US 9,068,428 B2Grant
Selectively corrodible downhole article and method of use
Issue Date:2015-06-30
•23 Claims
•6 Drawing Sheets
Abstract
A selectively corrodible downhole article includes a movable cylindrical member comprising a first section and an axially separated second section, the first section comprising a first material having a first galvanic activity, the second section comprising a second material having a second galvanic activity, the first galvanic activity greater than the second, the first section electrically isolated from the second section. The article also includes a fixed member disposed on the cylindrical member and configured for electrical contact with the first or second section, the fixed member comprising an intermediate material having an intermediate galvanic activity, the intermediate galvanic activity intermediate the first and second galvanic activity, the movable cylindrical member configured for movement from a first position where the first section is disposed and in electrical contact with the fixed member and a second position where the second section is disposed and in electrical contact with the fixed member.
Metadata
Assignee
- Baker Hughes Incorporated
Inventors
- Oleg A. Mazyar
- Michael H. Johnson
Application Information
Application Number:US 13/371,788
Filing Date:2012-02-13
Priority Date:2012-02-13
Art Unit:3676
Classifications
IPC:
E21B34/06E21B33/12E21B43/285E21B43/28E21B34/00
Field of Search:
E21B 34/06E21B 33/12E21B 34/063E21B 43/28E21B 43/285E21B 2034/002
Patent Drawings (6 sheets)
Description
Background
[0001] Certain downhole operations involve placement of elements in a downhole environment, where the element performs its function, and is then removed. For example, elements such as ball/ball seat assemblies and fracture (frac) plugs are downhole elements used to seal off lower zones in a borehole in order to carry out a hydraulic fracturing process (also referred to in the art as “fracking”) to break up different zones of reservoir rock. After the fracking operation, the ball/ball seat or plugs are then removed to allow, inter alia, fluid flow to or from the fractured rock.
[0002] Balls and/or ball seats, and frac plugs, can be formed of a corrodible material so that they need not be physically removed intact from the downhole environment. In this way, when the operation involving the ball/ball seat or frac plug is completed, the ball, ball seat, and/or frac plug is dissolved away. Otherwise, the downhole article may have to remain in the hole for a longer period than is necessary for the operation.
[0003] To facilitate removal, such elements can be formed of a material that reacts with the ambient downhole environment so that they need not be physically removed by, for example, a mechanical operation, but instead corrode or dissolve in the downhole environment. In order to employ dissolution or corrosion to remove downhole elements, it is very desirable to develop downhole articles and methods of their use whereby the dissolution or corrosion and removal of these elements may be selectively controlled.
Summary
[0004] In an exemplary embodiment, a selectively corrodible downhole article is disclosed. The article includes a movable cylindrical member comprising a first section and an axially separated second section, the first section comprising a first material having a first galvanic activity, the second section comprising a second material having a second galvanic activity, the first galvanic activity being greater than the second galvanic activity, the first section being electrically isolated from the second section. The article also includes a fixed member disposed on the cylindrical member and configured for electrical contact with the first section or the second section, the fixed member comprising an intermediate material having an intermediate galvanic activity, the intermediate galvanic activity being intermediate the first galvanic activity and the second galvanic activity, the movable cylindrical member configured for movement from a first position where the first section is disposed on and in electrical contact with the fixed member and a second position where the second section is disposed on and in electrical contact with the fixed member, wherein in the first position, the first section is configured for selective dissolution, and wherein in the second position, the fixed member is configured for selective dissolution.
[0005] In another exemplary embodiment, a method of removing a selectively corrodible downhole article is disclosed. The method includes disposing downhole a selectively corrodible downhole article, comprising: a movable cylindrical member comprising a first section and an axially separated second section, the first section comprising a first material having a first galvanic activity, the second section comprising a second material having a second galvanic activity, the first galvanic activity being greater than the second galvanic activity, the first section being electrically isolated from the second section; and a fixed member disposed on the cylindrical member and configured for electrical contact with the first section or the second section, the fixed member comprising an intermediate material having an intermediate galvanic activity, the intermediate galvanic activity being intermediate the first galvanic activity and the second galvanic activity, the movable cylindrical member configured for movement from a first position where the first section is disposed on and in electrical contact with the fixed member and a second position where the second section is disposed on and in electrical contact with the fixed member, wherein in the first position, the first section is configured for selective dissolution, and wherein in the second position, the fixed member is configured for selective dissolution. The method also includes exposing the selectively corrodible downhole article to a first wellbore fluid while the movable cylindrical member is in the first position, wherein the first section is selectively dissolved. The method further includes moving the movable cylindrical member to the second position and exposing the selectively corrodible metallic downhole article to a second wellbore fluid, wherein the fixed member is selectively dissolved.
Brief Description of the Drawings
[0006] Referring now to the drawings wherein like elements are numbered alike in the several Figures:
[0007] FIG. 1A is a cross-sectional view of an exemplary embodiment of a selectively corrodible downhole article comprising a ball, ball seat and movable cylindrical sleeve in a first position as disclosed herein;
[0008] FIG. 1B is a cross-sectional view of the exemplary embodiment of a selectively corrodible downhole article of FIG. 1A with the movable cylindrical sleeve in a second position as disclosed herein;
[0009] FIG. 2A is a cross-sectional view of an exemplary embodiment of a selectively corrodible downhole article comprising a plug, plug seat and movable tubular article in a first position as disclosed herein;
[0010] FIG. 2B is a cross-sectional view of the exemplary embodiment of a selectively corrodible downhole article of FIG. 2A with the movable tubular article in a second position as disclosed herein; and
[0011] FIG. 3 is a flowchart of an exemplary embodiment of a method of removing a selectively corrodible downhole article.
Detailed Description of the Invention
[0012] Referring to the figures, and particularly FIGS. 1-3 , a method 100 of removing a selectively corrodible downhole article 10 from a wellbore 70 is disclosed. The wellbore 70 may be formed in an earth formation 2 and may include a cement casing 4. The wellbore may also include a liner 6, which may include a plurality of metal tubulars (tubular sections) 8. The selectively corrodible downhole article 10 may comprise any suitable downhole article, including various downhole tools or components. In one embodiment, the selectively corrodible downhole article 10 may include a selectively corrodible ball 50 and ball seat 52, such as a frac ball and complementary ball seat, or a selectively corrodible plug 60 and plug seat 62, such as a frac plug and complementary plug seat. The article 10 is configured for selective dissolution in a suitable wellbore fluid 72, 74 acting as an electrolyte.
[0013] The article 10 includes a movable member, such as a movable cylindrical member 12, comprising a first section 14 and an axially separated second section 16. The first section 14 comprising a first material 18 having a first galvanic activity. The second section 16 includes a second material 20 having a second galvanic activity. The first galvanic activity is greater than the second galvanic activity, such that it has a greater tendency to corrode in a given wellbore fluid as an electrolyte. The first section 14 is electrically isolated from the second section 16. Electrical isolation may be accomplished by any suitable electrical isolator 22. A suitable electrical isolator may include any suitable electrically insulating material, particularly an electrically insulating polymer or ceramic, or a combination thereof.
[0014] The article 10 also includes a fixed member 24 disposed on the movable cylindrical member 12 or movable cylindrical member 12 may be disposed within fixed member 24. The movable cylindrical member 12 and fixed member 24 are both electrically conductive. The fixed member 24 is configured for electrical contact with the first section 14 or the second section 16, the fixed member 24 comprising an intermediate material 26 having an intermediate galvanic activity, the intermediate galvanic activity being intermediate the first galvanic activity and the second galvanic activity. The movable cylindrical member 12 is configured for movement from a first position 28 where the first section 14 is disposed on and in electrical contact with the fixed member 24 and a second position 30 where the second section 16 is disposed on and in electrical contact with the fixed member 24. In the first position 28, the first section 14 is configured for selective dissolution because the first material 18 is more galvanically active (i.e., is more reactive) than the intermediate material 26. In the second position, the fixed member 24 is configured for selective dissolution because the intermediate material 26 is more galvanically active than the second material 20. The first material 18, intermediate material 26 and second material 20 may each be, for example, a different metal from the galvanic series having the relative activities described herein. The first material 18, intermediate material 26 and second material 20 contact each other as described herein in the presence of a wellbore fluid that comprises an electrolyte, such as for example a brine, acidizing fluid, drilling mud or the like.
[0015] Referring to FIGS. 1A and 1B , the selectively corrodible article 10 may include a ball 50 and ball seat 52. In one embodiment, at least one of ball 50 and ball seat 52 comprise intermediate material 26. In this embodiment, while at least one of ball 50 and ball seat 52 comprise intermediate material 26, the other of the ball 50 and ball seat 52 may include another electrically conductive material that is less galvanically active than the material intermediate material 26. For example, the ball 50 may be formed from intermediate material, and the ball seat may be formed from a less galvanically active material, such that the ball 50 is configured for removal as described herein. Alternately, the ball seat 52 may be formed from intermediate material, and the ball may be formed from a less galvanically active material, such that the ball seat 52 is configured for removal from the wellbore 70 as described herein, and the ball 50 may be allowed to fall to a lower portion of the wellbore 70. In another embodiment, both the ball 50 and ball seat 52 may comprise intermediate material 26 and are configured for removal from the wellbore 70 as described herein.
[0016] Referring to FIGS. 2A and 2B , the selectively corrodible article 10 may include a plug 60, such as a frac plug, or a plug seat 62. In one embodiment, at least one of plug 60 and plug seat 62 comprise intermediate material 26. In this embodiment, while at least one of plug 60 and plug seat 62 comprise intermediate material 26, the other of the plug or plug seat 62 may include another electrically conductive material that is less galvanically active than the material intermediate material 26. For example, the plug 60 may be formed from intermediate material, and the plug seat 62 may be formed from a less galvanically active material, such that the plug 60 is configured for removal as described herein. Alternately, the plug seat 62 may be formed from intermediate material, and the plug 60 may be formed from a less galvanically active material, such that the plug seat 62 is configured for removal from the wellbore 70 as described herein, and the plug 60 may be allowed to fall to a lower portion of the wellbore 70. In another embodiment, both the plug 60 and plug seat 62 may comprise intermediate material 26 and are configured for removal from the wellbore 70 as described herein.
[0017] Referring to FIGS. 1A and 1B , in one embodiment the movable cylindrical member 12 may include a slidable sleeve 40 disposed within a tubular article 42 that may be moved axially upwardly or downwardly within the wellbore 70. In another embodiment, the movable cylindrical member 12 may include a movable tubular article 44 that may be moved axially upwardly or downwardly within the wellbore 70, as illustrated in FIGS. 2A and 2B . While the movable cylindrical member 12 is illustrated in FIGS. 2A and 2B with the first section 14 uphole (closer to the surface) from the second section 16 (FIG. 2A ), such that the movable member 12 is moved uphole (FIGS. 1B and 2B ) in accordance with method 100, as described herein, it will be understood that the positions of the first section 14 and the second section 16 may be reversed, such that the first section 14 is downhole (farther from the surface) from the second section 16, such that the movable member 12 is moved downhole in accordance with method 100, as described herein and illustrated in FIGS. 1A and 1B .
[0018] Referring to FIGS. 1A and 1B , in one embodiment the slidable sleeve 40 includes a first section 14 having a shape, such as the shape of a cylindrical ring or hollow cylinder, which is configured to abut the lower surface of the ball seat 52 in intimate touching contact sufficient to establish electrical contact between them for the purposes described herein. First section 14 formed from first material 18 is attached proximate a lower end of an electrical isolator 22 that may have any suitable shape, such as a hollow cylindrical shape, and is slidably disposed within the central bore of ball seat 52 and configured to move from first position 28 (FIG. 1A ) to second position 30 (FIG. 1B ). Slidable sleeve 40 also includes a second section 16 having a shape, such as the shape of a hollow frustoconical disk, which is configured to sealing engage the upper seating surface of the ball seat 52 in intimate touching and sealing contact sufficient to establish electrical contact and sealing contact between them for the purposes described herein. Second section 16 formed from second material 20 is attached proximate an upper end of the electrical isolator 22. In the first position 28, the second section 16 is electrically isolated from the ball seat 52 in the presence of first wellbore fluid 72 that is configured to act as an electrolyte and first section 14 is in electrical contact with the ball seat. As described herein, the first material 18 is configured to be more galvanically active in the electrolyte than the intermediate material 26 of the ball seat 52, such that the ball seat is protected from corrosion in first position 28, and first material is configured to be selectively corroded or dissolved in the first fluid 72. First position 28 may, for example, represent preparation and configuration of a section of the wellbore for a completion operation. The first section 14 may be biased against the ball seat 52 by a bias member, such as, for example, bias spring 31. Bias spring 31 may be configured for eventual removal by an appropriate wellbore fluid, such as second wellbore fluid 74, or may be configured such that its presence in the wellbore does not substantially interfere with the intended wellbore operations. Once the wellbore has been configured, it may be desirable to perform an operation such as fracturing by insertion of a ball 50 in first wellbore fluid 72 (FIG. 1A ) and pressurization of a second wellbore fluid 74 that is also configured to act as an electrolyte as shown in FIG. 1B . Pressurization of the second fluid 74 drives the ball 50 into the second section 16 thereby causing the slidable sleeve 40 to slide to second position 30 where the second section is in intimate electrical contact with the surface of ball seat 52 such that the wellbore operation may be performed in the pressurized portion of the wellbore above the seal formed between ball 50, second section 16 and ball seat 52. The first section 14 moves out of electrical contact with the ball seat 52 and ceases to provide galvanic protection afforded in the first position 28. In the second position 30, the intermediate material of the ball seat 52 and/or ball 50, for example, is more galvanically active than the second material 20 of the second section 16, thereby causing the ball seat 52 and/or ball 50 to corrode or dissolve in preparation for its eventual removal from the wellbore. The absolute and relative galvanic activity of intermediate material 26 and second material 20 may be selected to establish a predetermined time interval for performing the desired wellbore operation such as fracturing, including a predetermined interval for removal of the ball seat 52 and/or ball 50, as described herein. Since the ball seat 52 is supporting the ball 50 and slidable sleeve 40, it will be understood that its corrosion or dissolution will cause the ball 50 and slidable sleeve 40 to be removed from the location shown in the wellbore, such as by falling to a lower portion of the wellbore, such as the bottom of the wellbore.
[0019] The first material 18 may, for example, comprise any suitable corrodible, high reactivity metal. In one embodiment, the first material is magnesium, which is anodic with respect to the intermediate material 26 and second material 20. The first material 18 may includes any material suitable for use in a downhole environment, provided the first material 18 is more galvanically active in the downhole environment relative to the intermediate material 26 and second material 20. In particular, first material 18 may be selected from the materials described herein for use as intermediate material 26, so long as the first material 18 is selected to be more galvanically active than the intermediate material 26.
[0020] The intermediate material 26 may, for example, comprise a corrodible, intermediate reactivity metal. In one embodiment, the intermediate material 26 comprises magnesium, aluminum, manganese or zinc, or an alloy thereof, or a combination comprising at least one of the foregoing. Magnesium alloys include any such alloy which is corrodible in a corrosive environment including those typically encountered downhole, such as an aqueous environment which includes salt (i.e., brine), or an acidic or corrosive agent such as hydrogen sulfide, hydrochloric acid, or other such corrosive agents. Magnesium alloys suitable for use include alloys of magnesium with aluminum (Al), cadmium (Cd), calcium (Ca), cobalt (Co), copper (Cu), iron (Fe), manganese (Mn), nickel (Ni), silicon (Si), silver (Ag), strontium (Sr), thorium (Th), zinc (Zn), or zirconium (Zr), or a combination comprising at least one of these elements. Particularly useful alloys can be prepared from magnesium alloy particles including those prepared from magnesium alloyed with Al, Ni, W, Co, Cu, Fe, or other metals. Alloying or trace elements can be included in varying amounts to adjust the corrosion rate of the magnesium. For example, four of these elements (cadmium, calcium, silver, and zinc) have to mild-to-moderate accelerating effects on corrosion rates, whereas four others (copper, cobalt, iron, and nickel) have a still greater accelerating effect on corrosion. Exemplary commercially available magnesium alloys which include different combinations of the above alloying elements to achieve different degrees of corrosion resistance include, but are not limited to, for example, those alloyed with aluminum, strontium, and manganese such as AJ62, AJ50x, AJ51x, and AJ52x alloys, and those alloyed with aluminum, zinc, and manganese which include AZ91A-E alloys.
[0021] It will be appreciated that alloys having corrosion rates greater than those of the above exemplary alloys are contemplated as being useful herein. For example, nickel has been found to be useful in decreasing the corrosion resistance (i.e., increasing the corrosion rate) of magnesium alloys when included in amounts less than or equal to about 0.5 wt %, specifically less than or equal to about 0.4 wt %, and more specifically less than or equal to about 0.3 wt %, to provide a useful corrosion rate for the corrodible downhole article. The above magnesium alloys are useful for forming the intermediate material 26, and may be formed into the desired shape and size by casting, forging and machining.
[0022] In one embodiment, powders of magnesium or the magnesium alloys described are useful for forming the fixed member 24 as a powder compact. The magnesium alloy powder generally has a particle size of from about 50 to about 250 micrometers (μm), and more specifically about 60 to about 140 μm. The powder may be further coated using a method such as chemical vapor deposition, anodization or the like, or admixed by physical method such as cryo-milling, ball milling, or the like, with a metal or metal oxide, nitride or carbide, such as Al, Ni, W, Co, Cu or Fe, or oxides, nitrides or carbides thereof, or an alloy thereof, or a combination thereof. The coatings may have any suitable thickness, including nanoscale coatings having an average thickness of about 5 nm to about 2500 nm. Such coated powders are referred to herein as controlled electrolytic materials (CEM). The CEM is then molded or compressed into the desired shape by, for example, cold compression or pressing using an isostatic press at about 40 to about 80 ksi (about 275 to about 550 MPa), followed by extrusion, forging, or sintering, or machining, to provide a core having the desired shape and dimensions. The CEM materials may include the cellular nanomatrix materials formed from the powder materials described, for example, in commonly assigned, co-pending U.S. application Ser. No. 12/633,682 filed on Dec. 8, 2009; U.S. application Ser. No. 13/220,824 filed on Aug. 30, 2011; U.S. application Ser. No. 13/220,832 filed on Aug. 30, 2011; and U.S. application Ser. No. 13/220,822 filed on Aug. 30, 2011, which are incorporated herein by reference in their entirety.
[0023] It will be understood that the magnesium alloy or CEM, may thus have any corrosion rate necessary to achieve the desired performance of the article. In a specific embodiment, the magnesium alloy or CEM used to form the fixed member 24 has a corrosion rate of about 0.1 to about 150 mg/cm2/hour, specifically about 1 to about 15 mg/cm2/hour using aqueous 3 wt % KCl at 200° F. (93° C.).
[0024] The second material 20 is, in an embodiment, any material that is galvanically less active (having a lower reactivity than the first material 18 and intermediate material 26), based on, for example, the saltwater galvanic series. The second material 20 may include a lower reactivity metal such as various grades of steels, tungsten, chromium, nickel, copper, cobalt, iron, or an alloy thereof, or a combination comprising at least one of the foregoing. In one embodiment, the second material 20 may be substantially non-corrodible or inert in the downhole environment. In another embodiment, the second material 20 may be resistant to corrosion by a corrosive material. As used herein, “resistant” means the second material is not etched or corroded by any corrosive downhole conditions encountered (i.e., brine, hydrogen sulfide, etc., at pressures greater than atmospheric pressure, and at temperatures in excess of 50° C.), or any wellbore 70 fluid used in conjunction with the articles or methods described herein.
[0025] By selecting the reactivity of the first and second materials to have a greater or lesser difference in their corrosion potentials, the higher reactivity material (e.g., high reactivity metal) corrodes at a faster or slower rate, respectively. Generally, for metals in the galvanic series, the order of metals, from more noble (i.e., less active and more cathodic) to less noble (i.e., more active and more anodic) includes for example steel, tungsten, chromium, nickel, cobalt, copper, iron, aluminum, zinc, and magnesium.
[0026] When the dissimilar metal combinations described herein are brought into electrical contact in the presence of an electrolyte, an electrochemical potential is generated between the anodic, more galvanically active material and the cathodic, less galvanically active material. The greater the difference in corrosion potential between the dissimilar metals, the greater the electrical potential generated. In such an arrangement, the cathodic material is protected from corrosion by the anodic material, where the anodic material corrodes as a sacrificial anode. Corrosion of the fixed member 24, for example, in brines and other electrolytes can be controlled (eliminated or substantially reduced) when it is in the first position where it is in electrical contact with the more active first section 14. Electrically coupling the anodic material and the cathodic material with an electrolyte also produces an electrical potential that may also be used to power a downhole device, such as, for example, a device for downhole signaling or sensing.
[0027] Referring to FIG. 3 , the selectively corrodible article 10 may be used as disclosed herein, and more particularly may be used in accordance with a method 100 of removing a selectively corrodible downhole article 10. The method 100 includes disposing 110 downhole a selectively corrodible downhole article 10, as described herein. The method 100 also includes exposing 120 the selectively corrodible downhole article to a first wellbore fluid 72 while the movable cylindrical member is in the first position, wherein the first section is selectively dissolved. The method 100 further includes moving 130 the movable cylindrical member to the second position. The method 100 then includes exposing 140 the selectively corrodible metallic downhole article to a second wellbore 74 fluid, wherein the fixed member is selectively dissolved.
[0028] Disposing 110 the selectively corrodible downhole article 10 downhole may be accomplished in any suitable manner, including delivery downhole by use of a wireline, slickline, tubular string or the like. The movable cylindrical member 12 and fixed member 24 may be disposed downhole as individual components, or together as part of an assembly. Whether as part of the installation or afterwards, the movable cylindrical member 12 is placed in the first position 28 where the first section 14 is disposed on and in electrical contact with the fixed member 24.
[0029] Once the first section 14 is disposed on and in electrical contact with the fixed member 24, the method 100 also includes exposing 120 the selectively corrodible downhole article to a first wellbore fluid 72 while the movable cylindrical member is in the first position, wherein the first section is selectively dissolved. The first wellbore fluid 72 may include an aqueous or non-aqueous electrolyte, depending on the application and controllability of ambient conditions. In the downhole environment, controlling the ambient conditions to exclude moisture is not practical, and hence, under such conditions, the electrolyte is generally an aqueous electrolyte. Aqueous electrolytes may include water or a salt dissolved in water, such as a brine, or an acid, or a combination comprising at least one of the foregoing. Exposing 120 the selectively corrodible downhole article 10 to a first wellbore fluid 72 may include performing a downhole operation, such as a fracking, for example. During exposing 120, the movable cylindrical member 12 is in the first position 28 where the first section 14 is disposed on and in electrical contact with the fixed member 24. In the first position 28, the more galvanically active first material 18 of the first section 14 acts as an anode and is selectively dissolved or corroded while the less galvanically active intermediate material 26 of the fixed member 24 acts as a cathode and is selectively protected from dissolution or corrosion. The movable cylindrical member 12, particularly the first section 14, and the fixed member 24 may be designed for the wellbore operation for which they are to be used to provide sufficient material for the dissolution or corrosion that occurs during the downhole operation that is to be performed.
[0030] The method 100 further includes moving 130 the movable cylindrical member 12 to the second position 30. In the second position 30, the second section 16 is disposed on and in electrical contact with the fixed member 24. In the second position 30, the fixed member 24 is configured for selective dissolution because the intermediate material 26 is more galvanically active than the second material 20. In the second position 30, the more galvanically active intermediate material 26 of the fixed member 24 acts as an anode and is selectively dissolved or corroded while the less galvanically active second material 20 of the second section 16 acts as a cathode and is selectively protected from dissolution or corrosion. The fixed member 24 and intermediate material 26 may also be selected and designed for the wellbore operation for which they are to be used, such as to provide rapid dissolution or corrosion and removal from the wellbore 70. Removing the fixed member 24 may, for example, be used to open the wellbore for a subsequent wellbore operation, such as a completion or production operation.
[0031] The method 100 then includes exposing 140 the selectively corrodible metallic downhole article 10 to a second wellbore 74 fluid, wherein the fixed member 24 is selectively dissolved. This may also include the selective dissolution of other members, such as the ball 50 or plug 60, as described herein. The second wellbore fluid may be the same wellbore fluid as the first wellbore fluid 72. Alternately, the second wellbore fluid 74 and first wellbore fluid 72 may be different wellbore fluids.
[0032] All ranges disclosed herein are inclusive of the endpoints, and the endpoints are independently combinable with each other. The suffix “(s)” as used herein is intended to include both the singular and the plural of the term that it modifies, thereby including at least one of that term (e.g., the colorant(s) includes at least one colorants). “Optional” or “optionally” means that the subsequently described event or circumstance can or cannot occur, and that the description includes instances where the event occurs and instances where it does not. As used herein, “combination” is inclusive of blends, mixtures, alloys, reaction products, and the like. All references are incorporated herein by reference.
[0033] The use of the terms “a” and “an” and “the” and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should further be noted that the terms “first,” “second,” and the like herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The modifier “about” used in connection with a quantity is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the particular quantity).
[0034] While one or more embodiments have been shown and described, modifications and substitutions may be made thereto without departing from the spirit and scope of the invention. Accordingly, it is to be understood that the present invention has been described by way of illustrations and not limitation.
Claims
The invention claimed is:
1. A selectively corrodible downhole article, comprising:
a movable cylindrical member comprising a first section and an axially separated second section, the first section comprising a first material having a first galvanic activity, the second section comprising a second material having a second galvanic activity, the first galvanic activity being greater than the second galvanic activity, the first section being electrically isolated from the second section; and
a fixed member disposed on the cylindrical member and configured for electrical contact with the first section or the second section, the fixed member comprising an intermediate material having an intermediate galvanic activity, the intermediate galvanic activity being between the first galvanic activity and the second galvanic activity, the movable cylindrical member configured for movement from a first position where the first section is disposed on and in electrical contact with the fixed member and a second position where the second section is disposed on and in electrical contact with the fixed member, wherein in the first position, the first section is configured for selective dissolution, and wherein in the second position, the fixed member is configured for selective dissolution.
2. The article of claim 1, wherein the movable member comprises a movable tubular article.
3. The article of claim 1, wherein the movable member comprises a slidable sleeve disposed within a tubular article.
4. The article of claim 1, wherein the first material comprises magnesium.
5. The article of claim 1, wherein the second material comprises steel, tungsten, chromium, nickel, copper, cobalt, iron, or an alloy thereof, or a combination comprising at least one of the foregoing.
6. The article of claim 1, wherein the intermediate material comprises magnesium, aluminum, manganese or zinc, or an alloy thereof, or a combination comprising at least one of the foregoing.
7. The article of claim 1, wherein the first section comprises a controlled electrolytic material.
8. The article of claim 1, wherein the fixed member comprises a controlled electrolytic material.
9. The article of claim 1, wherein the fixed member comprises a ball or ball seat.
10. The article of claim 1, wherein the fixed member comprises a plug or plug seat.
11. The article of claim 1, wherein the movable member comprises a movable tubular article.
12. The article of claim 1, wherein the movable member comprises a slidable sleeve dispose on or within a tubular article.
13. The article of claim 1, wherein the first material comprises magnesium.
14. The article of claim 1, wherein the second material comprises steel, tungsten, chromium, nickel, copper, cobalt, iron, or an alloy thereof, or a combination comprising at least one of the foregoing.
15. The article of claim 1, wherein the intermediate material comprises magnesium, aluminum, manganese or zinc, or an alloy thereof, or a combination comprising at least one of the foregoing.
16. The article of claim 1, wherein the first section comprises a controlled electrolytic material.
17. The article of claim 1, wherein the fixed member comprises a controlled electrolytic material.
18. The article of claim 1, wherein the fixed member comprises a ball or ball seat.
19. The article of claim 1, wherein the fixed member comprises a plug or plug seat.
20. A method of removing a selectively corrodible downhole article, comprising:
disposing downhole a selectively corrodible downhole article, comprising: a movable cylindrical member comprising a first section and an axially separated second section, the first section comprising a first material having a first galvanic activity, the second section comprising a second material having a second galvanic activity, the first galvanic activity being greater than the second galvanic activity, the first section being electrically isolated from the second section; and a fixed member disposed on the cylindrical member and configured for electrical contact with the first section or the second section, the fixed member comprising an intermediate material having an intermediate galvanic activity, the intermediate galvanic activity being between the first galvanic activity and the second galvanic activity, the movable cylindrical member configured for movement from a first position where the first section is disposed on and in electrical contact with the fixed member and a second position where the second section is disposed on and in electrical contact with the fixed member, wherein in the first position, the first section is configured for selective dissolution, and wherein in the second position, the fixed member is configured for selective dissolution;
exposing the selectively corrodible downhole article to a first wellbore fluid while the movable cylindrical member is in the first position, wherein the first section is selectively dissolved;
moving the movable cylindrical member to the second position; and
exposing the selectively corrodible metallic downhole article to a second wellbore fluid, wherein the fixed member is selectively dissolved.
21. The method of claim 20, wherein the fixed member is selectively dissolved sufficiently to remove the fixed member from the selectively corrodible downhole article.
22. The method of claim 20, wherein the first wellbore fluid and the second wellbore fluid are the same fluid.
23. The method of claim 20, wherein the first wellbore fluid and the second wellbore fluid are different fluids.
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