Title:
DOWNWELL SYSTEM WITH DIFFERENTIALLY SWELLABLE PACKER
Kind Code:
A1


Abstract:
A packer assembly comprises a tubular member and a packer system that circumferentially overlies the tubular member. The packer system includes end portions and a central portion disposed between the end portions. The central portion and the end portions are formed of material that swells when contacted with a swelling fluid. The central and end portions are constructed to swell upon contact with the swelling fluid so that the central portion swells to a diameter defined by a wall of the wellbore more rapidly than the end portions. In such a configuration, the central portion of the packer system can be fully swollen prior to the full swelling of the end portions.



Inventors:
Gustafson, Eric J. (Stevens City, VA, US)
Butterfield, William S. (Stevens City, VA, US)
Williamson, Peter (Schriesheim, DE)
Application Number:
12/366756
Publication Date:
08/20/2009
Filing Date:
02/06/2009
Primary Class:
International Classes:
E21B33/12; E21B33/127
View Patent Images:
Related US Applications:



Primary Examiner:
COY, NICOLE A
Attorney, Agent or Firm:
MYERS BIGEL, P.A. (RALEIGH, NC, US)
Claims:
That which is claimed is:

1. A packer assembly for a wellbore, comprising: a tubular member; and a packer system that circumferentially overlies the tubular member, the packer system including end portions and a central portion disposed between the end portions; wherein the central portion and the end portions are formed of material that swells when contacted with a swelling fluid; and wherein the central and end portions are constructed to swell upon contact with the swelling fluid so that the central portion swells to a diameter defined by a wall of the wellbore more rapidly than the end portions.

2. The packer assembly defined in claim 1, wherein the central portion is formed of a different material than the end portions.

3. The packer assembly defined in claim 2, wherein the central portion includes separation caps located at axial ends of the central portion that encourage swelling of the central portion in a radial direction.

4. The packer assembly defined in claim 3, wherein the separation caps include apertures located to permit swelling fluid to contact the axial ends of the central portion.

5. The packer assembly defined in claim 2, wherein the central portion abuts a portion of the packer system formed of material that swells when contacted with a swelling fluid.

6. The packer assembly defined in claim 4, wherein the central portion abuts an intermediate portion that is sandwiched between the central portion and one of the end portions.

7. The packer assembly defined in claim 2, wherein the central portion comprises EPDM and a swelling agent.

8. The packer assembly defined in claim 6, wherein the end portion comprises EPDM.

9. The packer assembly defined in claim 1, wherein the central portion and the end portions are part of a unitary packer member.

10. The packer assembly defined in claim 8, wherein the central portion has an outer diameter that is greater than an outer diameter of the end portions.

11. The packer assembly defined in claim 9, wherein the unitary packer member is tapered from the central portion to the end portions.

12. The packer assembly defined in claim 8, wherein the central portion and the end portions comprise the same material.

13. A packer assembly for a wellbore, comprising: a tubular member; and a packer system that circumferentially overlies the tubular member, the packer system including end portions and a central portion disposed between the end portions; wherein the central portion and the end portions are formed of material that swells when contacted with a swelling fluid; and wherein the central portion is formed of a first material, the end portions are formed of a second, different material, and the first material swells more rapidly in the swelling fluid than the second material.

14. The packer assembly defined in claim 13, wherein the packer assembly is gapless between the central portion and the end portions.

15. The packer assembly defined in claim 13, wherein at least one gap is present between the central portion and each end portion, and wherein a separation cap is mounted on axial ends of the central portion.

16. The packer assembly defined in claim 15, wherein each of the separation caps includes apertures located to permit swelling fluid to contact the axial ends of the central portion.

17. The packer assembly defined in claim 13, wherein the first material comprises EPDM and a swelling agent.

18. The packer assembly defined in claim 17, wherein the second material comprises EPDM.

19. A packer assembly for a wellbore, comprising: a tubular member; and a packer system that circumferentially overlies the tubular member, the packer system including end portions and a central portion disposed between the end portions; wherein the central portion and the end portions are formed of material that swells when contacted with a swelling fluid; and wherein the central portion has a first diameter and the end portions have a second diameter that is less than the first diameter.

20. The packer assembly defined in claim 19, wherein the central portion and the end portions are part of a unitary packer member.

21. The packer assembly defined in claim 20, wherein the packer member is tapered from the central portion to the end portions.

22. The packer assembly defined in claim 19, wherein the central portion and the end portions comprise the same material.

Description:

RELATED APPLICATION

The present application claims priority from U.S. Provisional Patent Application Ser. No. 61/028,940, filed Feb. 15, 2008, the disclosure of which is hereby incorporated herein in its entirety.

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.

Although swellable systems are relatively inexpensive and simple, it can be difficult to control the timing of expansion of different sections of the packer. For example, if the ends of the packer seal prior to the center, it may be difficult or impossible for swelling fluid to reach the center portion of the packer. In such instances, swelling of the center portion of the packer may decrease or cease entirely. Incomplete swelling of the central portions of the packer can cause a delay in time to full set and/or a reduced capability to seal differential pressures. As such, it may be desirable to provide a packer system in which this shortcoming can be addressed.

SUMMARY OF THE INVENTION

As a first aspect, embodiments of the present invention are directed to a packer assembly for a wellbore. The packer assembly comprises a tubular member and a packer system that circumferentially overlies the tubular member. The packer system includes end portions and a central portion disposed between the end portions. The central portion and the end portions are formed of material that swells when contacted with a swelling fluid. The central and end portions are constructed to swell upon contact with the swelling fluid so that the central portion swells to a diameter defined by a wall of the wellbore more rapidly than the end portions. In such a configuration, the central portion of the packer system can be fully swollen prior to the full swelling of the end portions.

As a second aspect, embodiments of the present invention are directed to a packer assembly for a wellbore comprising a tubular member and a packer system that circumferentially overlies the tubular member. The packer system includes end portions and a central portion disposed between the end portions. The central portion and the end portions are formed of material that swells when contacted with a swelling fluid. The central portion is formed of a first material, the end portions are formed of a second, different material, and the first material swells more rapidly in the swelling fluid than the second material.

As a third aspect, embodiments of the present invention are directed to a packer assembly for a wellbore comprising a tubular member and a packer system that circumferentially overlies the tubular member. The packer system includes end portions and a central portion disposed between the end portions. The central portion and the end portions are formed of material that swells when contacted with a swelling fluid. The central portion has a first diameter and the end portions have a second diameter that is less than the first diameter.

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, with the packing elements of the packer system in an unswelled condition.

FIG. 2 is a partial section view of the packer system of FIG. 1, with the center section experiencing partial swelling.

FIG. 3 is a partial section view of the packer system of FIG. 1, with the center section experiencing pronounced swelling and the intermediate sections experiencing partial swelling.

FIG. 4 is a partial section view of the packer system of FIG. 1, with the center and intermediate sections experiencing pronounced swelling and the end sections experiencing partial swelling.

FIG. 5 is a partial section view of the packer system of FIG. 1, with all sections experiencing pronounced swelling.

FIG. 6 is a partial section view of a packer system according to alternative embodiments of the present invention, wherein individual sections of the packer system are separated by separating caps.

FIG. 7 is a top view of an exemplary end cap of the packer system of FIG. 6.

FIG. 8 is a partial section view of a packer system according to additional embodiments of the present invention.

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 tubing 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.

A packer system 30 is mounted to a segment of a base tubing 22. The packer system 30 includes a plurality of packer elements: in the illustrated embodiment, the system 30 includes a center element 32, two intermediate elements 34 that sandwich the center element 32, and two end elements 36 that sandwich the intermediate elements 34. In the illustrated embodiment, the elements 32, 34, 36 abut each other; however, in some embodiments gaps may exist between some or all of the elements.

The elements 32, 34, 36 are formed of a material, typically an elastomer, that swells when contacted with a swelling fluid. Most common swelling fluids include water and hydrocarbons. The elements 32, 34, 36 thus typically comprise materials that are selected for their ability to swell when in contact with water or hydrocarbon, depending on the projected location of the packer system 30 within the wellbore 10. 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.

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 swelling elastomer may also include a swelling agent. In some embodiments, the swelling agent may be a sorbent for hydrocarbon. The hydrocarbon swelling agent can be a component that causes the packer material to swell when in contact with hydrocarbon. In some embodiments, the swelling agent may be a sorbent for hydrocarbon. Also, in some embodiments the swelling agent may comprise polyethylene (particularly linear polyethylene) and/or other polymers, which may be combined with a hydrocarbon wax or the like. Other suitable swelling agents include thermoplastic polymer and copolymer mixtures and polyalphaolefins.

The materials of the elements 32, 34, 36 are selected and/or formulated to have different swelling rates, with the center element 32 swelling the most rapidly, the end elements 36 swelling the slowest, and the intermediate elements 34 swelling at a rate that falls between those of the center and end elements 32, 36. By selecting the materials of the elements 32, 34, 36 in this manner, upon contact with the swelling fluid, the center section 32 will swell most rapidly, and will therefore fill and seal against the walls of the wellbore 10 before the intermediate and end elements do so. The intermediate elements 34 then swells and seals next, followed by the end elements 36.

The sequence can be best understood by reference to FIGS. 1-5. In FIG. 1, the elements 32, 34, 36 have not been exposed to the swelling fluid, so none of the elements 32, 34, 36 have begun to swell. Upon contact with the swelling fluid, the center element 32 swells more rapidly than the intermediate or end elements 34, 36 (FIG. 2). Thus, the center element 32 swells sufficiently to contact and seal against the walls of the wellbore 10 before the intermediate and end sections 34, 36 (FIG. 3). Continued exposure to the swelling fluid causes the intermediate elements 34 to next contact and seal against the walls of the wellbore 10 (FIG. 4), which is then followed by the sealing of the end elements 36 against the walls of the wellbore 10 (FIG. 5).

With an arrangement such as that described above, in which the more central elements swell more quickly than the endmost elements, the end elements 36 do not seal against the walls of the wellbore 10 prior to the complete swelling and sealing of the center elements 32. As such, the risk of the ends sealing and preventing the activating fluid from contacting the center before it has swollen is reduced.

As an example, each of the center, intermediate and end elements 32, 34, 36 may comprise a blend of EPDM and HNBR, with the center element 32 comprising 100 parts of a swelling agent to each 100 parts of EPDM/HNBR, the intermediate elements 34 comprising 75 parts of swelling agent to each 100 parts of EPDM/HNBR, and the end elements comprising 50 parts of swelling agent to each 100 parts of EPDM/HNBR.

Another packer system, designated broadly at 130, is illustrated in FIGS. 6 and 7. In this embodiment, the elements 132, 134, 136 are formed of materials with different swelling rates in the same manner as the elements 32, 34, 36 described above in connection with the system 30 shown in FIGS. 1-5. However, in the system 130 the elements 132, 134, 136 do not abut each other, but instead are spaced apart from each other, and their end surfaces are covered with separation caps 133, 135, 137. The separation caps 133, 135, 137 prevent the elements 132, 134, 136 from swelling in an axial direction, which thereby forces the elements 132, 134, 136 to swell more in the radial direction. As shown in FIG. 7, each of the separation caps 133, 135, 137 includes multiple apertures 137a that permit swelling fluid to contact the end surfaces of the elements 132, 134, 136, which contact encourages more rapid swelling.

Another packer system, illustrated broadly at 230, is illustrated in FIG. 8. In this embodiment, the system 230 comprises a single element 232 formed of a single material, but the element 232 is tapered, such that it has a thicker central portion 233 and narrower ends 234. Thus, when the element 232 is contacted with a swelling fluid, the central portion 233 and the end portions 234 both swell, but the central portion 234 contacts and seals against the walls of the wellbore 10 before the end portions 233 can, even though the axial end surfaces of the end portions 233 may be exposed to swelling fluid also.

Those skilled in this art will appreciate that other embodiments may also be suitable. For example, the packer system 230 may comprise multiple distinct elements of different diameters rather than a single tapered element, or a single element may have a “stepped” profile with sections of different diameters rather than being tapered. Also, if multiple distinct elements are employed, the materials of each may vary, such that the system includes central elements that are not only thicker than the end elements, but also swell more rapidly. As another alternative, a coating over the packer elements that breaks down once the packer system is positioned in the wellbore may be employed, with such coating being thicker on the end elements (and, therefore, slower to break down) than on the center elements. Of course, the numbers of elements may also vary depending on the environment of use.

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.