US20140102726A1 - Controlled Swell-Rate Swellable Packer and Method - Google Patents

Controlled Swell-Rate Swellable Packer and Method Download PDF

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Publication number
US20140102726A1
US20140102726A1 US14/041,413 US201314041413A US2014102726A1 US 20140102726 A1 US20140102726 A1 US 20140102726A1 US 201314041413 A US201314041413 A US 201314041413A US 2014102726 A1 US2014102726 A1 US 2014102726A1
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United States
Prior art keywords
sealing element
rubber
rate
jacket
controlled swell
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Abandoned
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US14/041,413
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English (en)
Inventor
Pontus GAMSTEDT
Jens HINKE
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
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Priority to US14/041,413 priority Critical patent/US20140102726A1/en
Assigned to HALLIBURTON ENERGY SERVICES, INC. reassignment HALLIBURTON ENERGY SERVICES, INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: HINKE, JENS, SP GROUP A/S, GAMSTEDT, PONTUS
Publication of US20140102726A1 publication Critical patent/US20140102726A1/en
Abandoned legal-status Critical Current

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/1208—Packers; Plugs characterised by the construction of the sealing or packing means
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B05—SPRAYING OR ATOMISING IN GENERAL; APPLYING FLUENT MATERIALS TO SURFACES, IN GENERAL
    • B05D—PROCESSES FOR APPLYING FLUENT MATERIALS TO SURFACES, IN GENERAL
    • B05D1/00—Processes for applying liquids or other fluent materials
    • B05D1/36—Successively applying liquids or other fluent materials, e.g. without intermediate treatment
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B05—SPRAYING OR ATOMISING IN GENERAL; APPLYING FLUENT MATERIALS TO SURFACES, IN GENERAL
    • B05D—PROCESSES FOR APPLYING FLUENT MATERIALS TO SURFACES, IN GENERAL
    • B05D7/00—Processes, other than flocking, specially adapted for applying liquids or other fluent materials to particular surfaces or for applying particular liquids or other fluent materials
    • B05D7/50—Multilayers
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/127—Packers; Plugs with inflatable sleeve
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like

Definitions

  • Hydrocarbons are commonly produced from hydrocarbon-bearing portions of a subterranean formation via a wellbore penetrating the formation.
  • a casing or liner is conventionally disposed within the wellbore and may be secured against the formation with cement which may be displaced into the annular space between the casing or liner and the wellbore.
  • Packers may also be utilized to secure a casing string within a wellbore.
  • conventionally-available packers do not allow for such packer to be placed at a desired location within a wellbore. As such, improved packers are needed.
  • Disclosed herein is a controlled swell-rate swellable packer.
  • Also disclosed herein is a method of making a controlled swell-rate swellable packer, comprising providing a mandrel having at least one sealing element disposed about at least a portion thereof, masking at least a portion of the otherwise exposed portions of the sealing element, applying a jacket to the sealing element, and removing the mask, thereby yielding a controlled swell-rate swellable packer.
  • a method of utilizing a controlled swell-rate swellable packer comprising providing a controlled swell-rate swellable packer, disposing a tubular string having the controlled swell-rate swellable packer incorporated therein within a wellbore, and activating the controlled swell-rate swellable packer.
  • a controlled swell-rate swellable packer comprises a mandrel, a sealing element, and a jacket.
  • the sealing element is disposed about at least a portion of the mandrel, and the jacket covers at least a portion of an outer surface of the sealing element.
  • the jacket comprises a substantially impermeable material with respect to a swelling agent that is configured to cause the sealing element to swell.
  • the mandrel may comprise a tubular body generally defining a continuous axial flowbore.
  • the sealing element may comprises a swellable material, and the swellable material may comprise a water-swellable material, an oil-swellable material, or any combination thereof
  • the swellable material may comprise a compound selected from the group consisting of: a natural rubber, an acrylate butadiene rubber, a polyacrylate rubber, an isoprene rubber, a choloroprene rubber, a butyl rubber (IIR), a brominated butyl rubber (BIIR), a chlorinated butyl rubber (CIIR), a chlorinated polyethylene (CM/CPE), a neoprene rubber (CR), a styrene butadiene copolymer rubber (SBR), a sulphonated polyethylene (CSM), ethylene acrylate rubber (EAM/AEM), an epichlorohydrin ethylene oxide copolymer (CO, ECO), an ethylene-propylene rubber (EPM and EDPM), an ethylene-propy
  • a method of making a controlled swell-rate swellable packer comprises providing a mandrel having at least one sealing element disposed about at least a portion thereof, masking at least a portion of any exposed portions of the sealing element with a mask, applying a jacket to the sealing element, removing the mask, and providing a controlled swell-rate swellable packer.
  • the mask may be configured to cover a portion of the sealing element.
  • the mask may comprise at least one of a grid-like pattern, a diamond pattern, or a random pattern.
  • the mask may be formed from at least one of paper, plastic, wires, metals, a fibrous material, or any combination thereof
  • Applying the jacket to the sealing element may comprise at least one of spraying a liquideous or substantially liquideous material onto the sealing element, painting a liquideous or substantially liquideous material onto the sealing element, or dipping the sealing element into a liquideous or substantially liquideous material.
  • the method may also include drying the jacket before removing the mask.
  • a method of utilizing a controlled swell-rate swellable packer comprises providing a controlled swell-rate swellable packer, disposing a tubular string having the controlled swell-rate swellable packer incorporated therein within a wellbore, and activating the controlled swell-rate swellable packer.
  • the controlled swell-rate swellable packer comprises a sealing element and a jacket. The jacket is disposed on a first portion of an outer surface of the sealing element, and a second portion of the outer surface of the sealing element is uncovered.
  • the controlled swell-rate swellable packer may further comprise a mandrel, and the sealing element may be disposed circumferentially about at least a portion of the mandrel.
  • the sealing element may comprise a swellable material.
  • Activating the controlled-rate swellable packer may comprises contacting at least a portion of the controlled swell-rate packer with a swelling agent.
  • the swelling agent may comprise a water-based fluid, an oil-based fluid, or any combination thereof Contacting at least the portion of the controlled swell-rate packer with the swelling agent may comprise contacting the second portion of the outer surface of the sealing element with the swelling agent, and Contacting at least the portion of the controlled swell-rate packer with the swelling agent may comprise contacting the second portion of the outer surface of the sealing element with the swelling agent for at least 2 days.
  • FIG. 1 is partial cut-away view of an embodiment of an environment in which a controlled swell-rate swellable packer may be employed;
  • FIG. 2 is a cutaway view of an embodiment of a controlled swell-rate swellable packer
  • FIG. 3 is a perspective view of an embodiment of a controlled swell-rate swellable packer
  • FIG. 4 is a view of an embodiment of a mask which may be utilized in the manufacture of a controlled swell-rate swellable packer.
  • FIGS. 5-8 demonstrate examples associated with the controlled swell-rate swellable packer, as will be disclosed herein.
  • connection Unless otherwise specified, use of the terms “connect,” “engage,” “couple,” “attach,” or any other like term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described.
  • subterranean formation shall be construed as encompassing both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.
  • the operating environment generally comprises a wellbore 114 that penetrates a subterranean formation 102 for the purpose of recovering hydrocarbons, storing hydrocarbons, disposing of carbon dioxide, or the like.
  • the wellbore 114 may be drilled into the subterranean formation 102 using any suitable drilling technique.
  • a drilling or servicing rig 106 comprises a derrick 108 with a rig floor 110 through which a tubular string (e.g., a drill string, a tool string, a segmented tubing string, a jointed tubing string, a casing string, or any other suitable conveyance, or combinations thereof) generally defining an axial flowbore may be positioned within or partially within the wellbore.
  • a tubular string e.g., a drill string, a tool string, a segmented tubing string, a jointed tubing string, a casing string, or any other suitable conveyance, or combinations thereof
  • the tubular string may comprise two or more concentrically positioned strings of pipe or tubing (e.g., a first work string may be positioned within a second work string).
  • the drilling or servicing rig 106 may be conventional and may comprise a motor driven winch and other associated equipment for lowering the tubular string into the wellbore 114 .
  • a mobile workover rig, a wellbore servicing unit e.g., coiled tubing units
  • FIG. 1 depicts a stationary drilling rig 106
  • mobile workover rigs, wellbore servicing units such as coiled tubing units
  • wellbore servicing units such as coiled tubing units
  • the wellbore 114 may extend substantially vertically away from the earth's surface over a vertical wellbore portion, or may deviate at any angle from the earth's surface 104 over a deviated or horizontal wellbore portion. In alternative operating environments, portions or substantially all of the wellbore 114 may be vertical, deviated, horizontal, and/or curved.
  • At least a portion of the wellbore 114 is lined with a casing string and/or liner 120 defining an axial flowbore 121 .
  • at least a portion of the casing string 120 is secured into position against the formation 102 via a plurality of CSSPs 200 (e.g., a first CSSP 200 a, a second CSSP 200 b, a third CSSP 200 c, and a fourth CSSP 200 d ).
  • a plurality of CSSPs 200 e.g., a first CSSP 200 a, a second CSSP 200 b, a third CSSP 200 c, and a fourth CSSP 200 d .
  • at least a portion of the casing string 120 being partially secured into position against the formation 102 in a conventional manner with cement.
  • a CSSP like CSSP 200 as will be disclosed herein, may be similarly incorporated within (and similarly utilized to secure) any suitably tubular string.
  • a tubular string include, but are not limited to, a work string, a jointed pipe string, a coiled tubing string, a production tubing string, a drill string, the like, or combinations thereof.
  • the casing string 120 may further have incorporated therein at least one wellbore servicing tool (WST) 300 (e.g., a first WST 300 a, a second WST 300 b, a third WST 300 c, and a fourth WST 300 d ).
  • WST wellbore servicing tool
  • one or more of the WSTs 300 may comprise an actuatable stimulation assembly, which may be configured for the performance of a wellbore servicing operation, particularly, a stimulation operation such as a perforating operation, a fracturing operation, an acidizing operation, or combinations thereof.
  • the mandrel 210 is a generally cylindrical or tubular-like structure.
  • the mandrel 210 may comprise a unitary structure, alternatively, two or more operably connected components.
  • a mandrel may comprise any suitable structure; such suitable structures will be appreciated by those of skill in the art with the aid of this disclosure.
  • the sealing element 220 may generally be configured to selectively seal and/or isolate two or more portions of an annular space surrounding the CSSP 200 (e.g., between the CSSP 200 and one or more walls of the wellbore 114 ), for example, by selectively providing a barrier extending circumferentially around at least a portion of the exterior of the CSSP 200 .
  • the sealing element 220 may generally comprise a cylindrical structure having an interior bore (e.g., a tube-like and/or a ring-like structure).
  • the sealing element 220 may comprise a suitable interior diameter, a suitable external diameter, and/or a suitable thickness, for example, as may be selected by one of skill in the upon viewing this disclosure and in consideration of factors including, but not limited to, the size/diameter of the mandrel 210 , the against which the sealing element is configured to engage, the force with which the sealing elements is configured to engage such surface(s), or other related factors. While the embodiment of FIG. 1 illustrates a CSSP 200 comprising a single sealing element 220 , one of skill in the art, upon viewing this disclosure, will appreciate that a similar CSSP may comprise two, three, four, five, or any other suitable number of sealing elements like sealing element 220 .
  • the sealing element 220 may be configured to exhibit a radial expansion (e.g., an increase in exterior diameter) upon being contacted with a selected fluid, that is, a swelling agent.
  • a radial expansion e.g., an increase in exterior diameter
  • swellable materials generally refer to any elastomer that swells upon contact with the swelling agent.
  • the swellable material may be characterized as a resilient, volume changing material.
  • a variety of swellable materials may be utilized in accordance with the present disclosure, including, but not limited to, those that swell upon contact with an oleaginous fluid and/or an aqueous fluid, such as water.
  • Swellable materials suitable for use in the present invention may generally swell by up to approximately 500% of their original size at the surface.
  • Suitable elastomers that swell when in contact with aqueous fluid include, but are not limited to, nitrile rubbers (NBR), hydrogenated nitrile rubbers (HNBR, HNS), fluoro rubbers (FKM), perfluoro rubbers (FFKM), tetrafluorethylene/propylene (TFE/P), starch-polyacrylate acid graft copolymers, polyvinyl alcoholcyclic acid anhydride graft copolymers, isobutylene maleic anhydride, acrylic acid type polymers, vinylacetate-acrylate copolymer, polyethylene oxide polymers, carboxymethyl cellulose type polymers, starch-polyacrylonitrile graft copolymers and the like, polymethacrylate, polyacrylamide, non-soluble acrylic polymers, and highly swelling clay minerals such as sodium bentonite (having as main ingredient montmorillonite).
  • NBR nitrile rubbers
  • HNBR hydrogenated nitrile rubbers
  • swellable materials that behave in a similar fashion with respect to oleaginous fluids or aqueous fluids also may be suitable.
  • Suitable swellable materials are commercially available as Swellpackers from Halliburton Energy Services, Inc. in Houston, Tex.
  • the swellable elastomers may be any shape or size, including, but not limited to, spherical, fiber-like, ovoid, ribbons, etc. In some embodiments, the swellable elastomers may be particles ranging in size from about 0.1 ⁇ m to about 2000 ⁇ m. Other examples of suitable swellable elastomers that may be used in the methods of the present invention are disclosed in U.S. Application Publication No. 2004/0261990, which is incorporated in its entirety herein by reference.
  • the jacket may cover about 75%, alternatively, about 80%, alternatively, about 81%, alternatively, about 82%, alternatively, about 83%, alternatively, about 84%, alternatively, about 85%, alternatively, about 86%, alternatively, about 87%, alternatively, about 88%, alternatively, about 89%, alternatively, about 90%, alternatively, about 91%, alternatively, about 92%, alternatively, about 93%, alternatively, about 94%, alternatively, about 95% of the otherwise exposed surface area of the sealing element 220 may be covered (e.g., fluidicly sealed) by the jacket 230 .
  • the exposed and unexposed surfaces of the sealing element 220 may be obtained by “masking” or otherwise covering a portion of the sealing element 220 (e.g., the portion of the sealing element which will be exposed) prior to application of the jacket 230 material.
  • a “mask” may be configured to cover any suitable portion of the sealing element.
  • the mask may comprise a grid-like pattern, a diamond pattern, a random arrangement.
  • the mask may be made from any suitable material, examples of which include, but are not limited to, paper, plastic, wires, metals, various fibrous materials, or combinations thereof.
  • CSSP 200 disclosed herein
  • methods related to making/assembling and utilizing such a CSSP are also disclosed herein.
  • the mandrel 210 having at least one sealing element 220 disposed about at least a portion thereof may be obtained.
  • suitable mandrels 210 and sealing elements 220 may be obtained, alone or in combination, from Halliburton Energy Services, Inc. in Houston, Tex.
  • the jacket 230 may be applied to the masked sealing element 230 .
  • the material comprising the jacket 230 may be sprayed onto the sealing element 220 , alternatively, the material comprising the jacket 230 may be painted or brushed onto the sealing element 220 , alternatively, the sealing element 220 may be dipped, rolled, or submerged within the material comprising the jacket 230 .
  • the sealing element 220 is coated with the material which will form the jacket 230 , the jacket 230 material may adhere to the portions of the sealing element not covered or shrouded by the mask 250 .
  • a method of utilizing a CSSP generally comprises the steps of providing a CSSP 200 , disposing a tubular string having a CSSP 200 incorporated therein within a wellbore, and activating the CSSP 200 . Additionally, in an embodiment, the method may further comprise performing a wellbore servicing operation, producing a reservoir fluid, or combinations thereof.
  • the CSSP 200 may be incorporated within a tubular string (e.g., a casing string like casing string 120 , a work string, a production string, a drill string, or any other suitable wellbore tubular) and disposed within a wellbore.
  • a tubular string may comprise two, three, four, five, six, seven, eight, nine, ten, or more CSSPs incorporated therein.
  • the CSSP(s) 200 may be incorporated as the tubular string is “run into” the wellbore (e.g., wellbore 114 ).
  • the tubular string is “run into” the wellbore (e.g., wellbore 114 ).
  • the tubular strings are conventionally assembled in “joints” which are added to the uppermost end of the string as the string is run in.
  • the tubular string (e.g., casing string 120 ) may be assembled and run into the wellbore 114 until the CSSP(s) are located at a predetermined location, for example, such that a given CSSP (when expanded) will isolated two adjacent zones of the formation (e.g., formation zones 2, 4, 6, and 8) and/or portions of the wellbore 114 .
  • the CSSPs may be activated, that is, caused to expand.
  • activating the CSSP(s) may comprise contacting the CSSP with swelling agent.
  • the swelling agent may comprise any suitable fluid, for example, an oleaginous fluid, an aqueous fluid, or combinations thereof
  • the swelling agent may comprise a fluid already present within the wellbore 114 , for example, a servicing fluid, a formation fluid (e.g., a hydrocarbon), or combinations thereof
  • the swelling agent may be introduced into the wellbore 114 .
  • contact with the swelling agent may cause the sealing element to expand into contact with the formation (e.g., with the walls of the wellbore 114 ).
  • the expansion of the sealing element may be effective to isolate two or more portions of an annular space extending generally between the tubing string and the walls of the wellbore.
  • the expansion of the sealing element 220 may occur at a controlled rate, as disclosed herein.
  • the expansion of the sealing element 220 may occur over a predetermined duration, for example, about 4 days, alternatively, about 6 days, alternatively, about 8 days, alternatively, about 10 days, alternatively, about 12 days, alternatively, about 14 days, alternatively, about 16 days, alternatively, about 18 days, alternatively, about 20 days, alternatively, about 22 days, alternatively, about 24 days.
  • a wellbore servicing operation may be performed with respect to one or more of such formation zones.
  • the wellbore servicing operation may include any suitable servicing operation as will be appreciated by one of skill in the art upon viewing this disclosure. Examples of such wellbore servicing operations include, but are not limited to, a fracturing operation, a perforating operation, an acidizing operation, or combinations thereof.
  • a formation fluid e.g., oil, gas, or both
  • a formation fluid may be produced from the subterranean formation or one or more zones thereof.
  • FIG. 5 demonstrates the swell rates of various swellable materials (swellable barriers/sealing elements), some of which are uncoated, and some of which are coated with various products and in various patterns.
  • swellable barriers/sealing elements various swellable materials
  • the uncoated barriers exhibited expansion in the shortest amount of time, while coated barriers generally exhibited longer times to expand.
  • FIGS. 6A , 6 B, and 6 C demonstrate a swellable materials (e.g., barrier) partially coated with Accoflex P572B, as can been seen from the mesh-like pattern surrounding the barrier, as disclosed herein.
  • a swellable materials e.g., barrier
  • FIG. 7 demonstrates a comparison between (moving left to right) a coated swellable material, a partially coated swellable material (e.g., as can be seen from the grid-like pattern, as disclosed herein), and an uncoated swellable material.
  • the coated swellable material exhibited the greatest expansion while the uncoated swellable material exhibited the least expansion, while the partially coated exhibited an intermediate proportion of expansion.
  • FIG. 8 demonstrates the swellrates of various swellable materials (swellable barriers/sealing elements), some of which are uncoated, and some of which are coated in various patterns amounts. Generally, more coating applied to the swellable materials yields slower rates of expansion (e.g., in terms of percent weight gain).
  • a controlled swell-rate swellable packer comprises a mandrel; a sealing element, wherein the sealing element is disposed about at least a portion of the mandrel; and a jacket, wherein the jacket covers at least a portion of an outer surface of the sealing element, and wherein the jacket comprises a substantially impermeable material with respect to a swelling agent that is configured to cause the sealing element to swell.
  • a second embodiment comprises the controlled swell-rate swellable packer of the first embodiment, wherein the mandrel comprises a tubular body generally defining a continuous axial flowbore.
  • a third embodiment comprises the controlled swell-rate swellable packer of the first or second embodiment, wherein the sealing element comprises a swellable material.
  • a fourth embodiment comprises the controlled swell-rate swellable packer of the third embodiment, wherein the swellable material comprises a water-swellable material, an oil-swellable material, or any combination thereof.
  • a fifth embodiment comprises the controlled swell-rate swellable packer of the third embodiment, wherein the swellable material comprises a compound selected from the group consisting of: a natural rubber, an acrylate butadiene rubber, a polyacrylate rubber, an isoprene rubber, a choloroprene rubber, a butyl rubber (IIR), a brominated butyl rubber (BIIR), a chlorinated butyl rubber (CIIR), a chlorinated polyethylene (CM/CPE), a neoprene rubber (CR), a styrene butadiene copolymer rubber (SBR), a sulphonated polyethylene (CSM), ethylene acrylate rubber (EAM/AEM), an epichlorohydrin ethylene oxide copolymer (CO, ECO), an ethylene-propylene rubber (EPM and EDPM), an ethylene-propylene-diene terpolymer rubber (EPT), an ethylene vinyl acetate cop
  • a sixth embodiment comprises the controlled swell-rate swellable packer of the third embodiment, wherein the swellable material comprises a water-swellable material, and wherein the swellable material comprises a compound selected from the group consisting of: a nitrile rubber (NBR), a hydrogenated nitrile rubber (HNBR, HNS), a fluoro rubber (FKM), a perfluoro rubber (FFKM), tetrafluorethylene/propylene (TFE/P), a starch-polyacrylate acid graft copolymer, a polyvinyl alcoholcyclic acid anhydride graft copolymer, isobutylene maleic anhydride, an acrylic acid type polymer, a vinylacetate-acrylate copolymer, a polyethylene oxide polymer, a carboxymethyl cellulose type polymer, a starch-polyacrylonitrile graft copolymer, polymethacrylate, polyacrylamide, a non-soluble acrylic polymer,
  • a seventh embodiment comprises the controlled swell-rate swellable packer of any of the third to sixth embodiments, wherein the swellable material is characterized by a particle size of from about 0.1 microns to about 2000 microns.
  • An eighth embodiment comprises the controlled swell-rate swellable packer of any of the first to seventh embodiments, wherein the jacket covers at least about 75% of the outer surface of the sealing element.
  • a ninth embodiment comprises the controlled swell-rate swellable packer of any of the first to eighth embodiments, wherein the jacket comprises a fluoro-elastomer, a plastic, polyethylene, polypropylene, or combinations thereof.
  • a method of making a controlled swell-rate swellable packer comprises providing a mandrel having at least one sealing element disposed about at least a portion thereof; masking at least a portion of any exposed portions of the sealing element with a mask; applying a jacket to the sealing element; removing the mask; and providing a controlled swell-rate swellable packer.
  • An eleventh embodiment comprises the method of the tenth embodiment, wherein the mask is configured to cover a portion of the sealing element.
  • a twelfth embodiment comprises the method of the tenth or eleventh embodiment, wherein the mask comprises at least one of a grid-like pattern, a diamond pattern, or a random pattern.
  • a thirteenth embodiment comprises the method of any of the tenth to twelfth embodiments, wherein the mask is formed from at least one of paper, plastic, wires, metals, a fibrous material, or any combination thereof.
  • a fourteenth embodiment comprises the method of any of the tenth to thirteenth embodiments, wherein applying the jacket to the sealing element comprises at least one of spraying a liquideous or substantially liquideous material onto the sealing element, painting a liquideous or substantially liquideous material onto the sealing element, or dipping the sealing element into a liquideous or substantially liquideous material.
  • a fifteenth embodiment comprises the method of any of the tenth to fourteenth embodiments, further comprising drying the jacket before removing the mask.
  • a method of utilizing a controlled swell-rate swellable packer comprises providing a controlled swell-rate swellable packer, wherein the controlled swell-rate swellable packer comprises a sealing element and a jacket, wherein the jacket is disposed on a first portion of an outer surface of the sealing element, and wherein a second portion of the outer surface of the sealing element is uncovered; disposing a tubular string having the controlled swell-rate swellable packer incorporated therein within a wellbore; and activating the controlled swell-rate swellable packer.
  • a seventeenth embodiment comprises the method of the sixteenth embodiment, wherein the controlled swell-rate swellable packer further comprises a mandrel, wherein the sealing element is disposed circumferentially about at least a portion of the mandrel.
  • An eighteenth embodiment comprises the method of the sixteenth or seventeenth embodiment, wherein the sealing element comprises a swellable material.
  • a nineteenth embodiment comprises the method of any of the sixteenth to eighteenth embodiments, wherein activating the controlled-rate swellable packer comprises contacting at least a portion of the controlled swell-rate packer with a swelling agent.
  • a twentieth embodiment comprises the method of the nineteenth embodiment, wherein the swelling agent comprises a water-based fluid, an oil-based fluid, or any combination thereof.
  • a twenty first embodiment comprises the method of the nineteenth or twentieth embodiment, wherein contacting at least the portion of the controlled swell-rate packer with the swelling agent comprises contacting the second portion of the outer surface of the sealing element with the swelling agent.
  • a twenty second embodiment comprises the method of the nineteenth or twentieth embodiment, wherein contacting at least the portion of the controlled swell-rate packer with the swelling agent comprises contacting the second portion of the outer surface of the sealing element with the swelling agent for at least 2 days.
  • R 1 a numerical range with a lower limit, R 1 , and an upper limit, R u , any number falling within the range is specifically disclosed.
  • R R 1 +k*(R u ⁇ R 1 ), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent.
  • any numerical range defined by two R numbers as defined in the above is also specifically disclosed.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Physics & Mathematics (AREA)
  • Wood Science & Technology (AREA)
  • Sealing Material Composition (AREA)
  • Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
  • Materials For Medical Uses (AREA)
  • Compositions Of Macromolecular Compounds (AREA)
  • Treatments For Attaching Organic Compounds To Fibrous Goods (AREA)
  • Gasket Seals (AREA)
  • Extrusion Moulding Of Plastics Or The Like (AREA)
US14/041,413 2012-10-16 2013-09-30 Controlled Swell-Rate Swellable Packer and Method Abandoned US20140102726A1 (en)

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AU2013331694A1 (en) 2015-04-09
CN104755698B (zh) 2017-11-21
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CN104755698A (zh) 2015-07-01
CA2888532A1 (en) 2014-04-24
DK2909433T3 (en) 2020-03-30
EP2909433A1 (en) 2015-08-26
US20180291701A1 (en) 2018-10-11
WO2014062391A1 (en) 2014-04-24
MX357806B (es) 2018-07-25
US9869152B2 (en) 2018-01-16
US10012051B2 (en) 2018-07-03
US20140102728A1 (en) 2014-04-17
US20180100371A1 (en) 2018-04-12
CA2988943C (en) 2019-06-04
EP2909433B1 (en) 2020-03-11
BR112015008405B1 (pt) 2021-03-16
IN2015DN02454A (cg-RX-API-DMAC7.html) 2015-09-04
CA2888532C (en) 2018-01-30
RU2623411C2 (ru) 2017-06-26
CA2988943A1 (en) 2014-04-24
US10443340B2 (en) 2019-10-15
RU2015112674A (ru) 2016-12-10
MX2015004748A (es) 2015-10-12
EP2909433A4 (en) 2016-06-22
MY172691A (en) 2019-12-10

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