DISSOLVABLE, PROTECTIVE COVERING FOR DOWNHOLE TOOL COMPONENTS

Abstract

A downhole tool can include: an inner mandrel; at least one component, wherein a portion of the at least one component moves in a direction radially away from the inner mandrel when the downhole tool is set; and a protective covering, wherein the protective covering comprises a dissolvable material, and wherein the protective covering partially surrounds an outer diameter of the at least one component when the downhole tool is run-in. The downhole tool can be introduced into a wellbore. The protective covering can dissolve via chemical reactions of metals, metal alloys, or metal oxides, or by melting of a thermoplastic. The downhole tool can be set after the protective covering has dissolved. The tool can be a packer assembly, bridge plug, frac pack plug, or liner hangers. The at least one component of the downhole tool can be a sealing element, a collet, a split wedge, or a slip.

Description

TECHNICAL FIELD

Downhole tools are made from a variety of components. Some components, such as sealing elements and slips, can be damaged during placement of the downhole tool into a wellbore. Swellable components can also undergo premature expansion during placement of the downhole tool into the wellbore. A protective covering can wholly or partially surround one or more downhole tool components. The protective covering can dissolve after placement of the downhole tool into the wellbore.

BRIEF DESCRIPTION OF THE FIGURES

The features and advantages of certain embodiments will be more readily appreciated when considered in conjunction with the accompanying figures. The figures are not to be construed as limiting any of the preferred embodiments.

FIG. 1 is a schematic illustration of a well system containing a packer assembly according to certain embodiments.

FIG. 2A is a schematic illustration of a well system containing a packer assembly with a protective covering in a run-in position according to certain embodiments.

FIG. 2B is a schematic illustration of the well system of FIG. 2A after placement of the packer assembly and dissolution of the protective covering according to certain embodiments.

FIG. 3 is a cross-sectional view of a downhole tool comprising a slip and the protective covering according certain other embodiments.

FIG. 4A is a partial cross-sectional view of a packer assembly containing three sealing elements and a protective covering encasing all three sealing elements according to certain embodiments.

FIG. 4B is a partial cross-sectional view of a packer assembly containing three sealing elements and three protective coverings according to certain other embodiments.

DETAILED DESCRIPTION

Oil and gas hydrocarbons are naturally occurring in some subterranean formations. In the oil and gas industry, a subterranean formation containing oil and/or gas is referred to as a reservoir. A reservoir can be located under land or off shore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce oil or gas, a wellbore is drilled into a reservoir or adjacent to a reservoir. The oil, gas, or water produced from a reservoir is called a reservoir fluid.

As used herein, a “fluid” is a substance having a continuous phase that can flow and conform to the outline of its container when the substance is tested at a temperature of 71° F. (22° C.) and a pressure of one atmosphere “atm” (0.1 megapascals “MPa”). A fluid can be a liquid or gas. A homogenous fluid has only one phase; whereas a heterogeneous fluid has more than one distinct phase. A colloid is an example of a heterogeneous fluid. A heterogeneous fluid can be: a slurry, which includes a continuous liquid phase and undissolved solid particles as the dispersed phase; an emulsion, which includes a continuous liquid phase and at least one dispersed phase of immiscible liquid droplets; a foam, which includes a continuous liquid phase and a gas as the dispersed phase; or a mist, which includes a continuous gas phase and liquid droplets as the dispersed phase. As used herein, the term “base fluid” means the solvent of a solution or the continuous phase of a heterogeneous fluid and is the liquid that is in the greatest percentage by volume of a treatment fluid.

A well can include, without limitation, an oil, gas, or water production well, an injection well, or a geothermal well. As used herein, a “well” includes at least one wellbore. A wellbore can include vertical, inclined, and horizontal portions, and it can be straight, curved, or branched. As used herein, the term “wellbore” includes any cased, and any uncased, open-hole portion of the wellbore. A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. As used herein, a “well” also includes the near-wellbore region. The near-wellbore region is generally considered to be the region within approximately 100 feet radially of the wellbore. As used herein, “into a wellbore” means and includes into any portion of the well.

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

It is not uncommon for a wellbore to extend several hundreds of feet or several thousands of feet into a subterranean formation. The subterranean formation can have different zones. A zone is an interval of rock differentiated from surrounding rocks on the basis of its fossil content or other features, such as faults or fractures. For example, one zone can have a higher permeability compared to another zone. It is often desirable to treat one or more locations within multiples zones of a formation. One or more zones of the formation can be isolated within the wellbore via the use of a downhole tool called an isolation device.

During well completion, it is commonly desired to seal a portion of an annulus so fluids will not flow through the annulus but rather flow through the tubing string or casing. By sealing the portion of the annulus, oil, gas, water, or combinations thereof can be produced in a controlled manner through the wellhead via the tubing string or casing. Different downhole tools can be used to create seals in the well. Examples of such tools include packers and bridge plugs.

Packers can be utilized to seal the annulus in a wellbore. Typically, packers are used to anchor the tubing to the wellbore and to seal the tubing to the wellbore. A packer can be used in cased wellbore portions or open-hole wellbore portions. A packer can include a sealing element that seals to the wellbore to isolate the portion of the wellbore and can also include slips that grip the inside of a casing or wall of the wellbore to anchor the packer to the casing or wellbore wall.

Swellable sealing elements can be used to create a seal in the wellbore. A setting method can activate or energize sealing elements and slips while a releasing method can return the packer to the un-set position. A gravel pack packer can use a setting tool to apply compression to energize the sealing element and slips. A hydraulic packer has an internal setting piston that is hydraulically actuated to apply the compression to energize the sealing element and slips. A hydrostatic set packer has an atmospheric chamber that collapses with well hydrostatic pressure to supply the compressive forces needed to set the packer. A mechanical packer uses compression of the tubing string to apply the compressive force needed to energize the element and slips. All of these types of packers have a sealing element that is a ring of elastomeric material fitted on the outside of a mandrel. The actuation of the packer axially squeezes the sealing element to cause radial expansion of the sealing element and seals the annulus. The actuation of the packer deploys the slips to grip and anchor the packer to the inside of the casing or wall of the wellbore. For swellable sealing elements, exposure to a swelling fluid will cause the sealing element to swell or expand radially away from the inner mandrel to create a seal in the wellbore.

A bridge plug is composed primarily of slips, a plug mandrel, and a rubber sealing element. A bridge plug can be introduced into a wellbore and the sealing element can be caused to block fluid flow into downstream zones when the bridge plug is set. As used herein, the term “set” and all grammatical variations thereof means the act of causing or allowing a downhole tool to be permanently or retrievably fixed at a desired location within a wellbore—generally by movement of one or more tool components radially away from an inner mandrel and into contact with an inner diameter of a casing, tubing string, or wellbore wall.

A packer can be introduced into or run into the wellbore on a work string or on a production tubing during the course of treating and preparing the well for production. As used herein, the terms “run into” and “run-in” mean the time during which the downhole tool is being introduced into a wellbore at a desired location. The packer can act as an isolation device. For example, the packer can be used to substantially seal the annulus between the outside of the production tubing and the inside of the casing or wall of the wellbore by blocking the movement of fluids through the annulus past the packer location. Packers can also be used as service tools.

Some components of downhole tools can be damaged during run-in. By way of example, components can be damaged from debris or small particles in the run-in fluid. Another example is swabbing of a sealing element. When running packers having thin cross-sectional elements or soft flexible elements, there is a propensity for these elements to stretch radially due to fluid flow past the packer and to slide off the packer assembly. This is commonly referred to as swabbing, and can result in reduced running speed to keep the elements in place. Fluid flow past the packer can also cause slips or other components that are intended to move radially outwards away from an inner mandrel after setting to prematurely move outwardly. Thus, there is a need and an on-going industry wide concern to solve the aforementioned problems associated with downhole tool components.

It has been discovered that a protective covering can wholly or partially surround one or more downhole tool component in during run-in. The protective covering can dissolve after a desired period of time to allow the components to function as intended. Another advantage is the ability to use components having a very low (i.e., 30 to 60 durometer) elastomeric materials that would have a much higher conformity to rough surfaces due to the reduced hardness of the material. As used herein, the term “dissolve” and all grammatical variations thereof means a chemical compound that begins as a solid and becomes a liquid when exposed to a solvent or heat. For example, a solid can dissolve and either completely ionizes to form a solution with no precipitate or does not completely ionize and forms a heterogeneous fluid having small precipitate particles in the dispersed phase.

According to any of the embodiments, a downhole tool can include: an inner mandrel; at least one component, wherein a portion of the at least one component moves in a direction radially away from the inner mandrel when the downhole tool is set; and a protective covering, wherein the protective covering comprises a dissolvable material, and wherein the protective covering partially surrounds an outer diameter of the at least one component when the downhole tool is run-in.

According to any of the embodiments, a method of introducing a downhole tool into a wellbore can include: (A) positioning the downhole tool at a desired location within the wellbore, wherein the downhole tool comprises: an inner mandrel; at least one component; and a protective covering, wherein the protective covering comprises a dissolvable material, and wherein the protective covering partially surrounds an outer diameter of the at least one component while the downhole tool is being positioned at the desired location within the wellbore; (B) causing or allowing the protective covering to dissolve; and (C) setting the downhole tool at the desired location within the wellbore after the protective covering has dissolved, wherein a portion of the at least one component moves in a direction radially away from the inner mandrel during setting.

It is to be understood that the discussion of any of the embodiments regarding the downhole tool or any component of the downhole tool is intended to apply to all of the method and apparatus embodiments without the need to repeat the various embodiments throughout.

The downhole tool can be any tool used in an oil or gas operation that has one or more components that expand radially away from an inner mandrel. Examples of downhole tools having such components can include, but are not limited to, a packer assembly, a bridge plug, liner hangers, and frac pack plugs. The downhole tool can be used for a variety of oil and gas operations, such as, for zonal isolation, gravel packing, milling operations, and liner hangers.

Turning to the Figures, FIG. 1 depicts a well system 10. The well system 10 can include at least one wellbore 11. The wellbore 11 can penetrate a subterranean formation 12. The wellbore 11 comprises a wall 13. The subterranean formation 12 can be a portion of a reservoir or adjacent to a reservoir. The wellbore 11 can include a casing 14. The wellbore 11 can include only a generally vertical wellbore section or can include only a generally horizontal wellbore section. One or more tubing strings, for example, a tubing string 15 can be installed in the wellbore 11. The tubing string 15 can provide a conduit for fluids to travel from the formation to the surface of the wellbore 11 or vice versa. A downhole tool, for example, a packer assembly 16, can be run into the wellbore 11. It is to be understood that while the various embodiments can refer to a “packer assembly,” other downhole tools, such as bridge plugs, liner hangers, and frac pack plugs, are not to be excluded. A packer assembly 16 can provide an annular seal between the outside of the tubing string 15 and the inside of the casing 14 or wall of the wellbore 13 to define zones 17, 18. The packer assembly 16 can also be used between the outside of a first tubing string and the inside of a second tubing string (not shown). The packer assembly 16 can be used to seal or “pack off” the wellbore 11 such that the flow path of fluids in the wellbore 11 can be redirected.

It should be noted that the well system 10 illustrated in the drawings and described herein is merely one example of a wide variety of well systems in which the principles of this disclosure can be utilized. For instance, the wellbore 11 can have a horizontal section and a vertical section. It should be clearly understood that the principles of this disclosure are not limited to any of the details of the well system 10, or components thereof, depicted in the drawings or described herein. Furthermore, the well system 10 can include other components, such as, production tubing, screens, and other isolation devices not depicted in the drawing. According to the various embodiments, one or more packers can be introduced into multi-zone completions, between an inner and outer string, and in a vertical and/or horizontal section of the wellbore 11. The packer assembly 16 can be installed in the wellbore 11 during well completion operations or well testing operations. The packer assembly can be located in a cased wellbore section or an open-hole wellbore section. There can also be more than one packer assembly located within the wellbore in a variety of location, for example in cased sections, open-hole sections, or combinations thereof.

The packer assembly 16 can be a gravel pack packer that is used to support and retain gravel placed during gravel pack operations. In other embodiments, the packer assembly 16 can be a hydraulic packer (not shown) that can be set with the application of tubing pressure or a hydrostatic set packer (not shown) that can be set with the application of wellbore hydrostatic pressures. The packer assembly 16 can also be set with one or more sealing elements 22 that swell in the presence of a swelling fluid. Any combination of setting methods can be employed to set the packer.

As shown in FIG. 2A, the packer assembly 16 can include a body or inner mandrel 21. The inner mandrel 21 can include an upper inner mandrel 21a and a lower inner mandrel 21b. The inner mandrel 21 can allow fluids to flow from or into the subterranean formation via a conduit defined by a tubing string. While the inner mandrel 21 has been depicted in separate form, in other embodiments, the inner mandrel 21 can be an integral part of a tubing string.

The downhole tool, for example a packer assembly 16, includes at least one component wherein a portion of the component moves in a direction radially away from the inner mandrel 21 when the downhole tool is set. The at least one component can be a sealing element, a collet, a split wedge, or a slip.

FIGS. 2A and 2B show a packer assembly 16 including a sealing element 22. The sealing element 22 can be located on the outside of the upper inner mandrel 21a. There can also be more than one sealing element 22. By way of example, a packer assembly 16 can generally include from 1 to 10 sealing elements 22. Any discussion of a particular component of an embodiment (e.g., a slip, a sealing element, etc.) is meant to include the singular form of the component and also the plural form of the component, without the need to continually refer to the component in both the singular and plural form throughout. For example, if a discussion involves “the sealing element 22,” it is to be understood that the discussion pertains to one sealing element (singular) and two or more sealing elements (plural).

FIG. 3 shows a packer assembly 16 including a slip 23. The packer assembly 16 can include a slip system located on the outside of the inner mandrel 21. The slip system includes the slip 23. The slip 23 can be made from a single cylinder of material commonly referred to as a barrel slip, a set of slips retained in a groove on the slip prop commonly referred to as a dove-tail slip, or a slip retained by a housing with windows commonly referred to as a caged slip. The slip 23 can be located around a portion of the outside of the inner mandrel 21 and radially biased towards the outside of the inner mandrel 21. The slip 23 can have teeth on its face. As used herein, the term “teeth” includes one or more elements that are capable of grippingly engaging an inner diameter (I.D.) of a tubing string, or casing, or wall of the wellbore to retain the packer assembly 16 in a set position. The teeth can be sharp ridges machined onto the face of the slip 23 or sharp elements, for example, buttons or other geometric shapes that are attached to the face of the slip 23. The slip system can further include a slip prop 31. The slip prop can include an upper slip prop 31b and a lower slip prop 31a. An upper and a lower end of each slip 23 can be formed having a conical or ramped surface. These surfaces are complementary to and can slidingly engage a parallel, ramped surface of the upper slip prop 31b and ramped surface of the lower slip prop 31a, respectively. In one position, the slip 23 can be positioned substantially adjacent to the inner mandrel 21 and axially separated from the slip prop 31 so that the outer diameter (O.D.) of the slip 23 is less than or equal to the O.D. of the slip prop 31.

After the packer assembly 16 is run in the wellbore to a desired location, it can be set. Setting the packer assembly 16 can involve applying compression to the slip system to move the slip 23 axially towards and along the face of the slip prop 31 to move the slip 23 radially away from the inner mandrel 21 and into engagement with the casing 14 or wellbore wall 13 and to allow the slip 23 to maintain engagement with the casing or wellbore wall, for example as shown in FIG. 2B. The slip prop 31 can support the slip 23 in an expanded position outward from the mandrel 21 such that the slip 23 engages the I.D. of the casing or the wall of the wellbore when the packer assembly 16 is set. The slip prop 31 can prevent the slip 23 from retracting and releasing from the casing or well bore once the packer assembly 16 is set. As used herein, the term “slip prop” can include a wedge, cone, or any device that can support the slip 23 when it is set. When the slip 23 is engaged with the casing or wellbore wall, the packer assembly 16 has substantially limited or no vertical movement within the wellbore. The packer assembly can further include more than one slip system to facilitate setting of the packer assembly.

Setting the packer assembly 16 can further involve causing or allowing the sealing elements 22 to expand radially away from the inner mandrel 21 to form a pressure tight annular seal. The sealing element 22 can radially expand outwardly away from the inner mandrel 21 to provide a substantially pressure tight seal in an annulus, for example between the outside of a tubing string and the inside of the casing, when the packer assembly 16 is set. Movement of the sealing element 22 can be mechanically or hydrostatically actuated, or from swelling in the presence of a swelling fluid. An axial setting force can be applied to a setting sleeve to axially compress the sealing element 22 to cause it to expand to the I.D. of the casing or wall of the wellbore 11. The axial force is transferred through the element 22 and into the upper slip prop 31b to cause the slip system to engage the I.D. of the casing or wellbore wall. The sealing element 22 is subjected to mechanical pressure that causes it to be squeezed into high contract stress to the casing or the wall of the wellbore 11. The sealing element 22 can be retained on at least one end by a lock ring 52 that grips the inner mandrel 21. A second end of the sealing element 22 can push against the upper slip prop 31b and into the slip 23. As the rubber pressure pushes up against the lock ring 52 that is gripping the inner mandrel 21, the inner mandrel 21 can transfer the stress to a load device. The load device can transfer the force to the lower slip prop 31a and into the slip 23. The load device 33 keeps the packer assembly 16 in the set position by retaining the setting force from the lock ring and along the inner mandrel 21. One or more back up shoes 51 can also be used to retain the sealing element 22.

As discussed above, a sealing element 22 can be mechanically or hydraulically actuated, or swell in the presence of a swelling fluid. The sealing element 22 according to any of the embodiments can be made from an elastomeric material. The length of the sealing element 22 can vary and can be selected such that the desired sealing area around the body of the downhole tool is achieved. The inner diameter of the sealing element 22 can be selected such that the sealing element 22 fits around the outer diameter of the downhole tool body. The typical inner diameter of a sealing element 22 can range from 1 inch to 16 inches as required by the outer diameter of the downhole tool in the oil or gas operation. The thickness of a sealing element 22 is the difference between the largest outer diameter and the inner diameter of the sealing element 22, measured at the axial location of the largest outer diameter. Typically, a downhole tool having more than one sealing element 22 will be actuated mechanically or hydrostatically.

A swellable sealing element 22 swells in the presence of a swelling fluid. The swellable material can swell in the presence of a hydrocarbon liquid (hydrocarbon-swellable materials) or swell in the presence of an aqueous liquid (water-swellable materials). According to an embodiment, the swellable material is a hydrocarbon liquid swellable material, and the material is selected from the group consisting of natural rubbers, nitrile rubbers, hydrogenated nitrile rubber, acrylate butadiene rubbers, polyacrylate rubbers, isoprene rubbers, chloroprene rubbers, butyl rubbers (IIR), brominated butyl rubbers (BIIR), chlorinated butyl rubbers (CIIR), chlorinated polyethylenes (CM/CPE), neoprene rubbers (CR), styrene butadiene copolymer rubbers (SBR), sulphonated polyethylenes (CSM), ethylene acrylate rubbers (EAM/AEM), epichlorohydrin ethylene oxide copolymers (CO, ECO), ethylene-propylene rubbers (EPM and EDPM), ethylene-propylene-diene terpolymer rubbers (EPT), ethylene vinyl acetate copolymer, acrylonitrile butadiene rubbers, hydrogenated acrylonitrile butadiene rubbers (HNBR), fluorosilicone rubbers (FVMQ), silicone rubbers (VMQ), poly 2,2,1-bicyclo heptenes (polynorbornene), alkylstyrenes, and combinations thereof. One example of a suitable swellable elastomer comprises a block copolymer of a styrene butadiene rubber.

According to another embodiment, the swellable material is a water-swellable material. Some specific examples of suitable water-swellable materials, include, but are not limited to starch-polyacrylate acid graft copolymer and salts thereof, polyethylene oxide polymer, carboxymethyl cellulose type polymers, polyacrylamide, poly(acrylic acid) and salts thereof, poly(acrylic acid-co-acrylamide) and salts thereof, graft-poly(ethylene oxide) of poly(acrylic acid) and salts thereof, poly(2-hydroxyethyl methacrylate), poly(2-hydroxypropyl methacrylate), and combinations thereof. In certain embodiments, the water-swellable material may be cross-linked and/or lightly cross-linked. Other water-swellable materials that behave in a similar fashion with respect to aqueous fluids may also be suitable. The previous lists disclosing suitable swellable materials is by no means an exhaustive list, does not include every suitable swellable material example that could be given, and is not meant to limit the scope of the invention. The swellable material 102 can be selected such that it is insusceptible to corrosive or erosive fluids. For example, the swellable material does not degrade and maintains integrity.

The swelling fluid can be a hydrocarbon liquid or an aqueous liquid. As used herein, a “hydrocarbon liquid” has a liquid hydrocarbon as the base fluid. As used herein, an “aqueous liquid” has water as the base fluid. The swelling fluid can also contain dissolved compounds or undissolved compounds. For a heterogeneous fluid, the swelling fluid can be an emulsion, a slurry, or a foam.

The downhole tool also includes a protective covering 40. The protective covering 40 at least partially surrounds an outer diameter (O.D.) of the component (e.g., a slip or a sealing element) when the downhole tool is run-in. FIGS. 2A and 4B show the protective covering 40 partially surrounding the O.D. of a sealing element 22. For example, FIG. 2A shows one sealing element 22, while FIG. 4B shows three sealing elements 22. As can also be seen in FIG. 4B, there can be more than one protective covering 40, wherein each protective covering 40 at least partially surrounds each sealing element 22 or slip 23. FIG. 3 shows the protective covering 40 at least partially surrounding a slip 23.

According to any of the embodiments, the protective covering 40 completely surrounds the entire O.D. of the component of the downhole tool. These embodiments can be seen in FIG. 4A wherein the protective covering 40 completely surrounds all three of the sealing elements 22. It is to be understood that one protective covering 40 can completely surround a multitude of various components that expand radially away from the inner mandrel 21 when setting the downhole tool. For example, the protective covering 40 can surround one or more slips 23 and one or more sealing elements 22. Partial covering of the downhole tool component may be useful when the downhole tool component is not a swellable material. Components made of a swellable material may need complete protection from exposure to a fluid that could induce swelling and fluid forces that may have a greater detrimental impact on the integrity of the component compared to non-swellable components that may not require as much protection during run-in. Accordingly, and as shown for example in FIG. 4A, three sealing elements 22 made from a swellable material can be completely surrounded by the protective covering 40—analogous to a sleeve; whereas, as shown for example in FIG. 4B, three sealing elements 22 made from a non-swellable material can each have one protective covering 40 that partially surrounds each element—analogous to a strap or band. The protective covering 40 can also surround additional components of the downhole tool that do not extend radially away from the inner mandrel 21 when setting, such as but not limited to, a back-up shoe 51. Covering of the additional components with the protective covering can be useful to ensure complete protection of the components.

The protective covering 40 includes a dissolvable material. The dissolvable material according to any of the embodiments can be selected from a metal, a metal alloy, a hard plastic, and a thermoplastic. As used herein, the term “metal alloy” means a mixture of two or more elements, wherein at least one of the elements is a metal. The other element(s) can be a non-metal or a different metal. An example of a metal and non-metal alloy is steel, comprising the metal element iron and the non-metal element carbon. An example of a metal and metal alloy is bronze, comprising the metallic elements copper and tin. The dissolvable material can undergo or more chemical reactions to dissolve.

According to certain embodiments, the dissolvable material comprises a metal or metal alloy that chemically reacts with water to form a metal oxide. The metal oxide can then chemically react with water to hydrolyze and form a metal hydroxide. Alternatively, the metal oxide can chemically react with an acidic solution (i.e., having a pH less than 7) to form a salt of the metal oxide and water. A metal hydroxide can be insoluble in water. An insoluble metal hydroxide can chemically react with an acidic solution to form an ionic compound of the metal cation from the metal hydroxide and the anion from the acid plus water, as shown below in equation 1.

Acid+Metal Hydroxide→Ionic Compound+H₂O  (Eq. 1)

The protective covering 40 can be made from a metal, metal alloy, or metal oxide that is a solid. If the protective covering 40 is made from a metal oxide and the metal oxide is soluble in water, then according to certain embodiments, the downhole tool is run into the wellbore in a hydrocarbon liquid as the base fluid. The metal or the metal of the metal alloy can be selected from alkaline earth metals found in Group 2 of the periodic table, a transition metal found in Groups 3-12, or a post-transition metal found in Groups 13-15. Preferably, the alkaline earth metal is selected from magnesium or calcium. The transition metal can be selected from iron, cobalt, nickel, zinc, copper, or tungsten. The post-transition metal is preferably aluminum.

If a metal oxide is used, the metal can be alloyed with a different metal including, but not limited to, aluminum, zinc, manganese, zirconium, yttrium, neodymium, gadolinium, silver, calcium, tin, or rhenium. A third alloyed material can be included. The third material can be selected to increase corrosion with examples including, but not limited to, nickel, iron, copper, cobalt, iridium, gold, and palladium. Examples of non-metal materials that can be alloyed with the metal include, but are not limited to, carbon, aliphatic polyesters, polyglycolic acid (PGA), polylactic acid (PLA), polyvinyl alcohol (PVA), a urethane, a degradable rubber, a degradable polymer, or a salt.

In examples where the protective covering 40 comprises a metal alloy, the metal alloy can be produced from a solid solution process or a powder metallurgical process. The metal alloy can be formed either from the metal alloy production process or through subsequent processing of the metal alloy. As used herein, the term “solid solution” refers to an alloy that is formed from a single melt where all of the components in the alloy (e.g., a magnesium alloy) are melted together in a casting. The casting can be subsequently extruded, wrought, hipped, or worked to form the desired shape for the protective covering. Preferably, the alloying components are uniformly distributed throughout the metal alloy, although intra-granular inclusions may occur. It is to be understood that some minor variations in the distribution of the alloying particles can occur, but it is preferred that the distribution is such that a homogenous solid solution of the metal alloy is produced. A solid solution is a solid-state solution of one or more solutes in a solvent. Such a mixture is considered a solution rather than a compound when the crystal structure of the solvent remains unchanged by addition of the solutes, and when the mixture remains in a single homogeneous phase.

A powder metallurgy process generally includes obtaining or producing a fusible alloy matrix in a powdered form. The powdered fusible alloy matrix is then placed into a mold or blended with at least one other type of particle and then placed into a mold. Pressure is applied to the mold to compact the powder particles together, fusing them to form a solid material that can be used as the protective covering.

The metal or metal alloy can also be selected such that the protective covering 40 dissolves via galvanic corrosion in the presence of an electrolyte. Galvanic corrosion occurs when two different metals or metal alloys are in electrical connectivity with each other and both are in contact with an electrolyte. Electrical connectivity can mean that the two different metals or metal alloys are either touching or in close enough proximity to each other such that when the two different metals are in contact with an electrolyte, the electrolyte becomes electrically conductive and ion migration occurs between one of the metals and the other metal, and is not meant to require an actual physical connection between the two different metals, for example, via a metal wire. According to any of the embodiments, a source of electrical voltage can be supplied to the metals or metal alloys as opposed to relying solely on the electrolyte to supply the electrical connectivity. By way of example, batteries can be used to provide an electrical connectivity for the metals or metal alloys.

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

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

The following is a partial galvanic series chart using a deoxygenated sodium chloride water solution as the electrolyte. The metals are listed in descending order from the most noble (cathodic) to the least noble (anodic). The following list is not exhaustive, and one of ordinary skill in the art is able to find where a specific metal or metal alloy is listed on a galvanic series in a given electrolyte.

• • PLATINUM
  • GOLD
  • ZIRCONIUM
  • GRAPHITE
  • SILVER
  • CHROME IRON
  • SILVER SOLDER
  • COPPER—NICKEL ALLOY 80-20
  • COPPER—NICKEL ALLOY 90-10
  • MANGANESE BRONZE (CA 675), TIN BRONZE (CA903, 905)
  • COPPER (CA102)
  • BRASSES
  • NICKEL (ACTIVE)
  • TIN
  • LEAD
  • ALUMINUM BRONZE
  • STAINLESS STEEL
  • CHROME IRON
  • MILD STEEL (1018), WROUGHT IRON
  • ALUMINUM 2117, 2017, 2024
  • CADMIUM
  • ALUMINUM 5052, 3004, 3003, 1100, 6053
  • ZINC
  • MAGNESIUM
  • BERYLLIUM

The following is a partial anodic index listing the voltage of a listed metal against a standard reference electrode (gold) using a deoxygenated sodium chloride water solution as the electrolyte. The metals are listed in descending order from the greatest voltage (most cathodic) to the least voltage (most anodic). The following list is not exhaustive, and one of ordinary skill in the art is able to find the anodic index of a specific metal or metal alloy in a given electrolyte.

Anodic index
Metal                            Index (V)
Gold, solid and plated, Gold-platinum alloy −0.00
Rhodium plated on silver-plated copper −0.05
Silver, solid or plated; monel metal. High nickel- −0.15
copper alloys
Nickel, solid or plated, titanium an s alloys, Monel −0.30
Copper, solid or plated; low brasses or bronzes; −0.35
silver solder; German silvery high copper-nickel
alloys; nickel-chromium alloys
Brass and bronzes                −0.40
High brasses and bronzes         −0.45
18% chromium type corrosion-resistant steels −0.50
Chromium plated; tin plated; 12% chromium type −0.60
corrosion-resistant steels
Tin-plate; tin-lead solder       −0.65
Lead, solid or plated; high lead alloys −0.70
2000 series wrought aluminum     −0.75
Iron, wrought, gray or malleable, plain carbon and −0.85
low alloy steels
Aluminum, wrought alloys other than 2000 series −0.90
aluminum, cast alloys of the silicon type
Aluminum, cast alloys other than silicon type, −0.95
cadmium, plated and chromate
Hot-dip-zinc plate; galvanized steel −1.20
Zinc, wrought; zinc-base die-casting alloys; zinc −1.25
plated
Magnesium & magnesium-base alloys, cast or wrought −1.75
Beryllium                        −1.85

Another factor that can affect the rate of galvanic corrosion is the temperature and concentration of the electrolyte. The higher the temperature and concentration of the electrolyte, the faster the rate of corrosion. Yet another factor that can affect the rate of galvanic corrosion is the total amount of surface area of the least noble (anodic metal). The greater the surface area of the anode that can come in contact with the electrolyte, the faster the rate of corrosion. The cross-sectional size of the anodic metal pieces can be decreased in order to increase the total amount of surface area per total volume of the material. Yet another factor that can affect the rate of galvanic corrosion is the ambient pressure. Depending on the electrolyte chemistry and the two metals, the corrosion rate can be slower at higher pressures than at lower pressures if gaseous components are generated.

As used herein, an electrolyte is any substance containing free ions (i.e., a positive- or negative-electrically charged atom or group of atoms) that make the substance electrically conductive. The electrolyte can be selected from the group consisting of, solutions of an acid, a base, a salt, and combinations thereof. A salt can be dissolved in water, for example, to create a salt solution. Common free ions in an electrolyte include sodium (Na⁺), potassium (K⁺), calcium (Ca²⁺), magnesium (Mg²⁺), chloride (Cl⁻), hydrogen phosphate (HPO₄²⁻), and hydrogen carbonate (HCO₃⁻). The concentration (i.e., the total number of free ions available in the electrolyte) of the electrolyte can be adjusted to control the rate of dissolution of the first metal.

The protective covering 40 can also be made from a hardened thermoplastic material. As used herein, the term “thermoplastic” means a material that becomes liquid when heated, freezes to a solid, glassy substance when cooled sufficiently, and is capable of being re-melted and remolded. A thermoplastic material includes both crystalline regions and amorphous regions. The crystalline regions contribute to the material's strength and rigidity properties, while the amorphous regions contribute elastic properties. A thermoplastic material is elastic and flexible above the glass transition temperature that is specific for each type of material. The glass transition temperature is normally the midpoint in a temperature range for that material, which is in contrast to the melting point of a pure crystalline substance, such as water. Examples of thermoplastics include, without limitation, polyethylene, polypropylene, polyvinyl chloride, polystyrene, polyamides, polyesters, and polyurethanes. Preferably, the thermoplastic is selected such that it dissolves in a wellbore fluid. The wellbore fluid can be heated in order to cause the thermoplastic to dissolve. In other embodiments, the downhole temperature at the location of the downhole tool may be sufficiently high to cause the thermoplastic to dissolve without the need for heating the wellbore fluid at the wellhead.

The protective covering 40 can have a variety of dimensions. According to any of the embodiments, the length of the protective covering 40 is selected such that the protective covering 40 partially surrounds the component. The length can be, for example, within a range of 10% to 80% of the length of the component. According to other embodiments, the length of the protective covering 40 is selected such that the protective covering 40 completely surrounds the component. The length can be, for example, within a range of 100% to 150% of the length of the component. As discussed above, there can also be more than one protective covering 40. The length of the more than one protective covering 40 can be in a range within 10% to 150% of the length of each component. The protective covering 40 can have a length in the range of 0.25 inch to 50 feet.

The protective covering 40 also has a thickness defined by the difference between the I.D. and the O.D. of the covering. The thickness can vary and can be selected in part based on the run-in fluid and desired dissolution time—as discussed in more detail below. The O.D. of the downhole tool, including the components, may need to be smaller in order to accommodate the thickness of the protective covering 40. A reduced O.D. of the downhole tool can provide room for the downhole tool to be run into the wellbore based on the thickness of the protective covering 40. Alternatively, the thickness of the protective covering 40 can be adjusted to provide room for the downhole tool to be run into the wellbore so long as no loss of structural integrity of the protective covering 40 occurs due to a thinner covering.

The methods can include positioning the downhole tool at a desired location within the wellbore (also known as run-in). The downhole tool can be run-in in a first fluid. The first fluid can be an oil-based or water-based fluid. The first fluid can include additives, such as salt, an acid, a weighting agent, etc. The first fluid can be selected such that the first fluid dissolves less than 5% of the protective covering 40. By way of example, if the protective covering 40 dissolves when in contact with water, then the first fluid can consist essentially of a hydrocarbon liquid. By way of another example, if the protective covering 40 dissolves via galvanic corrosion, then the first fluid could not include an electrolyte. By way of another example, if the protective covering 40 dissolves via heating, then the first fluid can be at a temperature below the melting temperature of the thermoplastic. For example, for dissolution in water, the first fluid can be an emulsion with a hydrocarbon liquid as the continuous phase and water as a dispersed phase.

According to these embodiments, the methods can further include introducing a second fluid into the wellbore after the downhole tool is at the desired location. The second fluid can be selected such that the protective covering 40 dissolves. By way of example, the second fluid can include an electrolyte, be heated, or be a water-based fluid with salts, pH adjustors, etc. as required to cause dissolution of the protective covering 40. The second fluid can also be selected to cause swelling of a swellable tool component, for example, a swellable sealing element. If the downhole tool includes a swellable component and the second fluid does not cause swelling of the swellable component, then the methods can further include introducing a third fluid into the wellbore after dissolution of the protective covering 40. The third fluid can be selected to cause swelling of the swellable component.

According to other embodiments, the first fluid can be selected such that the protective covering 40 begins dissolving during introduction into the wellbore. Preferably, less than 15% of the protective covering 40 dissolves during run-in. The percentage of dissolution that occurs during run-in can vary and can be selected based on the material chosen to make up the protective covering, the total run time, the mode of dissolution, the thickness of the protective covering, and other factors. The structural integrity of the protective covering 40 is preferably maintained until the downhole tool reaches the desired location in the wellbore. Maintaining structural integrity allows the protective covering to function as intended in order to provide protection to the tool components from debris damage, damage from fluid flow and pressures, and premature swelling of any swellable components.

According to these embodiments, the thickness of the protective covering 40 may need to be increased in order to maintain structural integrity during run-in. The total dissolution time (i.e., the time it takes to dissolve enough of the protective covering to expose the components and set the downhole tool, which may be greater than 85%) is preferably greater than the run-in time. The total dissolution time can be in the range of 20% to 200% greater than the run-in time. For example, if it takes 6 hours to position the downhole tool at the desired location within the wellbore, then the total dissolution time can be 24 hours. This may be useful to ensure structural integrity of the protective covering 40.

According to these embodiments, the ingredients and concentration of dissolving ingredients can be selected such that the protective covering 40 retains structural integrity during run-in. By way of example, if the protective covering 40 dissolves by galvanic corrosion, the concentration of the electrolyte can be low enough such that the structural integrity of the protective covering is maintained during run-in. In these embodiments, the concentration of the ingredients that causes dissolution of the protective covering 40 can be increased after the downhole tool has reached the desired location within the wellbore in order to finish dissolving the protective covering 40. Alternatively, a second fluid that includes different ingredients and/or a different concentration of the dissolving ingredients can be introduced into the wellbore after the first fluid and when the downhole tool has reached the desired location within the wellbore. In other examples, for thermoplastic protective coverings, the temperature of first fluid can be selected to partially dissolve the protective covering 40 during run-in; while a second fluid can have a higher temperature can be used to finish dissolving the protective covering. The bottomhole temperature at the location of the downhole tool may also be sufficient to increase the temperature of the first fluid to finish dissolving the protective covering without the need for a second fluid.

The downhole tool is set after the tool has reached the desired location within the wellbore and after the total dissolution time has elapsed. With the protective covering 40 no longer surrounding the components of the downhole tool, the tool can be set within the wellbore. One of ordinary skill in the art will be able to set the tool based on the specific tool and the specific setting mechanism for the tool.

An embodiment of the present disclosure is a downhole tool comprising: an inner mandrel; at least one component, wherein a portion of the at least one component moves in a direction radially away from the inner mandrel when the downhole tool is set; and a protective covering, wherein the protective covering comprises a dissolvable material, and wherein the protective covering partially surrounds an outer diameter of the at least one component when the downhole tool is run-in. Optionally, the downhole tool further comprises wherein the downhole tool is selected from a packer assembly, a bridge plug, liner hangers, or a frac pack plug. Optionally, the downhole tool further comprises wherein the at least one component is selected from a sealing element, a collet, a split wedge, or a slip. Optionally, the downhole tool further comprises wherein the protective covering completely surrounds the entire outer diameter of the at least one component. Optionally, the downhole tool further comprises wherein one protective covering completely surrounds a two or more components. Optionally, the downhole tool further comprises wherein the dissolvable material comprises a metal, a metal alloy, or a metal oxide. Optionally, the downhole tool further comprises wherein the metal or metal alloy chemically reacts with water to form a metal oxide, and wherein the metal oxide chemically reacts with water to hydrolyze and form a metal hydroxide. Optionally, the downhole tool further comprises wherein the metal hydroxide is insoluble in a basic solution, and wherein the metal hydroxide chemically reacts with an acidic solution to form an ionic compound of the metal cation from the metal hydroxide and the anion from the acid plus water. Optionally, the downhole tool further comprises wherein the metal or metal alloy chemically reacts with water to form a metal oxide, and wherein the metal oxide chemically reacts with an acidic solution to form a salt of the metal oxide and water. Optionally, the downhole tool further comprises wherein the metal, the metal of the metal alloy, or the metal of the metal oxide are selected from an alkaline earth metal, a transition metal, or a post-transition metal. Optionally, the downhole tool further comprises wherein the alkaline earth metal is selected from magnesium or calcium, the transition metal is selected from iron, cobalt, nickel, zinc, copper, or tungsten, and the post-transition metal is aluminum. Optionally, the downhole tool further comprises wherein the protective covering dissolves via galvanic corrosion in the presence of an electrolyte, wherein the protective covering comprises a first metal and a second metal, and wherein the first metal is an anode and the second metal is a cathode. Optionally, the downhole tool further comprises wherein the protective covering comprises a thermoplastic, and wherein the thermoplastic dissolves at a temperature greater than or equal to the melting point of the thermoplastic. Optionally, the downhole tool further comprises wherein the protective covering has a length in a range within 10% to 150% of a length of the at least one component.

Another embodiment of the present disclosure is a method of introducing a downhole tool into a wellbore comprising: (A) positioning the downhole tool at a desired location within the wellbore, wherein the downhole tool comprises: an inner mandrel; at least one component; and a protective covering, wherein the protective covering comprises a dissolvable material, and wherein the protective covering partially surrounds an outer diameter of the at least one component while the downhole tool is being positioned at the desired location within the wellbore; (B) causing or allowing the protective covering to dissolve; and (C) setting the downhole tool at the desired location within the wellbore after the protective covering has dissolved, wherein a portion of the at least one component moves in a direction radially away from the inner mandrel during setting. Optionally, the method further comprises wherein: the dissolvable material comprises a metal, a metal alloy, or a metal oxide, and wherein the protective sleeve dissolves via a chemical reaction of the metal, the metal alloy, or the metal oxide with water or an acidic solution; or the protective covering dissolves via galvanic corrosion in the presence of an electrolyte, wherein the protective covering comprises a first metal and a second metal, and wherein the first metal is an anode and the second metal is a cathode; or the dissolvable material comprises a thermoplastic, and wherein the thermoplastic dissolves at a temperature greater than or equal to the melting point of the thermoplastic. Optionally, the method further comprises wherein the downhole tool is run into the wellbore in a first fluid, and wherein the first fluid is selected such that the first fluid dissolves less than 15% of the protective covering and the protective covering maintains structural integrity. Optionally, the method further comprises introducing a second fluid into the wellbore after the downhole tool has reached the desired location within the wellbore, and wherein the second fluid is selected such that the second fluid dissolves more than 15% of the protective covering. Optionally, the method further comprises wherein the first fluid dissolves more than 15% of the protective covering after the downhole tool has reached the desired location within the wellbore. Optionally, the method further comprises wherein the protective covering dissolves in a time in the range of 20% to 200% greater than the time to position the downhole tool at the desired location within the wellbore.

Therefore, the compositions, methods, and systems of the present disclosure are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is, therefore, evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure.

As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. While compositions, systems, and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions, systems, and methods also can “consist essentially of” or “consist of” the various components and steps. It should also be understood that, as used herein, “first,” “second,” and “third,” are assigned arbitrarily and are merely intended to differentiate between two or more fluids, components, etc., as the case may be, and does not indicate any sequence. Furthermore, it is to be understood that the mere use of the word “first” does not require that there be any “second,” and the mere use of the word “second” does not require that there be any “third,” etc.

Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is 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. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

Claims

1. A downhole tool comprising:

an inner mandrel;

at least one component, wherein a portion of the at least one component moves in a direction radially away from the inner mandrel when the downhole tool is set; and

a protective covering, wherein the protective covering comprises a dissolvable material, and wherein the protective covering partially surrounds an outer diameter of the at least one component when the downhole tool is run-in.

2. The downhole tool according to claim 1, wherein the downhole tool is selected from a packer assembly, a bridge plug, liner hangers, or a frac pack plug.

3. The downhole tool according to claim 1, wherein the at least one component is selected from a sealing element, a collet, a split wedge, or a slip.

4. The downhole tool according to claim 1, wherein the protective covering completely surrounds the entire outer diameter of the at least one component.

5. The downhole tool according to claim 1, wherein one protective covering completely surrounds a two or more components.

6. The downhole tool according to claim 1, wherein the dissolvable material comprises a metal, a metal alloy, or a metal oxide.

7. The downhole tool according to claim 6, wherein the metal or metal alloy chemically reacts with water to form a metal oxide, and wherein the metal oxide chemically reacts with water to hydrolyze and form a metal hydroxide.

8. The downhole tool according to claim 7, wherein the metal hydroxide is insoluble in a basic solution, and wherein the metal hydroxide chemically reacts with an acidic solution to form an ionic compound of the metal cation from the metal hydroxide and the anion from the acid plus water.

9. The downhole tool according to claim 6, wherein the metal or metal alloy chemically reacts with water to form a metal oxide, and wherein the metal oxide chemically reacts with an acidic solution to form a salt of the metal oxide and water.

10. The downhole tool according to claim 6, wherein the metal, the metal of the metal alloy, or the metal of the metal oxide are selected from an alkaline earth metal, a transition metal, or a post-transition metal.

11. The downhole tool according to claim 10, wherein the alkaline earth metal is selected from magnesium or calcium, the transition metal is selected from iron, cobalt, nickel, zinc, copper, or tungsten, and the post-transition metal is aluminum.

12. The downhole tool according to claim 1, wherein the protective covering dissolves via galvanic corrosion in the presence of an electrolyte, wherein the protective covering comprises a first metal and a second metal, and wherein the first metal is an anode and the second metal is a cathode.

13. The downhole tool according to claim 1, wherein the protective covering comprises a thermoplastic, and wherein the thermoplastic dissolves at a temperature greater than or equal to the melting point of the thermoplastic.

14. The downhole tool according to claim 1, wherein the protective covering has a length in a range within 10% to 150% of a length of the at least one component.

15. A method of introducing a downhole tool into a wellbore comprising:

(A) positioning the downhole tool at a desired location within the wellbore, wherein the downhole tool comprises: an inner mandrel; at least one component; and a protective covering, wherein the protective covering comprises a dissolvable material, and wherein the protective covering partially surrounds an outer diameter of the at least one component while the downhole tool is being positioned at the desired location within the wellbore;

(B) causing or allowing the protective covering to dissolve; and

(C) setting the downhole tool at the desired location within the wellbore after the protective covering has dissolved, wherein a portion of the at least one component moves in a direction radially away from the inner mandrel during setting.

16. The method according to claim 15, wherein:

the dissolvable material comprises a metal, a metal alloy, or a metal oxide, and wherein the protective sleeve dissolves via a chemical reaction of the metal, the metal alloy, or the metal oxide with water or an acidic solution; or

the protective covering dissolves via galvanic corrosion in the presence of an electrolyte, wherein the protective covering comprises a first metal and a second metal, and wherein the first metal is an anode and the second metal is a cathode; or

the dissolvable material comprises a thermoplastic, and wherein the thermoplastic dissolves at a temperature greater than or equal to the melting point of the thermoplastic.

17. The method according to claim 16, wherein the downhole tool is run into the wellbore in a first fluid, and wherein the first fluid is selected such that the first fluid dissolves less than 15% of the protective covering and the protective covering maintains structural integrity.

18. The method according to claim 17, further comprising introducing a second fluid into the wellbore after the downhole tool has reached the desired location within the wellbore, and wherein the second fluid is selected such that the second fluid dissolves more than 15% of the protective covering.

19. The method according to claim 17, wherein the first fluid dissolves more than 15% of the protective covering after the downhole tool has reached the desired location within the wellbore.

20. The method according to claim 15, wherein the protective covering dissolves in a time in the range of 20% to 200% greater than the time to position the downhole tool at the desired location within the wellbore.