Downhole Tool

BACKGROUND
Field

Embodiments of the present disclosure generally relate to a downhole tool including a coating, wherein the coating is formed using a Plasma Electrolytic Oxidation (“PEO”) process.

Description of the Related Art

Slips are used for various downhole tools, such as bridge plugs and packers. The slips may include buttons (e.g., gripping inserts) configured to grip the inner wall of a casing or tubular. Buttons may be made from cast or forged metal, which may then be machined and heat-treated to the proper engineering specifications according to conventional practices.

Some conventional slip assemblies are coated with a sprayed-on hard facing, which may have poor adhesion to the slips and may provide ineffective corrosion resistance or provides a poor barrier between the slip and wellbore fluids. Conventional slip assemblies may also have non-dissolvable buttons that are used to grip (e.g. bite) into a downhole tubular. If these buttons are attached to a dissolvable slip, the slip may dissolve in the presence of a chemical solution while leaving behind the buttons. The buttons might release from engagement with a downhole tubular after the dissolution of the slips. The buttons may impede subsequent downhole operations. As a result, a cleaning operation may be necessitated to flush the buttons back to the surface.

There is a need in the art for a slip with a coating that is well adhered to the slip, resistant to corrosion, and provides a barrier between portions of the slip and the wellbore fluids. There is also a need in the art for a sufficiently hard coating that can be applied on a slip to cover dissolvable gripping elements such that the coating contacts the downhole tubular to anchor a downhole tool.

Conventional seats of downhole tools may be damaged by the flow of wellbore fluids through the downhole tool such that an object cannot properly engage the seat. For example, a fracturing fluid including sand and/or proppants may damage the seat, preventing an object from creating a sealing engagement with the seat. For example, the seat may be damaged by corrosion caused by the wellbore fluids. There is a need in the art for a downhole tool with a seat including a damage resistant coating such that an object can sealing engage with the seat.

SUMMARY

In one embodiment, a downhole tool includes a cone member and a slip assembly. The slip assembly includes a plurality of slip segments. The slip segments are configured to move along the cone member into engagement with a downhole surface. Each slip segment includes a slip body, a plurality of degradable profile elements coupled to the slip body, and a first coating disposed on the plurality of profile elements, wherein the first coating is formed from a plasma electrolytic oxidation treatment. The first coating and profile elements form a plurality of gripping elements configured to grip the downhole tubular.

In one embodiment, a downhole tool includes a slip assembly having a plurality of slips configured to engage a downhole surface. The slip assembly includes a plurality of slip segments. Each slip segment includes a slip body, a plurality of profile elements coupled to the slip body, and a first coating disposed on the plurality of profile elements, wherein the first coating is formed from a plasma electrolytic oxidation treatment. The first coating and the plurality of profile elements form a plurality of gripping elements configured to grip the downhole surface.

In one embodiment, a method of using a downhole tool includes deploying a downhole tool into a downhole tubular. The downhole tool includes a slip assembly. The slip assembly includes a plurality of slip segments having a coating formed from a plasma electrolytic oxidation treatment, wherein the coating is configured to grip the downhole tubular. The method further includes activating the downhole tool to engage the plurality of slip segments with the downhole tubular, wherein the coating grips the downhole tubular such that the slip assembly anchors the downhole tool to the downhole tubular.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only exemplary embodiments and are therefore not to be considered limiting of its scope, may admit to other equally effective embodiments.

FIG. 1 illustrates an exemplary embodiment of a downhole tool.

FIG. 2 illustrates a cross-sectional view of the downhole tool show in FIG. 1.

FIG. 3A illustrates an exemplary slip segment. FIG. 3B illustrates a cross-sectional view of the slip segment shown in FIG. 3A. FIG. 3C illustrates the circled region in FIG. 3B.

FIG. 4 illustrates a cross-sectional view of an alternative embodiment of a slip segment.

FIG. 5 illustrates a flow diagram of a method for a PEO treatment to develop a PEO coating.

FIG. 6 illustrates a cross-sectional view of the downhole tool of FIG. 1 with slips engaged with a downhole tubular.

FIG. 7 illustrates a cross-sectional view of an exemplary downhole tool including a seat having a PEO coating.

FIG. 8 illustrates a cross-sectional view of an exemplary downhole tool including multiple seats having a PEO coating.

To facilitate understanding, identical reference numerals have been used, where possible, to designate identical elements that are common to the figures. It is contemplated that elements and features of one embodiment may be beneficially incorporated in other embodiments without further recitation.

DETAILED DESCRIPTION

FIG. 1 illustrates an exemplary downhole tool 100 according to an embodiment of this disclosure. The downhole tool 100 may be a bridge plug as shown, but it could also be a packer, a liner hanger, an anchoring device, or other downhole tool that uses a slip assembly to engage a downhole surface, such as a casing.

The downhole tool 100 includes a mandrel 110, a slip assembly 120, a cone 140, a shoe member 150, and a seal assembly 160. As shown, the slip assembly 120 is disposed between the cone 140 and the shoe member 150. The slip assembly 120 may include a plurality of slip segments 122. The seal assembly 160 may include one or more seal segments 162. One end of the mandrel 110 (FIG. 2) is releasably attached to the shoe member 150. For example, a shear ring 152 is used to releasably attach the mandrel 110 and the shoe member 150. The shear ring 152 can be disposed between the mandrel 110 and a nut 114 coupled to the end of the mandrel 110. One or more bands 123 may be used to retain the seal segments 162 and slip segments 122 on the downhole tool 100. In some embodiments, the bands 123 are expandable. FIG. 1 illustrates the downhole tool 100 coupled to a setting sleeve 113 for activating the downhole tool 100.

FIG. 2 illustrates a cross-section of FIG. 1. The cone 140 includes an inclined surface and is arranged on the mandrel 110 with its inclined surface facing the shoe member 150. In this example, teeth 143 are formed on the inclined surface of the cone 140 for mating with the teeth of the sealing assembly 160 and the teeth 133 of the slip assembly 120. As shown, the mandrel 110 is disposed within the slip assembly 120, the cone 140, the shoe member 150, and the seal assembly 160.

FIG. 3A illustrates an exemplary slip segment 122. The slip segment 122 includes a slip body 130 and a slip insert 125. The slip body 130 has an inclined surface 132 for riding on the inclined surface of the cone 140. Teeth 133 may be provided on the inclined surface 132 for mating with the teeth 143 of the cone 140. The slip body 130 may have grooves 131 corresponding to the bands 123. The end of the slip body 130 with the inclined surface has a wedge shape. One or more sealing protrusions 135 having an arcuate shape are formed on the outer surface of the wedge shaped end of the slip body 130. The slip insert 125 includes one or more gripping elements 126 composed of a profile element 128 coated with a PEO coating 129. The surface of the PEO coating 129 in FIG. 1 through FIGS. 3A-3B is shown with a shading.

In one embodiment, the slip body 130 is made of a dissolvable non-metallic material. Suitable dissolvable non-metallic materials include dissolvable non-metallic polylactic acid (PLA) based polymers, polyglycolic acid (PGA) based polymers, degradable urethane, and other polymers that are dissolvable over time. In one example, the slip body 130 is manufactured using an injection molding process. The dissolvable non-metallic material is injected into a mold of the shape of the slip body 130, where it is allowed to solidify before removal from the mold. The injection molding process advantageously provides for a lower cost slip assembly manufacturing process and for various designs of the slip assembly 120 such as segmented, interconnected, or unitary body. In some embodiments, the slip body 130 is formed from a dissolvable metallic material, such as an aluminum or magnesium alloy. In one embodiment, the bands 123 may be made of a dissolvable non-metallic material or a dissolvable metallic alloy.

As shown in FIGS. 3A and 3B, the slip insert 125 is disposed in a pocket 136 formed in the slip body 130. Each slip insert 125 includes a body 127 and one or more profile elements 128. The profile elements 128 may be attached to or integral with the body 127 of the slip insert 125. For example, the profile elements 128 may be a plurality of wickers integrally formed with the body 127 as shown in FIGS. 3A-3B. The slip insert 125 may be machined to form the profile elements 128. In some embodiments, the profile elements 128 may include one or more dissolvable and/or non-dissolvable buttons attached to the body 127. In some embodiments, the entire slip insert 125 and profile elements 128 are made of a degradable metallic material such as a dissolvable metallic material. Suitable dissolvable metallic materials include magnesium alloys or aluminum alloys. In some embodiments, the aluminum alloy may be about 75% to about 95% aluminum. In some embodiments, the magnesium alloy may be about 75% to about 95% magnesium. In some embodiments, the aluminum alloy may include magnesium. In some embodiments, the magnesium alloy may include aluminum. The dissolvable metallic materials begin to dissolve upon interaction with a chemical solution, such as a solvent. The solvent may be an electrolyte solution. In some embodiments, the cone 140 may be made from an aluminum or magnesium based alloy.

In one embodiment, one or more components of the downhole tool 100 are preferably composed of degradable materials, such as dissolvable materials, so the downhole tool 100 can be removed from the wellbore upon completion of operations without requiring a drilling-out operation. For example, at least one of the slip assembly 120, the cone 140, the shoe member 150, and the seal assembly 160 can be manufactured from a degradable material. In one example, the cone 140 may be made of a degradable polymer. In one example, one or more components of the downhole tool 100 are composed of a dissolvable material. An exemplary dissolvable material is a dissolvable polymeric material.

In some embodiments, one or components of the downhole tool 100 may be formed from a degradable material, such as a dissolvable metallic material, that is reactive with a chemical solution that is an electrolyte solution. The electrolyte solution to degrade the downhole tool 100 may include an electrolyte selected from the group comprising, consisting of, or consisting essentially of solutions of an acid, a base, a salt, and combinations thereof. A salt can be dissolved in water, for example, to create a salt solution. Common free ions in an electrolyte include, but are not limited to, sodium (Na⁺), potassium (K⁺), calcium (Ca²⁺), magnesium (Mg²⁺), chloride (Cl⁻), bromide (B⁻) hydrogen phosphate (HPO₄²⁻), hydrogen carbonate (HCO₃⁻), and any combination thereof. Preferably, the electrolyte contains halide ions such as chloride ions.

The profile elements 128 are coated with the PEO coating 129 to form the gripping elements 126. The gripping elements 126 are configured to grip (e.g., bite) a downhole surface, such as the surface of a downhole tubular or the surface of the wellbore, when the slip assembly 120 is in a radially extended position. For example, when the gripping elements 126 grip the downhole surface, the downhole tool 100 is anchored in the downhole surface. The downhole surface may be a casing. In some embodiments, the PEO coating 129 is formed on and bonded to the upper surface of the body 127 and the profile elements 128. Thus, the insert 125 includes the PEO coating 129. In some embodiments, the profile elements 128 are spaced apart from one another and the PEO coating 129 is formed on and bonded to only the profile elements 128 while the remainder of the upper surface of the body 127 is not coated, leaving an uncoated surface between adjacent coated profile elements 128.

As shown in FIGS. 3A and 3B, the upper surface of the body 127 is defined by the profile elements 128, which are shown as wickers. FIG. 3C illustrates the circled region in FIG. 3B to better show the coating 129 on the profile elements 128. The profile elements 128 are coated with the PEO coating 129. The PEO coating 129 is formed on and bonded to the profile elements 128. As shown in FIGS. 3B and 3C, the PEO coating 129 has a cross-section that follows the cross-section of the profile elements 128. As a result, the outer surface of the PEO coating 129 reflects a shape similar to the shape of the profile elements 128. As a result, the gripping elements 126 reflect the shape of the profile elements 128. As shown in FIGS. 3A-3B, the gripping elements 126 reflect the shape of the wickers 128 and are thus generally wicker shaped. The one or more gripping elements 126 form a gripping surface of the slip insert 125 that engages and/or bites into the downhole surface.

As shown in FIG. 3B, the slip insert 125 may include one or more tongues 137 that are engageable with one or more slots formed in the slip body 130. The tongues 137 facilitate attachment of the slip insert 125 to the slip body 130.

In one embodiment, the slip insert 125 is attached to the slip body 130 after the slip body 130 is removed from an injection mold. In another embodiment, the slip insert 125 is disposed in an injection mold before the slip body 130 material is injected into the mold. In this respect, the slip insert 125 is attached to the slip body 130 as the slip body 130 solidifies.

In some embodiments, the slip insert 125 undergoes a PEO treatment such that the slip insert 125 includes the PEO coating 129 before attaching the slip insert 125 to the slip body 130. In some embodiments, the slip insert 125 and the slip body 130 undergo a PEO treatment together, such as when the slip insert 125 is integral to the slip body 130. In some embodiments, the PEO coating 129 may have a thickness of about 20 microns to about 250 microns. For example, the PEO coating 129 may be about 40 microns thick. In some embodiments, the PEO coating 129 has a hardness of about 300 Vickers to about 2000 Vickers, such as about 1500 Vickers to about 2000 Vickers. For comparison, the hardness of a conventional steel casing is about 350 Vickers to about 400 Vickers. In some embodiments, the slip insert 125 is treated such that the entire surface of the slip insert 125 includes the PEO coating 129. In some embodiments, only the upper surface of the body 127 with the profile elements 128 is treated to include the PEO coating 129. In some embodiments, surfaces can be masked to avoid being treated to prevent the application of a PEO coating. For example, the non-coated areas may be masked with an inert material prior to the PEO treatment. The PEO coating 129 is bonded with the slip insert 125, such as the profile element 128. Because PEO coating 129 forms the outer surface of the gripping elements 126, the PEO coating contacts and/or penetrates the downhole surface when the slip segments 122 are set. In addition to the high hardness properties, the PEO coating 129 has a low stiffness which enables the PEO coating 129 to withstand strains, such as thermally induced strains associated with wellbore temperatures, without de-bonding from the underlying slip insert 125, such as de-bonding from the profile elements 128. Additionally, the PEO coating 129 prevents the coated surface, such as the surface of the profile elements 128 and/or the upper surface of the body 127, from being in contact with wellbore fluids.

In some embodiments, a chemical solution may be flowed downhole to degrade the slip insert 125. The chemical solution may interact with the non-coated areas, resulting in the degradation of the slip insert 125. For example, the slip body 130 and slip insert 125 may be sufficiently degraded such that portions of the downhole tool 100 may be flushed from the wellbore. In some embodiments, the PEO coating 129 remains and is not chemically reactive with the chemical solution. The PEO coating 129 may remain engaged with the downhole surface or it may be flushed from the wellbore. Without being bound by theory, it is believed that the thin PEO coating 129 may break up into smaller pieces due to the flow of wellbore fluids once the slip insert 125 is degraded and no longer supports the PEO coating 129 against the downhole surface.

When deployed downhole, the downhole tool 100 is activated by a setting tool, such as a wireline setting tool, which uses conventional techniques of pulling the mandrel 110 while simultaneously pulling the slip assembly 120 against the cone 140. The cone 140 is axially abutted against the setting sleeve 113. As a result, the slip assembly 120 rides up the cone 140 and move from the radially retracted position to the radially extended position to engage a downhole surface, such a wall of the surrounding downhole tubular or the surface of the wellbore. The gripping elements 126 grip the downhole surface when the slip assembly 120 is in the radially extended position. The individual slip segments 122 are prevented from riding back down the cone 140 by the engagement of the teeth 133 of the slip segments 122 and the teeth 143 of the cone 140. The slip segments 122 may be fully or partially wedged between the cone 140 and the downhole surface. In this manner, the slip assembly 120 retains (e.g., anchors) the downhole tool 100 in place. The slip assembly 120 also causes the seal assembly 160 to move up the inclined surface of the cone 140. The individual seal segments 162 move into engagement with the downhole surface. For example, the seal segments 162 include one or more sealing protrusion 165 configured to engage the downhole surface. The slip segments 122 further include one or more sealing protrusions 135 configured to engage the downhole surface. When the downhole tool 100 is activated, and the slip assembly 120 and the seal assembly 160 are set, the sealing protrusions 165 of the seal segments 162 are configured to form a seal ring with the sealing protrusions 135 of the slip segments 122. This seal ring seals the annulus between the downhole tool 100 and the downhole surface. Once the downhole tool 100 is activated, the setting sleeve 113 and mandrel may be retrieved to the surface.

To begin a fracturing operation, an object, such as a ball or a dart, is released into the wellbore and lands in a seat 142 of the downhole tool 100. The seat 142 may be formed in the interior of the cone 140. Fracturing fluid is pumped into the wellbore to fracture the formation upstream from the downhole tool 100 with the seated object. After pumping the fracturing fluid, the downhole tool 100 may degrade, such as dissolve, over time, thereby eliminating the need for a drilling-out operation to remove the downhole tool 100. For example, one or more chemical solutions may be pumped downhole to degrade one or more components of the downhole tool 100.

In some embodiments, the downhole tool 100 does not include a seal assembly 160 and the slip segments 122 do not have corresponding sealing protrusions 135. In some embodiments, the downhole tool 100 includes an alternative seal assembly that does not include seal segments. In some embodiments, the slip segments 122 do not include a wedged shape end, and the slip segments 122 is configured to move an alternative seal assembly, such as an elastomeric ring, along the inclined surface of the cone 140 such that the elastomeric ring expands into sealing engagement with the downhole surface.

FIG. 4 illustrates a cross-sectional view of an alternative embodiment of the slip segment 122a according to another embodiment of the downhole tool 100. The slip segment 122a includes a slip body 230, a pocket 236, and a slip insert 225. The slip segment 122a may further include grooves 231 corresponding to the bands 123. As shown, the slip insert 225 has a first PEO coating 229u and a second PEO coating 229b. The first PEO coating 229u and the second PEO coating 229b may have the same or substantially the same thickness and hardness values as the PEO coating 129. As shown, the slip segment 122a does not include one or more protrusions corresponding to a seal assembly 160. The slip segments 122a may be used with a downhole tool 100 that does not include a seal assembly 160, or the slip segments 122a may alternatively be used with an alternative seal assembly 160 that does not include a plurality of seal segments. In some embodiments, the slip segments 122a may include one or more sealing protrusions and thus the downhole tool 100 can include both slip segments 122a and the seal assembly 160 with the seal segments 162. In some embodiments, the slip segments 122a are used with a downhole tool with an alternative seal assembly that seals against a downhole surface that includes seal segments 162. In some embodiments, the slip segments 122a may be used with an alternative seal assembly that is an elastomer ring configured to expand into a sealing engagement with the downhole surface as the elastomer ring travels along the inclined surface of the cone 140

The slip insert 225 is disposed in a pocket 236. The slip insert 225 includes a body 227. The pocket 236 extends through the depth of the slip body 230. The slip insert 225 includes an upper surface configured to face the downhole surface and a lower surface opposite the upper surface and configured to face the cone 140. Each slip insert 225 includes one or more first profile elements 228. The first profile elements 228 may be attached to or integral with the upper surface of the body 227. The first profile elements 228 coated with the first PEO coating 229u form the one or more gripping elements 226. The one or more gripping elements 226 are configured to grip (e.g., bite) the downhole surface when the slip segments 122a are set. The one or more gripping elements 226 form a gripping surface of the slip insert 225 that engages and/or bites into the downhole surface. An uncoated area may be between adjacent, but spaced apart, profile elements 228.

In some embodiments, the first profile elements 228 may be wickers integral with the body 227 as shown in FIG. 4. In some embodiments, the first profile elements 228 may be one or more degradable buttons, such dissolvable buttons, attached the upper surface of the body 227. In some embodiments, the first profile elements 228 may be one or more non-dissolvable buttons attached to the upper surface of the body 227. In some embodiments, the slip insert 225 and first profile elements 228 are made of a dissolvable metallic material.

In some embodiments, and as shown in FIG. 4, the lower surface of the slip insert 225 includes teeth 234. The teeth 234 are configured to engage with teeth 143 of the cone 140. Each tooth 234 may be composed of a second profile element 233 coated with the second PEO coating 229b. In some embodiments, the slip insert 225 may be machined to form the first profile elements 228 and the second profile elements 233. The slip insert 225 may have a tongue 237. Suitable dissolvable metallic materials include magnesium or aluminum based dissolvable alloys. In one embodiment, the dissolvable metallic materials are dissolvable upon interaction with chemical solution, such as an electrolyte solution.

In some embodiments, the slip body 230 includes an inclined surface 232 corresponding to the inclined surface of the cone 140. In some embodiments, the slip insert 225 and/or the slip body 230 include the inclined surface 232. As shown, the teeth 234 are disposed on the inclined surface 232.

In some embodiments, the slip insert 225 is entirely coated with a PEO coating 229. In some embodiments, only the upper surface and the first profile elements 228 are coated with the first PEO coating 229u and the teeth 234 are simply the second profile elements 233 without a coating. In some embodiments, and as shown in FIG. 4, the upper surface of the body 227 and first profile elements 228 are coated with the first PEO coating 229u and the lower surface and second profile elements 233 are coated with the second PEO coating 229b. The first PEO coating 229u is bonded to the first profile elements 228 and has a cross-section that follows the cross section of the first profile elements 228. As a result, the outer surface of the first PEO coating 229u reflects a shape similar to the shape of the first profile elements 228. The second PEO coating 229b covers and is bonded to the second profile elements 233. The second PEO coating 229b has a cross section that follows the cross-section of the second profile elements 233. As a result, the outer surface of the second PEO coating 229b reflects a shape similar to the shape of the second profile elements 233.

The slip segment 122a may be formed in a similar manner as discussed above with respect to slip segment 122.

FIG. 5 is a flow diagram of a method 300 for a PEO treatment to develop a PEO coating. The method 300 begins at operation 301, in which surfaces of a substrate, such as the surface of the profile elements 128, 228, 233, and/or the surface of the body 127, 227, are subjected to a cleaning operation. In one example, the substrate may include an aluminum alloy or a magnesium alloy. The operation 301 may include exposure to one or more of a degreasing agent, an alkaline soak, and a clean water rinse to remove particulates or other debris from surfaces of the substrate where a PEO coating is desired. For example, the insert 125, 225 may be cleaned in operation 301. In operation 302, a masking material may be applied to the substrate to mask areas in which the formation of a PEO coating undesired. For example, every surface of the slip insert 125 but the upper surface may be masked. In operation 303, the substrate and the optional masking are placed in an electrolytic bath. The electrolytic bath includes the materials necessary to form the PEO coating, such as PEO coating 129. The electrolyte material may be selected based on the desired PEO coating to be developed. For example, the electrolyte bath may include an alkaline solution such as Potassium Hydroxide (KOH). An electric potential is applied to the substrate which exceeds the dielectric breakdown potential of the growing oxide layer that grows on the substrates surface, resulting in discharges into the electrolyte bath to create plasma reactions. For example, the substrate may be one electrode and another electrode is disposed in the electrolyte bath. The plasma reactions modify the growing oxide layer to develop the PEO coating. Thus, the plasma reaction may incorporate electrolytes in the electrolytic bath into the PEO coating. For example, a PEO treatment may result in the conversion of amorphous alumina into the harder corundum. The electrolyte material, composition of the substrate, and electrical potential may be influenced by the resulting thermal properties, hardness properties, strain tolerance, fatigue performance, and adhesive properties of the desired PEO coating. The PEO coating may be created by Keronite®.

Other exemplary, suitable methods of forming the PEO coating may be similar to the PEO treatments described in U.S. Pat. Nos. 6,365,028 and 6,896,785, and U.S. Patent Publication No. 2012/0031765, which descriptions are herein incorporated by reference.

Advantages of a PEO coating includes high wear resistance, hardness, and is resistant to corrosion. The PEO coating further provides a barrier between the substrate and wellbore fluids, such as a chemical solution added to the wellbore fluids. A PEO coating may grow both inward and outward from the substrate, resulting in a coating that is well adhered to the substrate. It is believed a PEO layer is superior to a conventional anodized layer or sprayed-on hard facing due to increased hardness caused by plasma reactions that cause the formation of crystalline forms of the substrate. Without being bound by theory, it is believed that a PEO layer provides a better fluid barrier for protecting a substrate than a conventional anodized layer or sprayed-on hard facing layer. A PEO coating may have a relatively low coefficient of friction. However, the PEO coating is deposited on the profile elements to develop an outer surface of the PEO coating that is similar (e.g., mirrors) to the shape of the profile elements. The coated profile elements form gripping elements configured to grip the downhole surface. The gripping elements form a gripping surface of the slip.

In some embodiments, the slip body is degraded prior to the degradation of the slip insert. For example, at least a portion of the slip body 130, 230 is degraded to expose a non-PEO coated surface of the slip insert 125, 225. The exposed non-PEO coated surface of the slip insert 125, 225 allows the chemical solution to cause degradation of the slip insert 125, 225. In some embodiments, one chemical solution is used to dissolve the slip body 130, 230 and a second, different chemical solution is used to dissolve the slip insert 125, 225.

In some embodiments, the slip segments do not include a slip insert 125, 225. Instead, the slip segments are formed from a degradable material, such as aluminum or magnesium alloy, and the slip segments have profiles elements, such as wickers, formed on or attached to a surface thereof. The slip segments are coated in a PEO coating. For example, the slip segments may have a PEO coating only on the surface configured to face a downhole tubular. In some embodiments, only the profile elements are coated. The PEO coated profile elements form gripping elements configured to grip the downhole surface when the slip segments are set against the downhole surface. The PEO coating may reflect the shape of the profile elements. For example, the gripping elements may resemble wickers if the profile elements are wickers. The PEO coating is configured to contact and/or penetrate the downhole surface. As a result, the slip segment with the PEO coating can be engaged with the downhole surface to anchor the downhole tool including the slip segments. The slip segments may include second profile elements that are coated in a PEO coating to form teeth that are configured to engage the teeth 143 of the cone 140.

As will be understood by a person of ordinary skill in the art, conventional slips may use buttons that grip the downhole casing. The buttons are attached to a slip segment, and the slip segment may be formed from a dissolvable or degradable material. For example, these buttons may be formed from machined ductile iron, cast iron, powder metal, ceramic, or combinations thereof. Conventional buttons are difficult to dissolve or degrade with conventional techniques. Once the slip segments holding the buttons degrade or dissolve, the buttons are no longer held into engagement with the downhole tubular. A cleanup operation may be necessitated to flow the buttons back to the surface. Unlike conventional buttons, the PEO coating that remains after the degradation of the slip easily flows back to the surface or is easily flowed downhole without the need for a time consuming cleanup operation.

In some embodiments, the PEO coatings remaining in the wellbore after the degradation of the downhole tool may be flowed back to the surface. In some embodiments, flowing the PEO coatings back to the surface may be completed as part of another operation that is not dedicated to cleaning the wellbore. Exemplary operations suitable for flowing back remaining PEO coatings include cleanup operation, a gel sweep operation, a production operation, or a milling operation. For example, the PEO coating may be flowed back to the surface during an operation to degrade another downhole tool having a PEO coating.

In some embodiment, the downhole tool 100 includes conventional buttons as profile elements which are coated with a PEO coating. One or more chemical solutions are used to degrade the downhole tool 100, leaving the buttons and the PEO coating. The buttons with the PEO coating may be flushed from wellbore.

In some embodiments, the PEO coating is applied to a non-degradable slip insert. In some embodiment of the slip assembly without a slip insert, the PEO coating may be applied to a non-degradable slip body. The non-degradable material may be a metallic material. For example, the profile elements may be formed from a non-degradable material, such as a non-dissolvable button. For example, a non-degradable button, such as a non-dissolvable button, may be formed from a ceramic material, powder metal, cast iron, ductile iron, or an alloy steel. In some embodiments, the profile elements may be non-dissolvable wickers.

FIG. 6 illustrates the downhole tool 100 in FIG. 1 after activation to set the slip assembly 120 and the seal assembly 160 against a downhole surface, which is the inner surface of the downhole tubular 700. The downhole tubular 700 may be a casing. Before the downhole tool 100 was activated, the downhole tool 100 was deployed into the downhole tubular 700. For example, the downhole tool 100 may be deployable downhole by a wireline setting tool and the slip assembly 120 and the seal assembly 160 are set by the wireline setting tool. As shown, the gripping elements 126 are engaged with the downhole surface, the downhole surface being the inner surface of the downhole tubular 700. The PEO coating 129 is engaged with the inner surface of the downhole tubular 700. The PEO coating 129 may also penetrate the downhole tubular 700. Thus, the slip segments 122 with the gripping elements 126 anchor the downhole tool 100 to the downhole tubular 700 when the slip segments 122 are in the extended position. Alternative slip segments, such as slip segments 122a having slip insert 225 or a slip segment without an insert, may be used to grip the downhole tubular with corresponding gripping elements composed of profile elements and the PEO coating.

After the downhole tool 100 is activated, an object 200 may be dropped which engaged the seat 142. As shown in FIG. 6, object 200 is a ball engaged with the seat 142. The object 200 may be made of a degradable material, such as a dissolvable material. A fracturing operation may occur after the object is engaged with the seat 142. After, or during, the fracturing operation, one or more chemical solutions are introduced into the wellbore to degrade the downhole tool 100 and/or object 200, which leave behind the PEO coating 129. The object 200 may also be extruded from the seat 142 instead of, or in addition to, being degraded. The PEO coating 129 may then be flowed further downhole or flowed out of the wellbore.

In some embodiments, the gripping elements 126, 226 penetrate the downhole surface, such as the inner surface of a casing.

FIG. 7 illustrates an exemplary downhole tool 400 deployable in a wellbore. The downhole tool 400 is shown disposed at the lower end of a casing string disposed in a wellbore. The downhole tool 400 includes a tubular member 410 and a seat 420. The seat 420 may be made of a dissolvable or degradable material. The seat 420 includes a body 422 and a PEO coating 424. The PEO coating 424 protects the body 422 of the seat 420 from wellbore fluids that could damage the seat 420. For example, The PEO coating 424 protects the ball seat 420 from degradation due to fracturing fluids, such as the abrasive properties of the sand. An object, such as a ball, is deployable into the wellbore to engage the seat 420 (via the PEO coating 424) and closes fluid communication through the seat 420. Pressure can be increased above the seated object. For example, the downhole tool 400 can be used to pressure test the casing string.

Alternatively, the seat 420 may be incorporated into another type of downhole tool, such as a packer, a liner hanger, or a fracturing tool. In one embodiment, the fracturing tool may be a plug and perforation tool. For example, the seat 420 may replace seat 142, in that the seat 142 of the cone 140 includes a PEO coating. In one embodiment, a downhole tool string may include a plurality of seats 420. The plurality of seats 420 may be graduated, in that some seats 420 may have a larger diameter than others to catch different sized objects. In some embodiments, the seat 420 is incorporated, attached to, or integral with a sliding sleeve such that pressure above an object caught by the seat 420 will cause the sliding sleeve to move.

The PEO coating 424 is applied to the body 422 in substantially the same way as described above.

FIG. 8 illustrates a downhole tool 800 used for a fracturing operation. The downhole tool includes a tubular member 810, a first sleeve 820, and a second sleeve 830. The first sleeve 820 and the second sleeve 830 are disposed in the tubular member 810. The first sleeve 820 has a first seat 822 coated with a PEO coating 822c. The second sleeve 830 includes a second seat 832 coated with a PEO coating 832c. The tubular member 810 includes a first set of fracturing ports 840 and a second set of fracturing ports 842. The first sleeve 820, in a first position, blocks the first set of fracturing ports 840. The first sleeve 820 is moveable to a second position to expose the first set of fracturing ports 840 in response to fluid pressure above a first object, such as a ball, engaged with the first seat 822. The second sleeve 830 is moveable to a second position to expose the second set of fracturing ports 842 in response to fluid pressure above a second object, such as a ball, engaged with the second seat 832. FIG. 8 shows the first sleeve 822 and the second sleeve 832 in the second position. The second seat 832 may have a diameter larger than a diameter of the first seat 822 such that the first object passes through the second seat 832 without seating against the second seat 832. The first object may be deployed first to land in the first seat 822 to cause the first sleeve 820 to be opened. Then, a fracturing operation is performed to fracture the formation via the exposed first set of fracturing ports 840. Later, the second object may be deployed to open the second sleeve 830. Then, a subsequent fracturing operation is performed to fracture a second zone of the formation via the exposed second set of fracturing ports 842. In some embodiments, one or more shearable members may retain the first sleeve 822 and the second sleeve 832 in the first position.

The PEO coating 822c and the PEO coating 832c protects the first seat 822 and the second seat 832, respectively, from damage by wellbore fluids. The protection afforded by the coatings 822c, 832c facilitates sealing engagement of the objects with the respective seat 822, 832 such that a fracturing operation can be performed. The downhole tool 800 may include additional sleeves to allow additional zones of the wellbore to be selectively fractured. The PEO coating 822c of the first seat 822 and the PEO coating 832c of the second seat 832 may be applied in substantially the same way as described above. In some embodiments, the downhole tool 800 may include one or more degradable or dissolvable components.

In some embodiments of the downhole tool, the slip body is formed from a degradable material.

In some embodiments of the downhole tool, the slip body has a plurality of teeth disposed on a surface opposite of the plurality of profile elements, and wherein the plurality of teeth are configured to engage with a plurality of teeth of the cone member.

In some embodiments of the downhole tool, the slip body further includes a pocket and a slip insert disposed in the pocket, wherein the slip insert includes the gripping elements.

In some embodiments of the downhole tool, wherein the slip body is formed from a degradable polymer and the slip insert is formed from either an aluminum or magnesium alloy.

In some embodiments of the downhole tool, wherein the slip insert has a lower surface opposite the engagement surface, the lower surface including a plurality of teeth configured to engage with a plurality of teeth of the cone member, wherein the teeth of the slip insert are composed of a plurality of second profile elements with a second coating disposed thereon, wherein the second coating formed from the plasma electrolytic oxidation treatment and.

In some embodiments of the downhole tool, the profile elements are wickers.

In some embodiments of the downhole tool, the profile elements are attached to the slip insert.

In some embodiments of the downhole tool, the profile elements are formed from a magnesium alloy.

In some embodiments of the downhole tool, the slip body is formed from a degradable material.

In some embodiments of the downhole tool, the slip body further includes a pocket and a slip insert disposed in the pocket, wherein the slip insert includes the plurality of gripping elements.

In some embodiments of the downhole tool, the slip body is formed from a degradable polymer and the slip insert is formed from either an aluminum or magnesium alloy.

In some embodiments of the downhole tool, wherein the slip insert has a lower surface opposite the engagement surface, the lower surface including a plurality of teeth configured to engage with a plurality of teeth of a cone member, wherein the teeth of the slip insert are composed of a plurality of second profile elements with a second coating disposed thereon, wherein the second coating formed from the plasma electrolytic oxidation treatment and.

In some embodiments of the downhole tool, the profile elements are attached to the slip insert.

In some embodiments of the downhole tool, the profile elements are formed from a degradable material.

In some embodiments of the downhole tool, the profile elements are formed from a magnesium alloy.

In some embodiments of the downhole tool, the profile elements are a plurality of non-dissolvable buttons.

In some embodiments, the method further includes performing a fracturing operation with the downhole tool.

In some embodiments, the method further includes suppling one or more chemical solutions downhole to degrade the downhole tool, wherein the coating is left in a wellbore upon the degradation of the downhole tool.

In some embodiments, the method further includes flowing the coating to the surface.

In some embodiments of the method, the slip insert includes the coating.

In one embodiment, a downhole tool includes a tubular member and a seat having a coating, wherein the coating is formed from a plasma electrolytic oxidation treatment.

In some embodiments of the downhole tool, a sleeve disposed in the tubular member includes the seat, wherein the sleeve is moveable from a first position to a second position in response to a fluid pressure above an object engaged with the coating.

In one embodiment, a downhole tool includes a slip assembly having a plurality of slips configured to engage a downhole surface. The slip assembly includes a plurality of slip segments. Each slip segment includes a slip body, a plurality of degradable profile elements coupled to the slip body, and a first coating disposed on the plurality of profile elements, wherein the first coating is formed from a plasma electrolytic oxidation treatment. The first coating and the plurality of profile elements form a plurality of gripping elements configured to grip the downhole surface.

In some embodiments of the downhole tool, the slip body is formed from a degradable material.

In some embodiments of the downhole tool, the slip body further includes a pocket and a slip insert disposed in the pocket, wherein the slip insert includes the plurality of gripping elements.

In some embodiments of the downhole tool, the slip body is formed from a degradable polymer and the slip insert is formed from either an aluminum or magnesium alloy.

In some embodiments of the downhole tool, wherein the slip insert has a lower surface opposite the engagement surface, the lower surface including a plurality of teeth configured to engage with a plurality of teeth of a cone member, wherein the teeth of the slip insert are composed of a plurality of second profile elements with a second coating disposed thereon, wherein the second coating formed from the plasma electrolytic oxidation treatment and.

In some embodiments of the downhole tool, the profile elements are attached to the slip insert.

In some embodiments of the downhole tool, the profile elements are formed from a magnesium alloy.

In one embodiment, a downhole tool includes a tubular member and a seat including a coating. The coating is formed from a plasma electrolytic oxidation treatment.

While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Downhole Tool

Information

Publication Number

Date Filed

Date Published

Inventors

Original Assignees

CPC

International Classifications

Abstract

Description

Claims