DOWNWELL SYSTEM WITH ACTIVATABLE SWELLABLE PACKER

Abstract

A packer system for a wellbore includes a tubular member and a packer element having an inner layer that circumferentially overlies the tubular member and an outer layer that circumferentially overlies the inner layer. The inner layer includes an elastomer that swells upon contact with a swelling fluid. The outer layer includes a material that provides at least a partial barrier to the swelling fluid.

Description

FIELD OF THE INVENTION

The present invention relates generally to a wellbore system for oil exploration, and more particularly to a packer for a wellbore system.

BACKGROUND OF THE INVENTION

A downhole wellbore system typically includes a pipe or other tubular structure that extends into a borehole drilled into the ground. In some instances, a casing is inserted into the wellbore to define its outer surface; in other instances, the rock or soil itself serves as the wall of the wellbore.

Many wellbore systems include a packer, which is designed to expand radially outwardly from the pipe against the walls of the wellbore. The packer is intended to seal segments of the pipe against the wellbore in order to isolate some sections of the wellbore from others. For example, it may be desirable to isolate a section of the formation that includes recoverable petroleum product from an aquifer.

Known sealing members for packers include, for example, mechanical packers which are arranged in the borehole to seal an annular space between a wellbore casing and a production pipe extending into the borehole. Such a packer is radially deformable between a retracted position, in which the packer is lowered into the borehole, and an expanded position, in which the packer forms a seal. Activation of the packer can be by mechanical or hydraulic means. One limitation of the applicability of such packers is that the seal surfaces typically need to be well defined, and therefore their use may be limited to wellbores with casings. Also, they can be somewhat complicated and intricate in their construction and operation. An exemplary mechanical packer arrangement is discussed in U.S. Pat. No. 7,070,001 to Whanger et al., the disclosure of which is hereby incorporated herein in its entirety.

Another type of annular seal member is formed by a layer of cement arranged in an annular space between a wellbore casing and the borehole wall. Although in general cement provides adequate sealing capability, there are some inherent drawbacks such as shrinking of the cement during hardening, which can result in de-bonding of the cement sheath, or cracking of the cement layer after hardening.

Additional annular seal members for packers have been formed of swellable elastomers. These elastomers expand radially when exposed to an activating liquid, such as water (often saline) or hydrocarbon, that is present in the wellbore. Exemplary materials that swell in hydrocarbons include ethylene propylene rubber (EPM and EPDM), ethylene-propylene-diene terpolymer rubber (EPT), butyl rubber, brominated butyl rubber, chlorinated butyl rubber), chlorinated polyethylene, neoprene rubber, styrene butadiene copolymer rubber (SBR), sulphonated polyethylene, ethylene acrylate rubber, epichlorohydrin ethylene oxide copolymer, silicone rubbers and fluorsilicone rubber. Exemplary materials that swell in water include starch-polyacrylate acid graft copolymer, polyvinyl alcohol cyclic acid anhydride graft copolymer, isobutylene maleic anhydride, acrylic acid type polymers, vinylacetate-acrylate copolymer, polyethylene oxide polymers, carboxymethyl cellulose type polymers, starch-polyacrylonitrile graft copolymers and the like and highly swelling clay minerals such as sodium bentonite. Exemplary swellable packers are discussed in U.S. Pat. No. 7,059,415 to Bosma et al. and U.S. Patent Publication No. 2007/0056735 to Bosma et al., the disclosure of each of which is hereby incorporated herein in its entirety.

With packers that employ swellable systems, it can be difficult to control the timing and/or rate of expansion. As such, it may be desirable to provide a packer system in which a swellable packer is time-controlled.

SUMMARY OF THE INVENTION

As a first aspect, embodiments of the present invention are directed to a packer system for a wellbore. The system comprises a tubular member and a packer element having an inner layer that circumferentially overlies the tubular member and an outer layer that circumferentially overlies the inner layer. The inner layer comprises an elastomer that swells upon contact with a swelling fluid. The outer layer comprises a material that provides at least a partial barrier to the swelling fluid.

In some embodiments, the outer layer comprises a material that is impermeable to water and hydrocarbon, but is removable with a non-naturally occurring fluid, such as an acid with a pH of less than 5.0. In some embodiments, the outer layer comprises a material that is partially permeable to at least one of water or hydrocarbon. In other embodiments, the outer layer comprises a material that degrades when contacted with at least one of water or hydrocarbon.

As a second aspect, embodiments of the present invention are directed to a packer system for a wellbore, comprising: a tubular member; a packer element having an inner layer that circumferentially overlies the tubular member and an outer layer that circumferentially overlies the inner layer; and centralizing end caps. The inner layer comprises an elastomer that swells upon contact with a swelling fluid. The outer layer comprises a material that provides at least a partial barrier to the swelling fluid. The end caps are mounted to the tubular member adjacent opposite ends of the packer element. The end caps can protect the outer layer as the packer system is lowered into and positioned within the wellbore.

As a third aspect, embodiments of the present invention are directed to a method of isolating a first section of a wellbore from a second section. The method commences with the step of providing a packer system having a tubular member and a packer element. The packer element includes an inner layer that circumferentially overlies the tubular member and an outer layer that circumferentially overlies the inner layer. The inner layer comprises an elastomer that swells upon contact with a swelling fluid, and the outer layer comprises a material that provides at least a partial barrier to the swelling fluid. The method further includes the steps of positioning the packer system in a wellbore, penetrating the outer layer to enable the inner layer to contact the swelling fluid, and permitting the inner layer to swell sufficiently to contact walls of the wellbore, thereby isolating at least the first section of the wellbore from the second section of the wellbore.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a partial section view of a downwell bore and pipe with a packer system according to embodiments of the present invention.

FIG. 2 is an enlarged section view of one end of the packer system of FIG. 1.

FIG. 3 is a partial section view of the packer system of FIG. 1 being lowered into place in the wellbore.

FIG. 4 is a partial section view of the pipe and packer system of FIG. 1 showing the wellbore being filled with an activating fluid.

FIG. 5 is a partial section view of the pipe and packer system of FIG. 1 showing the protective layer of the packer system dissolving in the activating fluid.

FIG. 6 is a partial section of the pipe and packer system of FIG. 1 showing the inner layer of the packing system in a swelled condition, thereby sealing against the wellbore walls.

DETAILED DESCRIPTION OF EMBODIMENTS OF THE INVENTION

The present invention will now be described more fully hereinafter, in which preferred embodiments of the invention are shown. This invention may, however, be embodied in different forms and should not be construed as limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the invention to those skilled in the art. In the drawings, like numbers refer to like elements throughout. Thicknesses and dimensions of some components may be exaggerated for clarity.

Unless otherwise defined, all terms (including technical and scientific terms) used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs. It will be further understood that terms, such as those defined in commonly used dictionaries, should be interpreted as having a meaning that is consistent with their meaning in the context of the relevant art and will not be interpreted in an idealized or overly formal sense unless expressly so defined herein.

The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used herein, the singular forms “a”, “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “comprises” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof. As used herein the expression “and/or” includes any and all combinations of one or more of the associated listed items.

In addition, spatially relative terms, such as “under”, “below”, “lower”, “over”, “upper” and the like, may be used herein for ease of description to describe one element or feature's relationship to another element(s) or feature(s) as illustrated in the figures. It will be understood that the spatially relative terms are intended to encompass different orientations of the device in use or operation in addition to the orientation depicted in the figures. For example, if the device in the figures is turned over, elements described as “under” or “beneath” other elements or features would then be oriented “over” the other elements or features. Thus, the exemplary term “under” can encompass both an orientation of over and under. The device may be otherwise oriented (rotated 90 degrees or at other orientations) and the spatially relative descriptors used herein interpreted accordingly.

Well-known functions or constructions may not be described in detail for brevity and/or clarity.

Turning now to the figures, a downwell pipe assembly, designated broadly at 20, is shown in FIG. 1. The assembly 20 is inserted into a wellbore 10, which is defined by walls in the earth. Although shown here disposed directly into the ground, in some embodiments the assembly 20 may be disposed within a casing or other annular member that is inserted in the earth. In addition, the wellbore 10 is illustrated herein as being substantially vertical, but may also be substantially horizontally disposed or disposed at any angle typically used for wells. As used herein, the term “wellbore” is intended to encompass either of these scenarios.

The assembly 10 includes a base pipe 22, which can be any pipe or tubular member typically employed in downwell environments, and a packer system 21. The packer system 21 includes one or more packer elements 26 (only one is shown herein) and two centralizing end caps 24, 25 (also known as “centralizers”). The packer element 26 includes both an inner layer 28 and an outer layer 30 (see FIG. 2).

The inner layer 28 is annular and circumferentially overlies the base pipe 22. The inner layer 28 is formed of a swellable material (typically a swellable elastomer) that swells in the presence of a swelling fluid. Typical swelling fluids include water and hydrocarbons, particularly in the form of crude oil. Exemplary elastomeric materials that swell in hydrocarbons include ethylene propylene rubber (EPM and EPDM), ethylene-propylene-diene terpolymer rubber (EPT), butyl rubber, brominated butyl rubber, chlorinated butyl rubber), chlorinated polyethylene, neoprene rubber, styrene butadiene copolymer rubber (SBR), sulphonated polyethylene, ethylene acrylate rubber, epichlorohydrin ethylene oxide copolymer, silicone rubbers and fluorsilicone rubber. Exemplary elastomeric materials that swell in water include starch-polyacrylate acid graft copolymer, polyvinyl alcohol cyclic acid anhydride graft copolymer, isobutylene maleic anhydride, acrylic acid type polymers, vinylacetate-acrylate copolymer, polyethylene oxide polymers, carboxymethyl cellulose type polymers, starch-polyacrylonitrile graft copolymers and the like. In some embodiments, swelling agents, such as low molecular weight polymers like polyethylene, may be included.

A swellable elastomer may also include fillers and additives that enhance its manufacturing or performance properties and/or reduce its costs. Exemplary filler materials include inorganic oxides such as aluminum oxide (Al₂O₃), silicon dioxide (SiO₂), magnesium oxide (MgO), calcium oxide (CaO), zinc oxide (ZnO) and titanium dioxide (TiO₂), carbon black (also known as furnace black), silicates such as clays, talc, wollastonite (CaSiO₃), magnesium silicate (MgSiO₃), anhydrous aluminum silicate, and feldspar (KAlSi₃O₈), sulfates such as barium sulfate and calcium sulfate, metallic powders such as aluminum, iron, copper, stainless steel, or nickel, carbonates such as calcium carbonate (CaCo₃) and magnesium carbonate (MgCo₃), mica, silica (natural, fumed, hydrated, anhydrous or precipitated), and nitrides and carbides, such as silicon carbide (SiC) and aluminum nitride (AlN). These fillers may be present in virtually any form, such as powder, pellet, fiber or sphere. Exemplary additives include polymerization initiators, activators and accelerators, curing or vulcanizing agents, plasticizers, heat stabilizers, antioxidants and antiozonants, coupling agents, pigments, and the like, that can facilitate processing and enhance physical properties.

The outer layer 30 circumferentially overlies the inner layer 28. The outer layer 30 is formed of a material that provides at a least partially barrier to at least one of water and hydrocarbons. The material of the outer layer 30 is also removable from the inner layer through one or more processes, as described below.

As one example, the outer layer 30 may be soluble in a fluid (such as an acid having a pH of 5.0 or less) that does not occur naturally in the wellbore 10. In such a case, the outer layer 30 may be formed of an organic coating such as acrylics, vinyl esters, polyesters, amine-formaldehyde condensates, phenolics, polycarbonates, alkyds, epoxies, polyurethanes, rubbers, silicones, polyvinyl chlorides, thermoplastics, waxes, starches, cellulosics, and other natural polymers. Inorganic coatings such as oxides, phosphates, and silicates may also be used. The activating fluid may be an aqueous solution. The solution contains an activating ingredient, such as an acid or base. Exemplary acids include mineral acids like hydrochloric or sulfuric acid and organic acids such as acetic or citric acid. Exemplary bases (typically strong bases) include sodium or potassium hydroxide. The activating fluid may also be hydrocarbon based, e.g. hydrocarbons typically used in drilling fluids. Crude oil or any available hydrocarbon may be used. Aliphatic or aromatic hydrocarbons can be used. This arrangement may be especially useful for a water-swellable packer, inasmuch as the packer can be activated with a hydrocarbon, the hydrocarbon pumped out of the wellbore, and the packer then allowed to swell in water.

As another example, the outer layer 30 may be partially permeable in water or hydrocarbon, such that exposure of the swellable elastomer of the inner layer 28 is delayed and limited by the presence of the outer layer 30. The thickness of the outer layer 30 can determine the time lapse between exposure to the fluid and the swelling of the inner layer 28.

As yet another example, the outer layer 30 may be degradable simply by exposure to the environment of the wellbore (e.g., air, water or hydrocarbon may degrade the outer layer 30). Turning again to FIG. 2, the centralizers 24, 25 (only the centralizer 24 is shown in FIG. 2) are attached to the base pipe 22 at either end of the packer element 24. The centralizers 24, 25 have a greater diameter (shown as D1 in FIG. 2) than the outer diameter (shown as D2 in FIG. 2) of the outer layer 30. The centralizers may be formed of any rigid material, with a composite polymeric material (such as epoxy reinforced with glass) being particularly suitable. It also may be advantageous for the centralizers 24, 25 to be formed of a material with a relatively low coefficient of friction to facilitate the installation of the assembly 20.

The outer layer 30 may be applied to the inner layer 28 by various methods. The outer layer 30 may be applied as a coating in liquid form by a carrier. The outer layer 30 may be built up in layers by applying several coats thereof. The outer layer 30 may be applied by a brush or roller, or sprayed onto the inner layer. The carrier may be water- or solvent-based. The carrier may be evaporated to form the coating, leaving a film on the swellable inner layer 30. The coating may also be cured by heat.

Alternatively, the outer layer 30 may be extruded onto the inner layer 28. Rubber or thermoplastic material can be heated and applied to the inner layer 28. The outer layer 30 can then be tooled or ground to a desired thickness that could affect its solubility in the activating fluid.

As another alternative, the outer layer 30 can be a sleeve that is pulled or wrapped onto the inner layer 28. The sleeve 30 would form a protective film on the inner layer 28 that could be dissolved by the activating fluid. The sleeve may be conformable so that it would protect the inner layer, and in some embodiments may be heat-shrinkable.

As still another alternative, the outer layer 30 may be cast onto the inner layer 28. Various thermosetting resins may be cast to form a coating on the inner layer 28. The chemistry of the resin may be varied to change the solubility of the coating in the activating fluid. The resins would be cured to form the coating and bond to the inner layer 28. The outer layer 30 can then be tooled or ground to a desired thickness that could affect its solubility in the activating fluid.

Active ingredients and fillers may be mixed into the outer layer 30 that can change the solubility of the outer layer 30 towards the dissolving fluid. Mineral fillers that are soluble in acids or bases may be used to cause the outer layer 30 to disintegrate upon exposure to the activating fluid. Examples of minerals or salts that are soluble in acidic solutions are calcium carbonate or calcium oxide. Examples of minerals or salts that are soluble in basic solutions are various oxides and phosphates such as magnesium oxide.

Turning now to FIGS. 3-6, an exemplary sequence of the installation and utilization of the packer system 21 is shown. After formation of the assembly 20 off-site, the assembly 20 is lowered into a wellbore 10. For predominantly vertical wellbores, the packer system 21 is typically located near the lower end of a long pipe that includes the base pipe 22; in a conventional vertical installation, segments of pipe (including the base pipe 22 with the packer system 21) are lowered sequentially into the wellbore 10 and attached (often via threaded ends) to form a long pipe. Installation of the pipe segments may be accompanied by drilling fluids such as drilling mud. The presence of the outer layer 30 can prevent or inhibit swelling of the inner layer 28 of the packer element 26 as the packer element is exposed to water, crude oil, drilling mud and the like.

Also, the presence of the centralizers 24, 25, which extend radially outwardly beyond the outer diameter D2 of the outer layer 30, can protect the outer layer 30 from damage as assembly 20 is lowered into the wellbore 10. Many wellbores are not straight, but include some deviations from side to side that the segments of pipe, including the assembly 20, must negotiate during installation. The centralizers 24, 25 can prevent the outer layer 30 from striking the side walls of the wellbore 10 and suffering damage from such contact. Also, if the centralizers 24, 25 have a relatively low coefficient of friction, they can facilitate the lowering of the assembly 20 into place by reducing friction when the centralizers 24, 25 contact the walls of the wellbore 10.

Turning now to FIG. 4, once the system 20 is in position in the wellbore 10, the outer layer 30 can be removed. FIG. 4 illustrates the introduction of an activating fluid (such as an acid having a pH of 5.0 or lower) that erodes or dissolves the outer layer 30. Typically, the activating fluid is introduced until its level in the wellbore reaches a certain depth (e.g., the earth's surface) to ensure that the packing element 26 is immersed in the activating fluid.

As illustrated in FIG. 5, the activating fluid dissolves or erodes the outer layer 30. After a certain duration, another fluid, such as drilling mud or water, may be introduced into the wellbore to flush out the activation fluid; this fluid may then cause the now-exposed inner layer to swell (FIG. 6). Alternatively, the activating fluid itself may cause swelling of the inner layer 28, or a fluid present in the wellbore (such as water or crude oil) may cause swelling of the inner layer 28. In any of these instances, the outer layer 30 is penetrated to allow a swelling fluid to contact the inner layer. Upon such contact, the inner layer 28 swells sufficiently to press against the side walls of the wellbore 10, thereby isolating the portion of the wellbore 10 located above the packing element 26 from the portion of the wellbore below the packing element 26.

The foregoing is illustrative of the present invention and is not to be construed as limiting thereof. Although exemplary embodiments of this invention have been described, those skilled in the art will readily appreciate that many modifications are possible in the exemplary embodiments without materially departing from the novel teachings and advantages of this invention. Accordingly, all such modifications are intended to be included within the scope of this invention as defined in the claims. The invention is defined by the following claims, with equivalents of the claims to be included therein.

Claims

1. A packer system for a wellbore, comprising: a tubular member; anda packer element having an inner layer that circumferentially overlies the tubular member and an outer layer that circumferentially overlies the inner layer;wherein the inner layer comprises an elastomer that swells upon contact with a swelling fluid; andwherein the outer layer comprises a material that provides at least a partial barrier to the swelling fluid.

2. The packer system defined in claim 1, wherein the outer layer comprises a material that is substantially impermeable to the swelling fluid, and is dissolvable in an non-naturally occurring activation fluid.

3. The packer system defined in claim 2, wherein the material of the outer layer is dissolvable in acid having a pH of less than about 5.0.

4. The packer system defined in claim 2, wherein the outer layer comprises an organic coating.

5. The packer system defined in claim 2, wherein the outer layer comprises an inorganic coating.

6. The packer system defined in claim 2, wherein the material of the outer layer is dissolvable in a base.

7. The packer system defined in claim 1, wherein the outer layer comprises a material that is partially permeable to the swelling fluid.

8. The packer system defined in claim 1, wherein the outer layer comprises a material that is degradable in water or hydrocarbon.

9. The packer system defined in claim 1, wherein the elastomer of the inner layer comprises a rubber material.

10. The packer system defined in claim 1, wherein the elastomer of the inner layer comprises EPDM.

11. The packer system defined in claim 1, further comprising centralizing end caps fixed to the tubular member and mounted adjacent opposed axial ends of the packer element.

12. The packer system defined in claim 11, wherein the end caps have a first radius, the outer layer has a second radius, and the first radius is greater than the second radius.

13. The packer system defined in claim 11, wherein the end caps comprise a polymer composite material.

14. A packer system for a wellbore, comprising: a tubular member; anda packer element having an inner layer that circumferentially overlies the tubular member and an outer layer that circumferentially overlies the inner layer;wherein the inner layer comprises an elastomer that swells upon contact with a swelling fluid; andwherein the outer layer comprises a material that provides at least a partial barrier to the swelling fluid; andcentralizing end caps mounted to the tubular member adjacent opposite ends of the packer element.

15. The packer system defined in claim 14, wherein the end caps have a first radius, the outer layer has a second radius, and the first radius is greater than the second radius.

16. The packer system defined in claim 14, wherein the end caps comprise a polymer composite material.

17. A method of isolating a first section of a wellbore from a second section, comprising: providing a packer system having a tubular member and a packer element, the packer element including an inner layer that circumferentially overlies the tubular member and an outer layer that circumferentially overlies the inner layer, the inner layer comprising an elastomer that swells upon contact with a swelling fluid, the outer layer comprising a material that provides at least a partial barrier to the swelling fluid;positioning the packer system in a wellbore;penetrating the outer layer to enable the inner layer to contact the swelling fluid; andpermitting the inner layer to swell sufficiently to contact walls of the wellbore, thereby isolating at least the first section of the wellbore from the second section of the wellbore.

18. The method defined in claim 17, wherein the step of penetrating the outer layer comprises removing the outer layer.

19. The method defined in claim 18, wherein the step of removing the outer layer comprises dissolving the outer layer with a non-naturally occurring fluid.

20. The method defined in claim 18, wherein the non-naturally occurring fluid comprises an acid having a pH of less than about 5.0.

21. The method defined in claim 18, wherein the step of removing the outer layer comprises removing the outer layer with one of water and hydrocarbon present in the wellbore.

22. The method defined in claim 17, wherein the outer layer is partially permeable to the swelling fluid, and wherein the step of penetrating the outer layer comprises passing the swelling fluid through the outer layer.