodible portions ranges from 0.1 percent to 10 percent of the combined surface area of the one or more non-corrodible portions, if not from 1 percent to 5 percent, for example to reduce the amount of power required to expose the layer of protective material 560. In at least one other embodiment, the one or more corrodible portions have a combined corrodible portion outer surface area exposed to the outside of the sealed chamber and the one or more non-corrodible portions have a combined non-corrodible portion outer surface area exposed to the outside of the sealed chamber. Any of the above percentages may be used in this alternative embodiment, nevertheless, in at least one embodiment, a combined surface area of the one or more corrodible portions is less than 10 percent of a combined surface area of the one or more non-corrodible portions.

[0060] Turning to FIGS. 6A through 6D, illustrated are different cross-sectional views of a downhole tool 600 designed, manufactured and / or operated at different stages of use. The downhole tool 600 of FIGS. 6A through 6D is similar in many respects to the downhole tool 400 of FIG. 4. Accordingly, like reference numbers have been used to indicate similar, if not identical features.

[0061] With initial reference to FIG. 6A, the downhole tool 600 has been positioned within a conduit 610. The conduit 610 may be any tubular employed in a well system, such wellbore casing in one embodiment. In the illustrated embodiment of FIG. 6A, little to no fluid surrounds the downhole tool 600. Nevertheless, in yet other embodiments, one or more fluids may be located in the conduit 610 and surrounding the downhole tool 600.

[0062] Turning to FIG. 6B, illustrated is the downhole tool 600 of FIG. 6A after pumping fluid 620 (e.g., including mud) downhole and into the conduit 610. The fluid 620, in at least one embodiment, is reactive fluid, such as might be used to cause the expandable metal to expand in response to hydrolysis. However, as the material to be protected 450 is isolated from the reactive fluid, the hydrolysis may not begin. In yet another embodiment, the fluid 620 is a non-reactive fluid. In the illustrated embodiment, the fluid 620 is a conductive fluid. At this stage, no triggering event has occurred.

[0063] Turning to FIG. 6C, illustrated is the downhole tool 600 of FIG. 6B after a triggering event has occurred (e.g., any one of the triggering events disclosed above, or other known or hereafter discovered triggering events), and thus the trigger device 470 applies a suitable voltage to sacrificial conductive protection layer 430 (e.g., through the sacrificial conductive protection layer pumping fluid 620 in one embodiment). As shown, the voltage causes the sacrificial conductive protection layer 430 to corrode, and thus go away. Accordingly, the material to be protected 450 is no longer protected within the sealed chamber 440. It should further be noted that, depending on the materials chosen for the sacrificial conductive protection layer 430 and the separate downhole conductive layer 480, the existence of an electrolyte (e.g., the fluid 620) may allow the downhole tool 600 to take further advantage of the galvanic corrosion effect.

[0064] Turning to FIG. 6D, illustrated is the downhole tool 600 of FIG. 6C after the fluid 620 (e.g., reactive fluid in the given embodiment) chemically reacts with the material to be protected 450 (e.g., a metal configured to expand in response to hydrolysis in this embodiment) to form an expanded metal seal 630.

[0065] It should be noted that while FIGS. 6A through 6D illustrate complete removal of the sacrificial conductive protection layer 430, other embodiments may exist wherein less than complete removal of the sacrificial conductive protection layer 430 (e.g., but sufficient removal to exposed the material to be protected) may occur. This is evident with the different designs for the sacrificial conductive protection layer discussed and illustrated with respect to FIGS. 5A through 5D.

[0066] Turning now to FIG. 7, illustrated is a downhole tool 700 designed, manufactured and / or operated according to one or more alternative embodiments of the disclosure. The downhole tool 700 of FIG. 7 is similar in many respects to the downhole tool 400 of FIG. 4. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 700 differs, for the most part, from the downhole tool 400, in that the downhole tool 700 does not employ a trigger circuitry power source 495 located proximate the material to be protected 450, or even within the second separate sealed chamber 490, but its trigger circuitry power source is located uphole of the downhole tool 700. In at least one embodiment, the trigger circuitry power source coupled to the downhole tool 700 is located many meters above the downhole tool 700, if not outside of the wellbore.

[0067] Turning now to FIG. 8, illustrated is a downhole tool 800 designed, manufactured and / or operated according to one or more alternative embodiments of the disclosure. The downhole tool 800 of FIG. 8 is similar in many respects to the downhole tool 400 of FIG. 4. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 800 differs, for the most part, from the downhole tool 400, in that the material to be protected 850 is a swellable material (e.g., swell elastomer) configured to swell by absorption after the triggering event, for example to form a swellable material seal. Those skilled in the art understand the various different swellable materials that could be used for the material to be protected 850. The swell elastomer, in one or more embodiments, may comprise elastomers that swell in water / brine and / or hydrocarbons, and is not limited to any specific composition. Common water-swell / brine-swell base elastomers include: Ethylene-Propylene-Diene Monomer Rubber (“EPDM”) (terpolymer of ethylene, propylene, and a diene monomer); Ethylene-Propylene Rubber (“EPM”) (copolymer of ethylene and propylene; non-diene version of EPDM); Blends of Acrylonitrile-Butadiene Rubber and Hydrogenated Acrylonitrile-Butadiene Rubber with hydrophilic polymer additives (“NBR” / “HNBR” blends with hydrophilic packages) (used to promote controlled water or brine swelling). Common oil-swell / hydrocarbon-swell base elastomers include: Acrylonitrile-Butadiene Rubber (“NBR”) (sometimes called Nitrile Butadiene Rubber; copolymer of acrylonitrile and butadiene); Hydrogenated Acrylonitrile-Butadiene Rubber (“HNBR”) (chemically hydrogenated version of NBR for improved heat and oxidation resistance); Fluorocarbon Rubber (“FKM”) (Fluoroelastomer) (terpolymer or copolymer based on vinylidene fluoride, hexafluoropropylene, and / or tetrafluoroethylene; “Viton®” is a common trade name); Tetrafluoroethylene-Propylene Rubber (“FEPM” (AFLAS-type)) (fluoroelastomer based on tetrafluoroethylene and propylene; marketed under trade names such as AFLAS®). Some less common swell elastomers include: Perfluoroelastomer Rubber (“FFKM”) ; (fluoroelastomers in which nearly all hydrogen atoms are replaced by fluorine; extremely high chemical and temperature resistance); Polychloroprene Rubber (“CR” (Neoprene)); Acrylic Rubber (“ACM”) (copolymer of alkyl acrylates); Ethylene-Acrylic Rubber (“AEM”) (copolymer of ethylene and acrylic monomers); Vinyl-Methyl Polysiloxane Rubber (“VMQ” (Silicone rubber)) (standard methyl-vinyl silicone elastomer).

[0068] The downhole tool 800, in the embodiment of FIG. 8, does not employ the non-reactive fluid 460, or any fluid, within the sealed chamber 440. Furthermore, in at least the embodiment of FIG. 8, a very small space exists between the material to be protected 850 and the sacrificial conductive protection layer 430, thus minimizing any pressure issues that may exist.

[0069] Turning now to FIG. 9, illustrated is a downhole tool 900 designed, manufactured and / or operated according to one or more alternative embodiments of the disclosure. The downhole tool 900 of FIG. 9 is similar in many respects to the downhole tool 400 of FIG. 4. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 900 differs, for the most part, from the downhole tool 400, in that the material to be protected 950 of the downhole tool 900 is a collection of solid particles configured to move to a different location within a wellbore (e.g., exit the sealed chamber and move to a different location within the wellbore) after the triggering event. For example, in at least one embodiment the collection of solid particles release and go into solution after the triggering event, such as anhydrous acids or salts, among others. The material to be protected 950, in one embodiment, may further include a tracer, the tracer providing information related to the triggering event, such as an indication that the material to be protected 950 is no longer protected.

[0070] Turning now to FIG. 10, illustrated is a downhole tool 1000 designed, manufactured and / or operated according to one or more alternative embodiments of the disclosure. The downhole tool 1000 of FIG. 10 is similar in many respects to the downhole tool 900 of FIG. 9. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 1000 differs, for the most part, from the downhole tool 900, in that the material to be protected 950 of the downhole tool 1000 is located within a volume of fluid 1010. In yet another embodiment, the material to be protected 950 may contain a viscosifier (e.g., like a gelling agent), a colloidal latex, etc., among others.

[0071] Turning now to FIG. 11, illustrated is a downhole tool 1100 designed, manufactured and / or operated according to one or more alternative embodiments of the disclosure. The downhole tool 1100 of FIG. 11 is similar in many respects to the downhole tool 400 of FIG. 4. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 1100 differs, for the most part, from the downhole tool 400, in that the material to be protected 1150 of the downhole tool 1100 is a volume of fluid configured to move to a different location within a wellbore (e.g., exit the sealed chamber and move to a different location within the wellbore) after the triggering event.

[0072] Aspects disclosed herein include:

[0073] A. A downhole tool, the downhole tool including: 1) material to be protected; 2) a sacrificial conductive protection layer positioned about the material to be protected, the sacrificial conductive protection layer configured to isolate the material to be protected from an undesirable material; and 3) a positive electrode and a negative electrode, the positive electrode coupled to the sacrificial conductive protection layer and the negative electrode coupled to a separate conductive feature, the sacrificial conductive protection layer configured to receive a voltage via the positive electrode from a trigger device to trigger a corrosion thereof based upon a triggering event.

[0074] B. A downhole tool, the downhole tool including: 1) a protective housing; 2) a sacrificial conductive protection layer sealing against the protective housing, the protective housing and sacrificial conductive protection layer forming a sealed chamber; 3) material to be protected disposed within the sealed chamber; and d) a trigger device positioned proximate the sacrificial conductive protection layer, the trigger device including a positive electrode coupled to the sacrificial conductive protection layer and a negative electrode coupled to a separate downhole conductive layer, the trigger device configured to apply a voltage to the sacrificial conductive protection layer to trigger a corrosion thereof based upon a triggering event.

[0075] C. A method, the method including: 1) positioning a downhole tool within a wellbore extending through one or more subterranean formations, the downhole tool including: a) material to be protected; b) a sacrificial conductive protection layer positioned about the material to be protected, the sacrificial conductive protection layer configured to isolate the material to be protected from an undesirable material; and c) a positive electrode coupled to the sacrificial conductive protection layer and a negative electrode coupled to a separate conductive feature; and 2) applying a voltage to the sacrificial conductive protection layer via the positive electrode to trigger a corrosion of the sacrificial conductive protection and expose the material to be protected.

[0076] D. A method, the method including: 1) positioning a downhole tool within a wellbore extending through one or more subterranean formations, the downhole tool including: a) a protective housing; b) a sacrificial conductive protection layer sealing against the protective housing, the protective housing and sacrificial conductive protection layer forming a sealed chamber; c) material to be protected disposed within the sealed chamber; and d) a trigger device positioned proximate the sacrificial conductive protection layer, the trigger device including a positive electrode coupled to the sacrificial conductive protection layer and a negative electrode coupled to a separate downhole conductive layer, the trigger device configured to apply a voltage to the sacrificial conductive protection layer to trigger a corrosion thereof based upon a triggering event; and 2) triggering the trigger device to corrode the sacrificial conductive protection layer and expose the material to be protected to an outside of the sealed chamber.

[0077] E. A well system, the well system including: 1) a wellbore extending through one or more subterranean formations; and 2) a downhole tool positioned within the wellbore, the downhole tool including: a) material to be protected; b) a sacrificial conductive protection layer positioned about the material to be protected, the sacrificial conductive protection layer configured to isolate the material to be protected from an undesirable material; and c) a positive electrode and a negative electrode, the positive electrode coupled to the sacrificial conductive protection layer and the negative electrode coupled to a separate conductive feature, the sacrificial conductive protection layer configured to receive a voltage via the positive electrode from a trigger device to trigger a corrosion thereof based upon a triggering event.

[0078] F. A well system, the well system including: 1) a wellbore extending through one or more subterranean formations; and 2) a downhole tool positioned within the wellbore, the downhole tool including: a) a protective housing; b) a sacrificial conductive protection layer sealing against the protective housing, the protective housing and sacrificial conductive protection layer forming a sealed chamber; c) material to be protected disposed within the sealed chamber; and d) a trigger device positioned proximate the sacrificial conductive protection layer, the trigger device including a positive electrode coupled to the sacrificial conductive protection layer and a negative electrode coupled to a separate downhole conductive layer, the trigger device configured to apply a voltage to the sacrificial conductive protection layer to trigger a corrosion thereof based upon a triggering event.

[0079] Aspects A, B, C, D, E and F may have one or more of the following additional elements in combination: Element 1: further including a protective housing, wherein the material to be protected is located at least partially within a cavity of the protective housing. Element 2: wherein the sacrificial protection layer seals against the protective housing around the cavity to form a sealed chamber around the material to be protected. Element 3: wherein the sealed chamber is a first sealed chamber, and further wherein the trigger device includes trigger circuitry located in a second separate sealed chamber. Element 4: wherein the separate conductive feature is a separate downhole conductive layer that forms at least a portion of the second separate sealed chamber. Element 5: further including a trigger circuitry power source located within the second separate sealed chamber, the trigger circuitry configured to apply the voltage to the sacrificial conductive protection layer to trigger the corrosion thereof based upon the triggering event and receiving power from the trigger circuitry power source. Element 6: wherein the trigger circuitry power source is an AC power source. Element 7: wherein the trigger circuitry power source is a DC power source including one or more batteries. Element 8: wherein the sacrificial conductive protection layer includes one or more corrodible portions exposed to an outside thereof and one or more non-corrodible portions exposed to an inside thereof. Element 9: wherein the sacrificial conductive protection layer is a tubular of conductive material having an inside surface and an outside surface, and further including a layer of protective material disposed on the tubular of conductive material to form the one or more corrodible portions and the one or more non-corrodible portions on the outside surface. Element 10: wherein the layer of protective material forms one or more rings of corrodible portions on the outside surface. Element 11: wherein the layer of protective material also forms one or more axial lines of corrodible portions on the outside surface to form a checkerboard pattern of corrodible portions on the outside surface. Element 12: wherein the layer of protective material forms one or more axial lines of corrodible portions on the outside surface. Element 13: wherein the layer of protective material forms one or more helical lines of corrodible portions on the outside surface. Element 14: wherein the one or more corrodible portions of the outside surface have a combined corrodible portion outer surface area and the one or more non-corrodible portions of the outside surface have a combined non-corrodible portion outer surface area, and further wherein a combined surface area of the one or more corrodible portions is less than 10 percent of a combined surface area of the one or more non-corrodible portions. Element 15: wherein the material to be protected includes metal configured to expand in response to hydrolysis after the triggering event. Element 16: wherein the metal configured to expand in response to hydrolysis includes one or more layers of metal configured to expand in response to hydrolysis. Element 17: wherein the one or more layers of metal configured to expand in response to hydrolysis are located in a sealed chamber, and further including a non-reactive fluid located in the sealed chamber and surrounding the one or more layers of metal configured to expand in response to hydrolysis. Element 18: wherein the material to be protected is swellable material configured to swell by absorption after the triggering event. Element 19: wherein the material to be protected is a collection of solid particles configured to move to a different location within a wellbore after the triggering event. Element 20: wherein the collection of solid particles are located within a volume of fluid. Element 21: wherein the material to be protected is a volume of fluid configured to move to a different location within a wellbore after the triggering event. Element 22: further including a protective housing coupled with a downhole feature, wherein the material to be protected is located at least partially within a cavity of the protective housing. Element 23: wherein the applying the voltage includes applying the voltage from a triggering device located proximate the sacrificial conductive protection layer. Element 24: wherein the triggering device applies the voltage based upon a triggering event. Element 25: further including a protective housing, wherein the material to be protected is at least partially located within a cavity of the protective housing and the sacrificial conductive protection layer seals against the protective housing around the cavity to form a sealed chamber around the material to be protected. Element 26: wherein the material to be protected includes metal configured to expand in response to hydrolysis, and further wherein applying the voltage allows the metal configured to expand in response to hydrolysis to expand to form an expanded metal seal. Element 27: wherein the material to be protected is a swellable material configured to swell by absorption, and further wherein applying the voltage allows the swellable material to swell by absorption to form a swellable material seal. Element 28: wherein the material to be protected is a collection of solid particles located within a sealed chamber, and further wherein applying the voltage allows the collection of solid particles to exit the sealed chamber and move to a different location within the wellbore. Element 29: wherein the material to be protected is a volume of fluid located within a sealed chamber, and further wherein applying the voltage allows the volume of fluid to exit the sealed chamber and move to a different location within the wellbore.

[0080] Those skilled in the art to which this application relates will appreciate that other and further additions, deletions, substitutions and modifications may be made to the described embodiments.

Examples

Embodiment Construction

[0017]In the drawings and descriptions that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawn figures are not necessarily to scale. Certain features of the disclosure may be shown exaggerated in scale or in somewhat schematic form and some details of certain elements may not be shown in the interest of clarity and conciseness. The present disclosure may be implemented in embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results.

[0018]Unless otherwise specified,...

CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims the benefit of U.S. Provisional Application Ser. No. 63 / 781,649, filed on Apr. 1, 2025, entitled “DOWNHOLE TOOL INCLUDING A TRIGGER DEVICE CONFIGURED TO APPLY A VOLTAGE TO A SACRIFICIAL CONDUCTIVE PROTECTION LAYER TO TRIGGER A CORROSION THEREOF BASED UPON A TRIGGERING EVENT,” commonly assigned with this application and incorporated herein by reference in its entirety.BACKGROUND

[0002] Wellbores are drilled into the earth for a variety of purposes including accessing hydrocarbon bearing formations. A variety of downhole tools may be used within a wellbore in connection with accessing and extracting such hydrocarbons. Throughout the process, it may become necessary to isolate sections of the wellbore for a number of different reasons, such as fluid control, production optimization, well integrity, etc. Downhole tools, such as frac plugs, bridge plugs, packers, and other suitable tools, may be used to isolate wellbore sections.

[0003] The aforementioned downhole tools are commonly run into the wellbore on a conveyance, such as a wireline, work string or production tubing. Such tools often have either an internal or external setting tool, which is used to set the downhole tool within the wellbore and hold the tool in place, and thus function as a wellbore anchor. The wellbore anchors typically include a plurality of slips, which extend outwards when actuated to engage and grip a casing within a wellbore or the open hole itself, and a sealing assembly, which can be made of rubber and extends outwards to seal off the flow of liquid around the downhole tool.BRIEF DESCRIPTION

[0004] Reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:

[0005] FIG. 1A illustrates a perspective view of a well system including an exemplary operating environment that the apparatuses, systems and methods disclosed herein may be employed;

[0006] FIG. 1B illustrates a zoomed in cross-sectional view of a portion of FIG. 1A;

[0007] FIGS. 2A through 2C illustrate Pourbaix diagrams for Mg, Al, and Zn, respectively;

[0008] FIG. 3 illustrates a galvanic series chart;

[0009] FIG. 4 illustrates one embodiment of a downhole tool designed, manufactured and / or operated according to one or more embodiments of the disclosure;

[0010] FIGS. 5A through 5D illustrate various different perspective views of different sacrificial conductive protection layers, as might be used with the downhole tool of FIG. 4;

[0011] FIGS. 6A through 6D illustrate different cross-sectional views of a downhole tool designed, manufactured and / or operated at different stages of use;

[0012] FIG. 7 illustrates one embodiment of a downhole tool designed, manufactured and / or operated according to one or more embodiments of the disclosure;

[0013] FIG. 8 illustrates one embodiment of a downhole tool designed, manufactured and / or operated according to one or more embodiments of the disclosure;

[0014] FIG. 9 illustrates one embodiment of a downhole tool designed, manufactured and / or operated according to one or more embodiments of the disclosure;

[0015] FIG. 10 illustrates one embodiment of a downhole tool designed, manufactured and / or operated according to one or more embodiments of the disclosure; and

[0016] FIG. 11 illustrates one embodiment of a downhole tool designed, manufactured and / or operated according to one or more embodiments of the disclosure.DETAILED DESCRIPTION

[0017] In the drawings and descriptions that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawn figures are not necessarily to scale. Certain features of the disclosure may be shown exaggerated in scale or in somewhat schematic form and some details of certain elements may not be shown in the interest of clarity and conciseness. The present disclosure may be implemented in embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results.

[0018] Unless otherwise specified, use of the terms “connect,”“engage,”“couple,”“attach,” or any other like 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. Furthermore, unless otherwise specified, use of the terms “up,”“upper,”“upward,”“uphole,”“upstream,” or other like terms shall be construed as generally toward the surface of the subterranean formation; likewise, use of the terms “down,”“lower,”“downward,”“downhole,”“downstream,” or other like terms shall be construed as generally toward the bottom, terminal end of a well, regardless of the wellbore orientation. Use of any one or more of the foregoing terms shall not be construed as denoting positions along a perfectly vertical axis. Additionally, unless otherwise specified, use of the term “subterranean formation” shall be construed as encompassing both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.

[0019] Various values and / or ranges are explicitly disclosed in certain embodiments herein. However, values / ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited. Similarly, values / ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited. In the same way, values / ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited. Similarly, an individual value disclosed herein may be combined with another individual value or range disclosed herein to form another range.

[0020] The term “approximately XYZ,” as used herein, means that it is within plus or minus 20percent of perfectly XYZ. The term “substantially XYZ,” as used herein, means that it is within plus or minus 10 percent of perfectly XYZ. The term “significantly XYZ,” as used herein, means that it is within plus or minus 5 percent of perfectly XYZ. The term “ideally XYZ,” as used herein, means that it is within plus or minus 1 percent of perfectly XYZ. The monicker “XYZ” could refer to parallel, perpendicular, alignment, or other relative features disclosed herein.

[0021] Turning to FIG. 1A, illustrated is a perspective view of a well system 100 including an exemplary operating environment that the apparatuses, systems and methods disclosed herein may be employed. For example, the well system 100 could use a downhole tool designed, manufactured and / or operated according to any of the embodiments, aspects, applications, variations, designs, etc. disclosed in the following paragraphs. The term downhole tool, as used herein and without limitation, includes frac plugs, bridge plugs, packers, and other tools for fluid isolation, as well as wellbore anchors, among any other downhole tool that may employ one or more inventive aspects of the disclosure.

[0022] The well system 100 illustrated in the embodiment of FIG. 1A includes a wellbore 120 extending through one or more subterranean formations 130. As those skilled in the art appreciate, the wellbore 120 may be fully cased, partially cased, or an open hole wellbore. In the illustrated embodiment of FIG. 1A, the wellbore 120 is partially cased, and thus includes a cased region 140 and an open hole region 145. The cased region 140, as is depicted, may employ casing 150 that is held into place by cement 160. Any type of casing 150 may be used and remain within the scope of the disclosure, including conductor casing, surface casing, intermediate casing, production casing, other liners, including production liners, etc..

[0023] The well system 100 illustrated in FIG. 1A may additionally include a downhole conveyance 170 deploying a downhole tool 180 within the wellbore 120. The downhole conveyance 170 can be, for example, tubing-conveyed, wireline, slickline, work string, or any other suitable means for conveying the downhole tool 180 into the wellbore 120. In one particular advantageous embodiment, the downhole conveyance 170 is American Petroleum Institute “API” pipe.

[0024] As shown in the zoomed in cross-sectional view of FIG. 1B, the downhole tool 180, in at least one embodiment, includes a material to be protected 185, as well as a sacrificial conductive protection layer 190 protecting and / or isolating the material to be protected 185 from undesirable fluids and / or solids. In the illustrated embodiment, the sacrificial conductive protection layer 190 is disposed on (e.g., directly on) the material to be protected 185, although other configurations are within the scope of the disclosure (e.g., as will be discussed below). Further to the embodiment of FIG. 1B, in one or more embodiments, a trigger device 195 may be positioned proximate the sacrificial conductive protection layer 190, the trigger device 195 for example configured to apply a voltage to the sacrificial conductive protection layer 190 to trigger a corrosion thereof based upon a triggering event, as discussed further below.

[0025] The present disclosure has recognized that certain features (e.g., referred to as “material(s) to be protected”) need protection and / or isolation from other features, whether from other fluids or solids (e.g., from other reactive fluids or solids), until such time there is a desire for the originally separated features to be able to come together. For example, expandable metal (e.g., as further understood below) and swell elastomers (e.g., as further understood below), among others, are often used to provide sealing and zonal isolation. Such materials, however, expand when exposed to wellbore fluids, and any premature exposure could interfere with the running-in-hole of the sealing and / or zonal isolation device, or alternatively could result in the sealing and / or zonal isolation device having insufficient expanding material to form a good seal (e.g., in the case of expandable metal). As a result, there is a desire to isolate and / or protect the material to be protected (e.g., from reactive fluids in one example embodiment) during run-in-hole and during wellbore cleanup (e.g., among others), but have the ability to initiate a triggering event that subsequently no longer isolates and / or protects the material to be protected from the other material. Accordingly, in at least one embodiment, the present disclosure envisions protecting the material to be protected with a sacrificial conductive protection layer, and at a subsequent point in time initiating a triggering event that triggers the corrosion (e.g., partial or full corrosion) of the sacrificial protection layer to expose the material to be protected to the feature it was previously isolated and / or protected from.

[0026] The mechanism for protecting the material to be protected using the sacrificial protection layer may take on many different forms. In at least one embodiment, the material to be protected comprises solids (e.g., as opposed to a liquid). For example, the material to be protected in this example embodiment is a piece of the material, regardless of shape (e.g., a tubular, a mandrel, a solid rod, etc.) having the sacrificial protection layer is disposed thereon. In at least one embodiment, the sacrificial conductive protection layer is disposed directly on the material to be protected, but in yet another embodiment one or more solid material layers are physically disposed between the sacrificial conductive protection layer and the material to be protected. In yet even another embodiment, the material to be protected is located in a cavity in or formed by a protective housing, and the sacrificial conductive protection layer seals against the protective housing to form a sealed chamber. In this embodiment, fluid (e.g., air or liquid) could be located in the sealed chamber surrounding the material to be protected.

[0027] Given the foregoing, the present disclosures has recognized that various different forms of electrochemistry may be used to trigger the corrosion of the sacrificial conductive protection layer to expose the material to be protected, for example based upon a triggering event. In one embodiment, the present disclosure has recognized that the application of certain voltages (e.g., provided via a power source, whether uphole or downhole) to the sacrificial conductive protection layer may be used to trigger the corrosion of the sacrificial conductive protection layer to expose the material to be protected. Accordingly, the applied voltage may be used to trigger a corrosion of the sacrificial conductive protection layer upon a triggering event.

[0028] Turning briefly to FIGS. 2A through 2C, illustrated are Pourbaix diagrams for Mg, Al, and Zn, respectively, which happen to be three materials (e.g., of many others) that the sacrificial conductive protection layer may comprise in one or more embodiments. FIGS. 2A through 2C illustrate the voltages required for various different pH values for each of the Mg, Al, and Zn to go between immunity and corrosion states. With reference to FIG. 2A, assuming a fixed pH value of 2 for the moment, the Mg would go from an immunity state to a corrosion state by applying greater than −2.6 volts. For the purpose of this analysis, the term “greater” means a value greater on a number scale (e.g., in this example, this would include −2.0 volts, −1.0 volts, 1.0 volts, 2.0 volts, etc.). With reference to FIG. 2B, assuming a fixed pH value of 2 for the moment, the Al would go from an immunity state to a corrosion state by applying greater than −1.8 volts. With reference to FIG. 2C, assuming a fixed pH value of 2 for the moment, the Zn would go from an immunity state to a corrosion state by applying greater than −1.0 volts. It should be noted that the same principle could be used with many other conductive materials that the sacrificial conductive protection layer may comprise. Accordingly, the present disclosure is not limited to just Mg, Al, and Zn sacrificial conductive protection layers, but could include others known in the art.

[0029] Given the foregoing, the present disclosure envisions positioning a trigger device proximate the sacrificial conductive protection layer, the trigger device configured to apply a voltage to the sacrificial conductive protection layer to trigger a corrosion thereof based upon a triggering event. The term “proximate,” as used herein with regard to the placement of the trigger device, means that the trigger device is located within 1000 m of the protective housing. In yet another embodiment, however, the trigger device is located within 100 m of the protective housing, if not withing 10 m of the protective housing, if not within 1 m of the protective housing, if not within 0.5 m of the protective housing, if not within 0.1 m of the protective housing. In at least one embodiment, the trigger device includes a positive electrode coupled to the sacrificial conductive protection layer and a negative electrode coupled to a separate downhole conductive layer. Out of an abundance of caution, in at least one embodiment a positive voltage may be applied to the sacrificial conductive protection layer, such that the sacrificial conductive protection layer spends at least part of its time as an anode of the circuit. The voltage applied to the sacrificial conductive protection layer, in at least one embodiment, is between 0.01 volts and 200 volts. In yet another embodiment, the voltage applied to the sacrificial conductive protection layer is between 0.5 volts and 10 volts. In at least one embodiment, the electrical current applied to the sacrificial conductive protection layer is between 0.5 milliamps and 100 amps, and in yet another embodiment is between 0.05 amps and 5 amps. In one embodiment, the positive voltage accelerates the corrosion process by up to at least 2× (e.g., in comparison to applying no voltage at all). In another embodiment, the positive voltage accelerates the corrosion process by up to at least 5×. In yet another embodiment, the positive voltage accelerates the corrosion process by up to at least 10×, and in yet another embodiment of 20× or 100×, or more. Those skilled in the art understand there may be an inherent limit on the amount that the positive voltage may speed up the corrosion process, but in at least one embodiment that limit is about 100,000×.

[0030] The voltage being applied to the sacrificial conductive protection layer may come from an AC power source or a DC power source, whether located proximate the sacrificial conductive protection layer (e.g., as that term is defined above with regard to the location of the trigger device and the sacrificial conductive protection layer), within 100 m, 10 m, 1 m, 0.5 m or 0.1 m of the sacrificial conductive protection layer, uphole of the sacrificial conductive protection layer, or for that matter outside of the wellbore. Nevertheless, in at least one embodiment, the power source is a collection of one or more batteries located downhole proximate (e.g., as that term is defined herein) the sacrificial conductive protection layer. In at least one other embodiment, the power source is a downhole power generator, such as a fluid flow turbine, among others.

[0031] The trigger device of the downhole tool may trigger the corrosion of the sacrificial conductive protection layer based upon a variety of different triggering events. In at least one embodiment, the triggering event is a lack of movement of the downhole tool. For example, when trigger circuitry of the trigger device senses the absence of movement of the downhole tool, the trigger circuitry may start a triggering sequence that will lead up to the trigger of the corrosion of the sacrificial conductive protection layer (e.g., in this embodiment the application of a voltage to the sacrificial conductive protection layer). In at least one embodiment, the sequence is an immediate application of the voltage to the sacrificial conductive protection layer, and thus an immediate trigger of the corrosion. In yet another embodiment, the sequence is a timed delay of the application of the voltage to the sacrificial conductive protection layer, and thus a timed delay of the trigger of the corrosion. In yet another embodiment, the sequence of the timed delay of the application of the voltage may commence, but if a movement of the downhole tool is sensed in the interim, the timed delay would be reset. In yet another embodiment, changes in fluid flow, temperature (e.g., through fluid swapping), pressure, etc. surrounding the trigger device may be used to start the triggering sequence. In yet another embodiment, the triggering sequence may be based upon a timer (e.g., a specific period of time after a given occurrence), a transmitted signal through a wire, a transmitted signal sent wirelessly, or from a sensing of the operation of the wellbore, among other mechanisms.

[0032] In even yet another embodiment, the downhole tool may additionally take advantage of the galvanic corrosion effect (e.g., another electrochemical process) to trigger the corrosion of the sacrificial conductive protection layer. Turning briefly to FIG. 3, illustrated is a galvanic series chart. The galvanic series (e.g., also called the electropotential series) determines the nobility of metals and semi-metals. When two metals are submerged in an electrolyte, while also electrically connected by some external conductor, the less noble (base) will experience galvanic corrosion. The rate of corrosion is determined by the electrolyte, the difference in nobility, and the relative areas of the anode and cathode exposed to the electrolyte. The difference can be measured as a difference in voltage potential: the less noble metal is the one with a lower (e.g., more negative) electrode potential than the more noble one, and will function as the anode (electron or anion attractor) within the electrolyte device functioning as a galvanic cell.

[0033] Given the foregoing, the materials for the sacrificial conductive protection layer and the separate downhole conductive layer may be chosen to further take advantage of the galvanic corrosion effect. Accordingly, those skilled in the art understand that so long as the sacrificial conductive protection layer is chosen such that its electrode potential is lower than that of the separate downhole conductive layer, the galvanic corrosion effect may also be taken advantage of. For example, the sacrificial conductive protection layer could be any one of the Mg, Al, or Zn discussed above, so long as the separate downhole conductive layer has an electrode potential of greater than −0.06, if not greater than −0.04, if not greater than −0.02, or even a positive electrode potential. Again, the present disclosure is not limited to any specific materials for the sacrificial conductive protection layer and the separate downhole conductive layer, and the present disclosure may choose to take advantage of galvanic corrosion, or choose not to take advantage of galvanic corrosion, simply based upon the specific materials chosen.

[0034] Turning to FIG. 4, illustrated is one embodiment of a downhole tool 400 designed, manufactured and / or operated according to one or more embodiments of the disclosure. The downhole tool 400, in the illustrated embodiment, includes a downhole feature 410. The downhole feature 410, in the given embodiment, is a tubular as might be used in a well system (e.g., the well system 100). Nevertheless, in yet other embodiments, the downhole feature 410 is not a tubular, but another well system feature. In the illustrated embodiment of FIG. 4, the downhole tool 400 additionally includes a protective housing 420 coupled with the downhole feature 410. In the illustrated embodiment, the protective housing 420 is positioned radially about the downhole feature 410 and forms a cavity 425. Nevertheless, other embodiments may exist wherein the protective housing 420 does not extend radially about the downhole feature 410.

[0035] In one or more embodiments, such as that shown in FIG. 4, the downhole tool 400 additionally includes a sacrificial conductive protection layer 430 sealing against the protective housing 420 around the cavity 425. For example, in at least the embodiment shown, the protective housing 420 and sacrificial conductive protection layer 430 form a sealed chamber 440. In one or more embodiments, one or more seal members 445 (e.g., O-rings) may be used to assist in the sealing of the protective housing 420 and seal chamber 440.

[0036] In accordance with one embodiment, a material to be protected 450 is located at least partially within the cavity 425 of the protective housing 420, in this embodiment disposed within the sealed chamber 440. The material to be protected 450 may comprise a variety of different materials, whether in solid form or liquid form, that one desires to keep isolated (e.g., temporarily keep isolated), for example within the sealed chamber 440 in the embodiment of FIG. 4. In at least one embodiment, a desire may exist to isolate the material to be protected 450 from features and / or substances outside of the sealed chamber 440, such as reactive solids / fluids, caustic materials, etc. In yet one other embodiment, a desire may exist to isolate features and / or substances and / or locations outside of the sealed chamber 440 from the material to be protected 450. Accordingly, unless otherwise required, the present disclosure is not limited to one or the other of these situations.

[0037] Notwithstanding the foregoing, in the embodiment of FIG. 4, the material to be protected 450 is a metal configured to expand in response to hydrolysis, also referred to as an expandable metal. The term expandable metal, as used herein, refers to the expandable metal in a pre-expansion form. Similarly, the term expanded metal, as used herein, refers to the resulting expanded metal after the expandable metal has been subjected to reactive fluid, as discussed below. The expanded metal, in accordance with one or more aspects of the disclosure, comprises a metal that has expanded in response to hydrolysis. In certain embodiments, the expanded metal includes residual unreacted metal. For example, in certain embodiments the expanded metal is intentionally designed to include the residual unreacted metal. The residual unreacted metal has the benefit of allowing the expanded metal to self-heal if cracks or other anomalies subsequently arise, or for example to accommodate changes in the tubular or mandrel diameter due to variations in temperature and / or pressure. Nevertheless, other embodiments may exist wherein no residual unreacted metal exists in the expanded metal. In at least one embodiment, the residual unreacted metal exists when the expandable metal has expanded into contact with another feature, such as another wellbore tubular, prior to all of the expanded metal reacting into expanded metal. Once the expanded metal has sealed against this wellbore tubular, the reactive fluid may no longer reach the expandable metal, and the hydrolysis essentially ends. Similarly, if all of the expandable metal has reacted into expanded metal prior to sealing against the wellbore tubular, the expanded metal may ultimately wash away.

[0038] The expandable metal, in some embodiments, may be described as expanding to a cement like material. In other words, the expandable metal goes from metal to micron-scale particles and then these particles expand and lock together to, in essence, seal two or more surfaces together. The reaction may, in certain embodiments, occur in less than 2 days in a reactive fluid and in certain temperatures. Nevertheless, the time of reaction may vary depending on the reactive fluid, the expandable metal used, the downhole temperature, surface-area-to-volume ratio (SA:V) of the expandable metal, and any dissimilar cathodic electric conductors that may be included therein (e.g., as discussed herein).

[0039] In some embodiments, the reactive fluid may be a brine solution such as may be produced during well completion activities, and in other embodiments, the reactive fluid may be one of the additional solutions discussed herein (e.g., water-based mud). The expandable metal is electrically conductive in certain embodiments. The expandable metal, in certain embodiments, has a yield strength greater than about 8,000 psi, e.g., 8,000 psi + / −50%. The expandable metal, in at least one embodiment, has a minimum dimension greater than about 1.25 mm (e.g., approximately 0.05 inches).

[0040] The hydrolysis of the expandable metal can create a metal hydroxide. The formative properties of alkaline earth metals (Mg—Magnesium, Ca—Calcium, etc.) and transition metals (Zn—Zinc, Al—Aluminum, etc.) under hydrolysis reactions demonstrate structural characteristics that are favorable for use with the present disclosure. Hydration results in an increase in size from the hydration reaction and results in a metal hydroxide that can precipitate from the fluid.

[0041] It should be noted that the starting expandable metal, unless otherwise indicated, is not a metal oxide (e.g., an insulator). In contrast, the starting expandable metal has, in certain embodiments, the properties of traditional metals: 1) Highly conductive to both electricity and heat (e.g., greater than 1,000,000 siemens per meter); 2) Contains a metallic bond (e.g., the outermost electron shell of each of the metal atoms overlaps with a large number of neighboring atoms). As a consequence, the valence electrons are allowed to move from one atom to another and are not associated with any specific pair of atoms. This gives metals their conductive nature; 3) Malleable and ductile, for example deforming under stress without cleaving; and 4) Tend to be shiny and lustrous with high density.

[0042] The hydration reactions for magnesium is:where Mg(OH)2 is also known as brucite. Another hydration reaction uses aluminum hydrolysis. The reaction forms a material known as Gibbsite, bayerite, boehmite, aluminum oxide, and norstrandite, depending on form. The possible hydration reactions for aluminum are:Another hydration reaction uses calcium hydrolysis. The hydration reaction for calcium is:Where Ca(OH)2 is known as portlandite and is a common hydrolysis product of Portland cement. Magnesium hydroxide and calcium hydroxide are considered to be relatively insoluble in water. Aluminum hydroxide can be considered an amphoteric hydroxide, which has solubility in strong acids or in strong bases. Alkaline earth metals (e.g., Mg, Ca, etc.) work well for the expandable metal, but transition metals (Al, etc.) also work well for the expandable metal. In one embodiment, the metal hydroxide is dehydrated by the swell pressure to form a metal oxide.In at least one embodiment, the expandable metal is a non-graphene based expandable metal. By non-graphene based material, it is meant that is does not contain graphene, graphite, graphene oxide, graphite oxide, graphite intercalation, or in certain embodiments, compounds and their derivatized forms to include a function group, e.g., including carboxy, epoxy, ether, ketone, amine, hydroxy, alkoxy, alkyl, aryl, aralkyl, alkaryl, lactone, functionalized polymeric or oligomeric groups, or a combination comprising at least one of the forgoing functional groups. In at least one other embodiment, the expandable metal does not include a matrix material or an exfoliatable graphene-based material. By not being exfoliatable, it means that the expandable metal is not able to undergo an exfoliation process. Exfoliation as used herein refers to the creation of individual sheets, planes, layers, laminae, etc. (generally, “layers”) of a graphene-based material; the delamination of the layers; or the enlargement of a planar gap between adjacent ones of the layers, which in at least one embodiment the expandable metal is not capable of.In yet another embodiment, the expandable metal does not include graphite intercalation compounds, wherein the graphite intercalation compounds include intercalating agents such as, for example, an acid, metal, binary alloy of an alkali metal with mercury or thallium, binary compound of an alkali metal with a Group V element (e.g., P, As, Sb, and Bi), metal chalcogenide (including metal oxides such as, for example, chromium trioxide, PbO2, MnO2, metal sulfides, and metal selenides), metal peroxide, metal hyperoxide, metal hydride, metal hydroxide, metals coordinated by nitrogenous compounds, aromatic hydrocarbons (benzene, toluene), aliphatic hydrocarbons (methane, ethane, ethylene, acetylene, n-hexane) and their oxygen derivatives, halogen, fluoride, metal halide, nitrogenous compound, inorganic compound (e.g., trithiazyl trichloride, thionyl chloride), organometallic compound, oxidizing compound (e.g., peroxide, permanganate ion, chlorite ion, chlorate ion, perchlorate ion, hypochlorite ion, As2O5, N2O5, CH3DlO4, (NH4)2S2O8, chromate ion, dichromate ion), solvent, or a combination comprising at least one of the foregoing. Thus, in at least one embodiment, the expandable metal is a structural solid expanded metal, which means that it is a metal that does not exfoliate and it does not intercalate. In yet another embodiment, the expandable metal does not swell by sorption.In an embodiment, the expandable metal used can be a metal alloy. The expandable metal alloy can be an alloy of the base expandable metal with other elements in order to either adjust the strength of the expandable metal alloy, to adjust the reaction time of the expandable metal alloy, or to adjust the strength of the resulting metal hydroxide byproduct, among other adjustments. The expandable metal alloy can be alloyed with elements that enhance the strength of the metal such as, but not limited to, Al—Aluminum, Zn—Zinc, Mn—Manganese, Zr—Zirconium, Y—Yttrium, Nd—Neodymium, Gd—Gadolinium, Ag—Silver, Ca—Calcium, Sn—Tin, and Re—Rhenium, Cu—Copper. In some embodiments, the expandable metal alloy can be alloyed with a dopant that promotes corrosion, such as Ni—Nickel, Fe—Iron, Cu—Copper, Co—Cobalt, Ir—Iridium, Au—Gold, C—Carbon, Ga—Gallium, In—Indium, Mg—Mercury, Bi—Bismuth, Sn—Tin, and Pd—Palladium. The expandable metal alloy can be constructed in a solid solution process where the elements are combined with molten metal or metal alloy. Alternatively, the expandable metal alloy could be constructed with a powder metallurgy process. The expandable metal can be cast, forged, extruded, sintered, welded, mill machined, lathe machined, stamped, eroded or a combination thereof. The metal alloy can be a mixture of the metal and metal oxide. For example, a powder mixture of aluminum and aluminum oxide can be ball-milled together to increase the reaction rate.Optionally, non-expanding components may be added to the starting metallic materials. For example, ceramic, elastomer, plastic, epoxy, glass, or non-reacting metal components can be embedded in the expandable metal or coated on the surface of the expandable metal. In yet other embodiments, the non-expanding components are metal fibers, a composite weave, a polymer ribbon, or ceramic granules, among others. In one variation, the expandable metal is formed in a serpentinite reaction, a hydration and metamorphic reaction. In one variation, the resultant material resembles a mafic material. Additional ions can be added to the reaction, including silicate, sulfate, aluminate, carbonate, and phosphate. The metal can be alloyed to increase the reactivity or to control the formation of oxides.The expandable metal can be configured in many different fashions, as long as an adequate volume of material is available for supporting the necessary features. For example, the expandable metal may be formed into a single long member and / or layer, multiple short members and / or layers, rings, among others. In another embodiment, the expandable metal may be formed into a long wire of expandable metal, which can be in turn be wound around a mandrel as a sleeve. The wire diameters do not need to be of circular cross-section, but may be of any cross-section. For example, the cross-section of the wire could be oval, rectangle, star, hexagon, keystone, hollow braided, woven, twisted, among others, and remain within the scope of the disclosure. In certain other embodiments, the expandable metal is a collection of individual separate chunks of the metal held together with a binding agent. In yet other embodiments, the expandable metal is a collection of individual separate chunks of the metal that are not held together with a binding agent, but held in place using one or more different techniques, including an enclosure (e.g., an enclosure that could be crushed to expose the individual separate chunks to the reactive fluid), a cage, etc.

[0048] Additionally, a delay coating or protective layer may be applied to one or more portions of the expandable metal to delay the expanding reactions. In one embodiment, the material configured to delay the hydrolysis process is a fusible alloy. In another embodiment, the material configured to delay the hydrolysis process is a eutectic material. In yet another embodiment, the material configured to delay the hydrolysis process is a wax, oil, or other non-reactive material. The delay coating or protective layer may be applied to any of the different expandable metal configurations disclosed above.

[0049] Returning back to FIG. 4, the protective housing 420 and the sacrificial conductive protection layer 430 may shield (e.g., temporally shield) the material to be protected 450, in this instance the expandable metal, from reactive fluids located outside of the sealed chamber 440. In at least one other embodiment, a non-reactive fluid 460 is located within the sealed chamber 440 and surrounding the material to be protected 450. The non-reactive fluid 460, in one embodiment, is deionized water, oil, or another non-reactive fluid. The non-reactive fluid 460, when used, may protect the sacrificial conductive protection layer 430 against the pressure of the wellbore, and thus prevent the sacrificial conductive protection layer 430 from failing under the pressure of the wellbore.

[0050] The downhole tool 400, in one or more embodiments, further includes a trigger device 470 positioned proximate the sacrificial conductive protection layer 430. For example, in at least one embodiment, a positive electrode 475a of the trigger device 470 is coupled to the sacrificial conductive protection layer 430 and a negative electrode 475b of the trigger device 470 is coupled to a separate downhole conductive layer 480. In at least this one embodiment, the trigger device 470 is configured to apply a voltage to the sacrificial conductive protection layer 430 to trigger a corrosion thereof based upon a triggering event, as discussed above. In the illustrated embodiment, the trigger device 470 additionally includes trigger circuitry 485, for example located in a second separate sealed chamber 490 in one or more embodiments.

[0051] Further to the embodiment of FIG. 4, in one or more embodiments, the separate downhole conductive layer 480 forms at least a portion of the second separate sealed chamber 490. For example, the separate downhole conductive layer 480 may function as the seal to the second separate sealed chamber 490. Additionally, in at least one embodiment, a trigger circuitry power source 495 may be located within the second separate sealed chamber 490. In at least this one embodiment, the trigger circuitry 485 is configured to apply the voltage to the sacrificial conductive protection layer 430 to trigger a corrosion thereof based upon a triggering event, and receiving power from the trigger circuitry power source 495. In at least one embodiment, the trigger circuitry power source 495 is an AC power source. In at least one other embodiment, such as shown, the trigger circuitry power source 495 is a DC power source, for example including one or more batteries. While not shown, in certain embodiments it is advantageous to include a fluid (e.g., non-reactive fluid) within the second separate sealed chamber 490 as well, for example to also protect the trigger circuitry 485 and trigger circuitry power source 495 from the effects of the wellbore pressure.

[0052] Turning to FIGS. 5A through 5D, illustrated are various different perspective views of different sacrificial conductive protection layers, as might be used with the downhole tool 400 of FIG. 4. Within initial reference to FIG. 5A, illustrated is a sacrificial conductive protection layer 500a. The sacrificial conductive protection layer 500a, in the illustrated embodiment, includes one or more corrodible portions 510 (e.g., exposed to an outside of the sealed chamber, such as the sealed chamber 440 of FIG. 4) and one or more non-corrodible portions 520 (e.g., exposed to an inside and / or outside of the sealed chamber, such as the sealed chamber 440 of FIG. 4). In the illustrated embodiment of FIG. 5A, the sacrificial conductive protection layer 500a is a tubular 530 of conductive material having an inside surface 540 and an outside surface 550. The sacrificial conductive protection layer 500a, in the illustrated embodiment, further includes a layer of protective material 560 disposed on the tubular 530. In at least this one embodiment, the layer of protective material 560 is precisely formed (e.g., deposited or coated) on the tubular 530 to expose portions thereof (e.g., forming the one or more corrodible portions 510) and cover other portions thereof (e.g., forming the one or more non-corrodible portions 520). Stated another way, a desired pattern of corrodible portions 510 and non-corrodible portions 520 may be formed by precisely depositing and / or coating a certain pattern of the layer of protective material 560 on the tubular 530, wherein the resulting corrodible portions 510 are those portions / sections of the tubular 530 that are not covered by the layer of protective material 560, and the resulting non-corrodible portions 520 are those portions / sections of the tubular 530 covered by the layer of protective material 560.

[0053] It should additionally be noted that in other embodiments, rather than the layer of protective material 560 originally being precisely deposited or coated at specific locations, an entirety of the tubular 530 might be coated with the layer of protective material 560, and then subsequent thereto portions of the layer of protective material 560 modified and / or removed to form the pattern of corrodible portions 510 and non-corrodible portions 520. For example, in at least one embodiment the blanket layer of protective material 560 may be modified and / or removed with a subtractive manufacturing step, such as machining, abrading etc., to form the resulting pattern of corrodible portions 510 and non-corrodible portions 520. Alternatively, a masking agent could first be applied to the tubular 530 (e.g., in regions where it is desired for the corrodible portions 510 to be located), but as the blanket layer of protective material 560 is subsequently deposited or coated on the entirety of the tubular 530, it would not adhere to those portions covered by the masking agent (e.g., thereby forming the corrodible portions 510) but would only adhere to those portions not covered by the masking agent (e.g., thereby forming the non-corrodible portions 520). Similarly, a photolithography process, for example similar to that often used in the manufacture of semiconductors, could be used to deposit, pattern, and etch the layer of protective material 560 to form the pattern of corrodible portions 510 and non-corrodible portions 520. Those skilled in the art, particularly given the new teachings herein, would understand other ways to form the corrodible portions 510 and non-corrodible portions 520, and thus unless otherwise required, any specific method could be used.

[0054] Given the foregoing, in at least one embodiment, the layer of protective material 560 may be formed on the tubular 530 of conductive material in any pattern, regardless of shape, size, or location. For example, in at least one embodiment, the layer of protective material 560 is located on one or more of the inside surface 540 (e.g., inside diameter (ID)), outside surface 550 (e.g., outside diameter (OD)), and edges 555 of the tubular 530, whether patterned or not. For example, in one embodiment, the layer of protective material 560 entirely covers the inside surface 540 (e.g., inside diameter (ID)) and edges 555 of the tubular 530, while covers less than an entirety of the outside surface 550 (e.g., outside diameter (OD)) (e.g., is patterned on the outside surface 550 in one or more different configurations, such as to form the corrodible portion 510). In yet another embodiment, the layer of protective material 560 entirely covers the outside surface 550 (e.g., outside diameter (OD)) and edges of the tubular 530, while covers less than an entirety of the inside surface 540 (e.g., inside diameter (ID)) (e.g., is patterned on the inside surface 540 in one or more different configurations, such as to form the corrodible portion 510). In even yet another embodiment, the layer of protective material 560 entirely covers the inside surface 540 (e.g., inside diameter (ID)) and outside surface 550 (e.g., outside diameter (OD)) of the tubular 530, while covers less than an entirety of the edges 555. In even yet another embodiment, any combination of the foregoing is possible, depending on the design of the device and desired location for the corrodible portions 510. It should further be understood that the corrodible portions 510 need not completely transect the thickness of the tubular 530 (e.g., the pattern on the inside surface 540 need not mirror that on the outside surface 550). Similarly, the corrodible portions 510 could be a small section of the tubular 530 that would ultimately allow the material to be protected (e.g., material to be protected 450) and an exterior of the protective housing (e.g., protective housing 420) to have access to one another, without entirely separating the tubular 530 into individual separate pieces (e.g., a plurality of centralized holes could be formed through the thickness of the sacrificial conductive protection layer 430 to provide such access).

[0055] In the illustrated embodiment of FIG. 5A, the layer of protective material 560 forms one or more rings 570a (e.g., exposed rings) of corrodible portions 510 on the outside surface 550. In accordance with one or more embodiments, the one or more corrodible portions 510 are electrically coupled with the trigger device of the downhole tool (e.g., with regard to FIG. 4, electrically coupled with the positive electrode 475a of the trigger circuitry 485). It should be noted that in one or more embodiments, such as that shown, the one or more corrodible portions extend through a thickness of the tubular. In at least one embodiment, the layer of protective material 560 includes a polymer. In yet another embodiment, the layer of protective material 560 includes an epoxy, a ceramic coating, or any other material that is suitable for creating the one or more corrodible portions 510 and one or more non-corrodible portions 520. Accordingly, unless otherwise states, the layer of protective material 560 is not limited to any specific material.

[0056] Turning to FIG. 5B, illustrated is a sacrificial conductive protection layer 500b. The sacrificial conductive protection layer 500b of FIG. 5B is similar in many respects to the sacrificial conductive protection layer 500a of FIG. 5A. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The sacrificial conductive protection layer 500b differs, for the most part, from the sacrificial conductive protection layer 500a, in that the layer of protective material 560 of the sacrificial conductive protection layer 500b forms one or more axial lines 570b of corrodible portions 510 on the outside surface 550. In at least this one embodiment, the triggering process would result in four separate remaining tubular portions that are entirely free to move relative to one another.

[0057] Turning to FIG. 5C, illustrated is a sacrificial conductive protection layer 500c. The sacrificial conductive protection layer 500c of FIG. 5C is similar in many respects to the sacrificial conductive protection layer 500a of FIG. 5A and the sacrificial conductive protection layer 500b of FIG. 5B. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The sacrificial conductive protection layer 500c, in the illustrated embodiment, includes both the one or more rings 570a and one or more axial lines 570b of corrodible portions 510, thereby forming a checkerboard pattern of corrodible portions 510 on the outside surface 550. In at least this one embodiment, the triggering process would result in approximately twenty separate remaining tubular portions that are entirely free to move relative to one another.

[0058] Turning to FIG. 5D, illustrated is a sacrificial conductive protection layer 500d. The sacrificial conductive protection layer 500d of FIG. 5D is similar in many respects to the sacrificial conductive protection layer 500a of FIG. 5A. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The sacrificial conductive protection layer 500d differs, for the most part, from the sacrificial conductive protection layer 500a, in that the layer of protective material 560 of the sacrificial conductive protection layer 500d forms one or more helical lines 570d of corrodible portions 510 on the outside surface 550. In at least this one embodiment, contrary to FIGS. 5A through 5C, the triggering process would result in a single tubular portion with a single continuous spiral gap.

[0059] The embodiments of FIGS. 5A through 5D illustrate that upon subjecting the sacrificial conductive protection layer 500c to a voltage, they may corrode, and for example provide access between an inside surface 540 of the tubular 530 and an outside surface 550 of the tubular 530, whether that through one or more holes or slots in the tubular 530 exposing the material to be protected, or allowing the tubular 530 to break into smaller pieces exposing the material to be protected. Furthermore, given the lesser surface area of a combination of the corrodible portions in one or more embodiments, less power (e.g., wattage) is needed to expose the material to be protected. For example, in at least one embodiment, a combined surface area of the one or more corrodible portions is less than 1000 percent of a combined surface area of the one or more non-corrodible portions. For example, in at least one other embodiment, the combined surface area of the one or more corrodible portions is less than 200 percent of the combined surface area of the one or more non-corrodible portions. In yet another embodiment, the combined surface area of the one or more corrodible portions is less than the combined surface area of the one or more non-corrodible portions. In yet another embodiment, the combined surface area of the one or more corrodible portions is less than 50 percent of the combined surface area of the one or more non-corrodible portions. In yet another embodiment, the combined surface area of the one or more corrodible portions is less than 10 percent of the combined surface area of the one or more non-corrodible portions. In yet another embodiment, the combined surface area of the one or more corrodible portions is less than 5 percent of the combined surface area of the one or more non-corrodible portions. In yet another embodiment, the combined surface area of the one or more corrodible portions is less than 1 percent of the combined surface area of the one or more non-corrodible portions. In yet another embodiment, such as when a trigger circuitry power source 495 is employed downhole, the combined surface area of the one or more corrodible portions ranges from 0.1 percent to 10 percent of the combined surface area of the one or more non-corrodible portions, if not from 1 percent to 5 percent, for example to reduce the amount of power required to expose the layer of protective material 560. In at least one other embodiment, the one or more corrodible portions have a combined corrodible portion outer surface area exposed to the outside of the sealed chamber and the one or more non-corrodible portions have a combined non-corrodible portion outer surface area exposed to the outside of the sealed chamber. Any of the above percentages may be used in this alternative embodiment, nevertheless, in at least one embodiment, a combined surface area of the one or more corrodible portions is less than 10 percent of a combined surface area of the one or more non-corrodible portions.

[0060] Turning to FIGS. 6A through 6D, illustrated are different cross-sectional views of a downhole tool 600 designed, manufactured and / or operated at different stages of use. The downhole tool 600 of FIGS. 6A through 6D is similar in many respects to the downhole tool 400 of FIG. 4. Accordingly, like reference numbers have been used to indicate similar, if not identical features.

[0061] With initial reference to FIG. 6A, the downhole tool 600 has been positioned within a conduit 610. The conduit 610 may be any tubular employed in a well system, such wellbore casing in one embodiment. In the illustrated embodiment of FIG. 6A, little to no fluid surrounds the downhole tool 600. Nevertheless, in yet other embodiments, one or more fluids may be located in the conduit 610 and surrounding the downhole tool 600.

[0062] Turning to FIG. 6B, illustrated is the downhole tool 600 of FIG. 6A after pumping fluid 620 (e.g., including mud) downhole and into the conduit 610. The fluid 620, in at least one embodiment, is reactive fluid, such as might be used to cause the expandable metal to expand in response to hydrolysis. However, as the material to be protected 450 is isolated from the reactive fluid, the hydrolysis may not begin. In yet another embodiment, the fluid 620 is a non-reactive fluid. In the illustrated embodiment, the fluid 620 is a conductive fluid. At this stage, no triggering event has occurred.

[0063] Turning to FIG. 6C, illustrated is the downhole tool 600 of FIG. 6B after a triggering event has occurred (e.g., any one of the triggering events disclosed above, or other known or hereafter discovered triggering events), and thus the trigger device 470 applies a suitable voltage to sacrificial conductive protection layer 430 (e.g., through the sacrificial conductive protection layer pumping fluid 620 in one embodiment). As shown, the voltage causes the sacrificial conductive protection layer 430 to corrode, and thus go away. Accordingly, the material to be protected 450 is no longer protected within the sealed chamber 440. It should further be noted that, depending on the materials chosen for the sacrificial conductive protection layer 430 and the separate downhole conductive layer 480, the existence of an electrolyte (e.g., the fluid 620) may allow the downhole tool 600 to take further advantage of the galvanic corrosion effect.

[0064] Turning to FIG. 6D, illustrated is the downhole tool 600 of FIG. 6C after the fluid 620 (e.g., reactive fluid in the given embodiment) chemically reacts with the material to be protected 450 (e.g., a metal configured to expand in response to hydrolysis in this embodiment) to form an expanded metal seal 630.

[0065] It should be noted that while FIGS. 6A through 6D illustrate complete removal of the sacrificial conductive protection layer 430, other embodiments may exist wherein less than complete removal of the sacrificial conductive protection layer 430 (e.g., but sufficient removal to exposed the material to be protected) may occur. This is evident with the different designs for the sacrificial conductive protection layer discussed and illustrated with respect to FIGS. 5A through 5D.

[0066] Turning now to FIG. 7, illustrated is a downhole tool 700 designed, manufactured and / or operated according to one or more alternative embodiments of the disclosure. The downhole tool 700 of FIG. 7 is similar in many respects to the downhole tool 400 of FIG. 4. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 700 differs, for the most part, from the downhole tool 400, in that the downhole tool 700 does not employ a trigger circuitry power source 495 located proximate the material to be protected 450, or even within the second separate sealed chamber 490, but its trigger circuitry power source is located uphole of the downhole tool 700. In at least one embodiment, the trigger circuitry power source coupled to the downhole tool 700 is located many meters above the downhole tool 700, if not outside of the wellbore.

[0067] Turning now to FIG. 8, illustrated is a downhole tool 800 designed, manufactured and / or operated according to one or more alternative embodiments of the disclosure. The downhole tool 800 of FIG. 8 is similar in many respects to the downhole tool 400 of FIG. 4. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 800 differs, for the most part, from the downhole tool 400, in that the material to be protected 850 is a swellable material (e.g., swell elastomer) configured to swell by absorption after the triggering event, for example to form a swellable material seal. Those skilled in the art understand the various different swellable materials that could be used for the material to be protected 850. The swell elastomer, in one or more embodiments, may comprise elastomers that swell in water / brine and / or hydrocarbons, and is not limited to any specific composition. Common water-swell / brine-swell base elastomers include: Ethylene-Propylene-Diene Monomer Rubber (“EPDM”) (terpolymer of ethylene, propylene, and a diene monomer); Ethylene-Propylene Rubber (“EPM”) (copolymer of ethylene and propylene; non-diene version of EPDM); Blends of Acrylonitrile-Butadiene Rubber and Hydrogenated Acrylonitrile-Butadiene Rubber with hydrophilic polymer additives (“NBR” / “HNBR” blends with hydrophilic packages) (used to promote controlled water or brine swelling). Common oil-swell / hydrocarbon-swell base elastomers include: Acrylonitrile-Butadiene Rubber (“NBR”) (sometimes called Nitrile Butadiene Rubber; copolymer of acrylonitrile and butadiene); Hydrogenated Acrylonitrile-Butadiene Rubber (“HNBR”) (chemically hydrogenated version of NBR for improved heat and oxidation resistance); Fluorocarbon Rubber (“FKM”) (Fluoroelastomer) (terpolymer or copolymer based on vinylidene fluoride, hexafluoropropylene, and / or tetrafluoroethylene; “Viton®” is a common trade name); Tetrafluoroethylene-Propylene Rubber (“FEPM” (AFLAS-type)) (fluoroelastomer based on tetrafluoroethylene and propylene; marketed under trade names such as AFLAS®). Some less common swell elastomers include: Perfluoroelastomer Rubber (“FFKM”) ; (fluoroelastomers in which nearly all hydrogen atoms are replaced by fluorine; extremely high chemical and temperature resistance); Polychloroprene Rubber (“CR” (Neoprene)); Acrylic Rubber (“ACM”) (copolymer of alkyl acrylates); Ethylene-Acrylic Rubber (“AEM”) (copolymer of ethylene and acrylic monomers); Vinyl-Methyl Polysiloxane Rubber (“VMQ” (Silicone rubber)) (standard methyl-vinyl silicone elastomer).

[0068] The downhole tool 800, in the embodiment of FIG. 8, does not employ the non-reactive fluid 460, or any fluid, within the sealed chamber 440. Furthermore, in at least the embodiment of FIG. 8, a very small space exists between the material to be protected 850 and the sacrificial conductive protection layer 430, thus minimizing any pressure issues that may exist.

[0069] Turning now to FIG. 9, illustrated is a downhole tool 900 designed, manufactured and / or operated according to one or more alternative embodiments of the disclosure. The downhole tool 900 of FIG. 9 is similar in many respects to the downhole tool 400 of FIG. 4. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 900 differs, for the most part, from the downhole tool 400, in that the material to be protected 950 of the downhole tool 900 is a collection of solid particles configured to move to a different location within a wellbore (e.g., exit the sealed chamber and move to a different location within the wellbore) after the triggering event. For example, in at least one embodiment the collection of solid particles release and go into solution after the triggering event, such as anhydrous acids or salts, among others. The material to be protected 950, in one embodiment, may further include a tracer, the tracer providing information related to the triggering event, such as an indication that the material to be protected 950 is no longer protected.

[0070] Turning now to FIG. 10, illustrated is a downhole tool 1000 designed, manufactured and / or operated according to one or more alternative embodiments of the disclosure. The downhole tool 1000 of FIG. 10 is similar in many respects to the downhole tool 900 of FIG. 9. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 1000 differs, for the most part, from the downhole tool 900, in that the material to be protected 950 of the downhole tool 1000 is located within a volume of fluid 1010. In yet another embodiment, the material to be protected 950 may contain a viscosifier (e.g., like a gelling agent), a colloidal latex, etc., among others.

[0071] Turning now to FIG. 11, illustrated is a downhole tool 1100 designed, manufactured and / or operated according to one or more alternative embodiments of the disclosure. The downhole tool 1100 of FIG. 11 is similar in many respects to the downhole tool 400 of FIG. 4. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 1100 differs, for the most part, from the downhole tool 400, in that the material to be protected 1150 of the downhole tool 1100 is a volume of fluid configured to move to a different location within a wellbore (e.g., exit the sealed chamber and move to a different location within the wellbore) after the triggering event.

[0072] Aspects disclosed herein include:

[0073] A. A downhole tool, the downhole tool including: 1) material to be protected; 2) a sacrificial conductive protection layer positioned about the material to be protected, the sacrificial conductive protection layer configured to isolate the material to be protected from an undesirable material; and 3) a positive electrode and a negative electrode, the positive electrode coupled to the sacrificial conductive protection layer and the negative electrode coupled to a separate conductive feature, the sacrificial conductive protection layer configured to receive a voltage via the positive electrode from a trigger device to trigger a corrosion thereof based upon a triggering event.

[0074] B. A downhole tool, the downhole tool including: 1) a protective housing; 2) a sacrificial conductive protection layer sealing against the protective housing, the protective housing and sacrificial conductive protection layer forming a sealed chamber; 3) material to be protected disposed within the sealed chamber; and d) a trigger device positioned proximate the sacrificial conductive protection layer, the trigger device including a positive electrode coupled to the sacrificial conductive protection layer and a negative electrode coupled to a separate downhole conductive layer, the trigger device configured to apply a voltage to the sacrificial conductive protection layer to trigger a corrosion thereof based upon a triggering event.

[0075] C. A method, the method including: 1) positioning a downhole tool within a wellbore extending through one or more subterranean formations, the downhole tool including: a) material to be protected; b) a sacrificial conductive protection layer positioned about the material to be protected, the sacrificial conductive protection layer configured to isolate the material to be protected from an undesirable material; and c) a positive electrode coupled to the sacrificial conductive protection layer and a negative electrode coupled to a separate conductive feature; and 2) applying a voltage to the sacrificial conductive protection layer via the positive electrode to trigger a corrosion of the sacrificial conductive protection and expose the material to be protected.

[0076] D. A method, the method including: 1) positioning a downhole tool within a wellbore extending through one or more subterranean formations, the downhole tool including: a) a protective housing; b) a sacrificial conductive protection layer sealing against the protective housing, the protective housing and sacrificial conductive protection layer forming a sealed chamber; c) material to be protected disposed within the sealed chamber; and d) a trigger device positioned proximate the sacrificial conductive protection layer, the trigger device including a positive electrode coupled to the sacrificial conductive protection layer and a negative electrode coupled to a separate downhole conductive layer, the trigger device configured to apply a voltage to the sacrificial conductive protection layer to trigger a corrosion thereof based upon a triggering event; and 2) triggering the trigger device to corrode the sacrificial conductive protection layer and expose the material to be protected to an outside of the sealed chamber.

[0077] E. A well system, the well system including: 1) a wellbore extending through one or more subterranean formations; and 2) a downhole tool positioned within the wellbore, the downhole tool including: a) material to be protected; b) a sacrificial conductive protection layer positioned about the material to be protected, the sacrificial conductive protection layer configured to isolate the material to be protected from an undesirable material; and c) a positive electrode and a negative electrode, the positive electrode coupled to the sacrificial conductive protection layer and the negative electrode coupled to a separate conductive feature, the sacrificial conductive protection layer configured to receive a voltage via the positive electrode from a trigger device to trigger a corrosion thereof based upon a triggering event.

[0078] F. A well system, the well system including: 1) a wellbore extending through one or more subterranean formations; and 2) a downhole tool positioned within the wellbore, the downhole tool including: a) a protective housing; b) a sacrificial conductive protection layer sealing against the protective housing, the protective housing and sacrificial conductive protection layer forming a sealed chamber; c) material to be protected disposed within the sealed chamber; and d) a trigger device positioned proximate the sacrificial conductive protection layer, the trigger device including a positive electrode coupled to the sacrificial conductive protection layer and a negative electrode coupled to a separate downhole conductive layer, the trigger device configured to apply a voltage to the sacrificial conductive protection layer to trigger a corrosion thereof based upon a triggering event.

[0079] Aspects A, B, C, D, E and F may have one or more of the following additional elements in combination: Element 1: further including a protective housing, wherein the material to be protected is located at least partially within a cavity of the protective housing. Element 2: wherein the sacrificial protection layer seals against the protective housing around the cavity to form a sealed chamber around the material to be protected. Element 3: wherein the sealed chamber is a first sealed chamber, and further wherein the trigger device includes trigger circuitry located in a second separate sealed chamber. Element 4: wherein the separate conductive feature is a separate downhole conductive layer that forms at least a portion of the second separate sealed chamber. Element 5: further including a trigger circuitry power source located within the second separate sealed chamber, the trigger circuitry configured to apply the voltage to the sacrificial conductive protection layer to trigger the corrosion thereof based upon the triggering event and receiving power from the trigger circuitry power source. Element 6: wherein the trigger circuitry power source is an AC power source. Element 7: wherein the trigger circuitry power source is a DC power source including one or more batteries. Element 8: wherein the sacrificial conductive protection layer includes one or more corrodible portions exposed to an outside thereof and one or more non-corrodible portions exposed to an inside thereof. Element 9: wherein the sacrificial conductive protection layer is a tubular of conductive material having an inside surface and an outside surface, and further including a layer of protective material disposed on the tubular of conductive material to form the one or more corrodible portions and the one or more non-corrodible portions on the outside surface. Element 10: wherein the layer of protective material forms one or more rings of corrodible portions on the outside surface. Element 11: wherein the layer of protective material also forms one or more axial lines of corrodible portions on the outside surface to form a checkerboard pattern of corrodible portions on the outside surface. Element 12: wherein the layer of protective material forms one or more axial lines of corrodible portions on the outside surface. Element 13: wherein the layer of protective material forms one or more helical lines of corrodible portions on the outside surface. Element 14: wherein the one or more corrodible portions of the outside surface have a combined corrodible portion outer surface area and the one or more non-corrodible portions of the outside surface have a combined non-corrodible portion outer surface area, and further wherein a combined surface area of the one or more corrodible portions is less than 10 percent of a combined surface area of the one or more non-corrodible portions. Element 15: wherein the material to be protected includes metal configured to expand in response to hydrolysis after the triggering event. Element 16: wherein the metal configured to expand in response to hydrolysis includes one or more layers of metal configured to expand in response to hydrolysis. Element 17: wherein the one or more layers of metal configured to expand in response to hydrolysis are located in a sealed chamber, and further including a non-reactive fluid located in the sealed chamber and surrounding the one or more layers of metal configured to expand in response to hydrolysis. Element 18: wherein the material to be protected is swellable material configured to swell by absorption after the triggering event. Element 19: wherein the material to be protected is a collection of solid particles configured to move to a different location within a wellbore after the triggering event. Element 20: wherein the collection of solid particles are located within a volume of fluid. Element 21: wherein the material to be protected is a volume of fluid configured to move to a different location within a wellbore after the triggering event. Element 22: further including a protective housing coupled with a downhole feature, wherein the material to be protected is located at least partially within a cavity of the protective housing. Element 23: wherein the applying the voltage includes applying the voltage from a triggering device located proximate the sacrificial conductive protection layer. Element 24: wherein the triggering device applies the voltage based upon a triggering event. Element 25: further including a protective housing, wherein the material to be protected is at least partially located within a cavity of the protective housing and the sacrificial conductive protection layer seals against the protective housing around the cavity to form a sealed chamber around the material to be protected. Element 26: wherein the material to be protected includes metal configured to expand in response to hydrolysis, and further wherein applying the voltage allows the metal configured to expand in response to hydrolysis to expand to form an expanded metal seal. Element 27: wherein the material to be protected is a swellable material configured to swell by absorption, and further wherein applying the voltage allows the swellable material to swell by absorption to form a swellable material seal. Element 28: wherein the material to be protected is a collection of solid particles located within a sealed chamber, and further wherein applying the voltage allows the collection of solid particles to exit the sealed chamber and move to a different location within the wellbore. Element 29: wherein the material to be protected is a volume of fluid located within a sealed chamber, and further wherein applying the voltage allows the volume of fluid to exit the sealed chamber and move to a different location within the wellbore.

[0080] Those skilled in the art to which this application relates will appreciate that other and further additions, deletions, substitutions and modifications may be made to the described embodiments.

Examples

Embodiment Construction

[0017]In the drawings and descriptions that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawn figures are not necessarily to scale. Certain features of the disclosure may be shown exaggerated in scale or in somewhat schematic form and some details of certain elements may not be shown in the interest of clarity and conciseness. The present disclosure may be implemented in embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results.

[0018]Unless otherwise specified,...

Claims

1. A downhole tool, comprising:material to be protected;a sacrificial conductive protection layer positioned about the material to be protected, the sacrificial conductive protection layer configured to isolate the material to be protected from an undesirable material; anda positive electrode and a negative electrode, the positive electrode coupled to the sacrificial conductive protection layer and the negative electrode coupled to a separate conductive feature, the sacrificial conductive protection layer configured to receive a voltage via the positive electrode from a trigger device to trigger a corrosion thereof based upon a triggering event.

2. The downhole tool as recited in claim 1, further including a protective housing, wherein the material to be protected is located at least partially within a cavity of the protective housing.

3. The downhole tool as recited in claim 2, wherein the sacrificial conductive protection layer seals against the protective housing around the cavity to form a sealed chamber around the material to be protected.

4. The downhole tool as recited in claim 3, wherein the sealed chamber is a first sealed chamber, and further wherein the trigger device includes trigger circuitry located in a second separate sealed chamber.

5. The downhole tool as recited in claim 4, wherein the separate conductive feature is a separate downhole conductive layer that forms at least a portion of the second separate sealed chamber.

6. The downhole tool as recited in claim 4, further including a trigger circuitry power source located within the second separate sealed chamber, the trigger circuitry configured to apply the voltage to the sacrificial conductive protection layer to trigger the corrosion thereof based upon the triggering event and receiving power from the trigger circuitry power source.

7. The downhole tool as recited in claim 6, wherein the trigger circuitry power source is an AC power source.

8. The downhole tool as recited in claim 6, wherein the trigger circuitry power source is a DC power source including one or more batteries.

9. The downhole tool as recited in claim 1, wherein the sacrificial conductive protection layer includes one or more corrodible portions exposed to an outside thereof and one or more non-corrodible portions exposed to an inside thereof.

10. The downhole tool as recited in claim 9, wherein the sacrificial conductive protection layer is a tubular of conductive material having an inside surface and an outside surface, and further including a layer of protective material disposed on the tubular of conductive material to form the one or more corrodible portions and the one or more non-corrodible portions on the outside surface.

11. The downhole tool as recited in claim 10, wherein the layer of protective material forms one or more rings of corrodible portions on the outside surface.

12. The downhole tool as recited in claim 11, wherein the layer of protective material also forms one or more axial lines of corrodible portions on the outside surface to form a checkerboard pattern of corrodible portions on the outside surface.

13. The downhole tool as recited in claim 10, wherein the layer of protective material forms one or more axial lines of corrodible portions on the outside surface.

14. The downhole tool as recited in claim 10, wherein the layer of protective material forms one or more helical lines of corrodible portions on the outside surface.

15. The downhole tool as recited in claim 10, wherein the one or more corrodible portions of the outside surface have a combined corrodible portion outer surface area and the one or more non-corrodible portions of the outside surface have a combined non-corrodible portion outer surface area, and further wherein a combined surface area of the one or more corrodible portions is less than 10 percent of a combined surface area of the one or more non-corrodible portions.

16. The downhole tool as recited in claim 1, wherein the material to be protected includes metal configured to expand in response to hydrolysis after the triggering event.

17. The downhole tool as recited in claim 16, wherein the metal configured to expand in response to hydrolysis includes one or more layers of metal configured to expand in response to hydrolysis.

18. The downhole tool as recited in claim 17, wherein the one or more layers of metal configured to expand in response to hydrolysis are located in a sealed chamber, and further including a non-reactive fluid located in the sealed chamber and surrounding the one or more layers of metal configured to expand in response to hydrolysis.

19. The downhole tool as recited in claim 1, wherein the material to be protected is swellable material configured to swell by absorption after the triggering event.

20. The downhole tool as recited in claim 1, wherein the material to be protected is a collection of solid particles configured to move to a different location within a wellbore after the triggering event.

21. The downhole tool as recited in claim 20, wherein the collection of solid particles are located within a volume of fluid.

22. The downhole tool as recited in claim 1, wherein the material to be protected is a volume of fluid configured to move to a different location within a wellbore after the triggering event.

23. The downhole tool as recited in claim 1, further including a protective housing coupled with a downhole feature, wherein the material to be protected is located at least partially within a cavity of the protective housing.

24. A downhole tool, comprising:a protective housing;a sacrificial conductive protection layer sealing against the protective housing, the protective housing and sacrificial conductive protection layer forming a sealed chamber;material to be protected disposed within the sealed chamber; anda trigger device positioned proximate the sacrificial conductive protection layer, the trigger device including a positive electrode coupled to the sacrificial conductive protection layer and a negative electrode coupled to a separate downhole conductive layer, the trigger device configured to apply a voltage to the sacrificial conductive protection layer to trigger a corrosion thereof based upon a triggering event.

25. A method, comprising:positioning a downhole tool within a wellbore extending through one or more subterranean formations, the downhole tool including:material to be protected;a sacrificial conductive protection layer positioned about the material to be protected, the sacrificial conductive protection layer configured to isolate the material to be protected from an undesirable material; anda positive electrode and a negative electrode, the positive electrode coupled to the sacrificial conductive protection layer and the negative electrode coupled to a separate conductive feature; andapplying a voltage to the sacrificial conductive protection layer via the positive electrode to trigger a corrosion of the sacrificial conductive protection layer and expose the material to be protected.

26. The method as recited in claim 25, wherein the applying the voltage includes applying the voltage from a triggering device located proximate the sacrificial conductive protection layer.

27. The method as recited in claim 26, wherein the triggering device applies the voltage based upon a triggering event.

28. The method as recited in claim 25, further including a protective housing, wherein the material to be protected is at least partially located within a cavity of the protective housing and the sacrificial conductive protection layer seals against the protective housing around the cavity to form a sealed chamber around the material to be protected.

29. The method as recited in claim 25, wherein the material to be protected includes metal configured to expand in response to hydrolysis, and further wherein applying the voltage allows the metal configured to expand in response to hydrolysis to expand to form an expanded metal seal.

30. The method as recited in claim 25, wherein the material to be protected is a swellable material configured to swell by absorption, and further wherein applying the voltage allows the swellable material to swell by absorption to form a swellable material seal.

31. The method as recited in claim 25, wherein the material to be protected is a collection of solid particles located within a sealed chamber, and further wherein applying the voltage allows the collection of solid particles to exit the sealed chamber and move to a different location within the wellbore.

32. The method as recited in claim 25, wherein the material to be protected is a volume of fluid located within a sealed chamber, and further wherein applying the voltage allows the volume of fluid to exit the sealed chamber and move to a different location within the wellbore.

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