US20130008671A1 - Wellbore plug and method - Google Patents

Wellbore plug and method Download PDF

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US20130008671A1
US20130008671A1 US13/530,897 US201213530897A US2013008671A1 US 20130008671 A1 US20130008671 A1 US 20130008671A1 US 201213530897 A US201213530897 A US 201213530897A US 2013008671 A1 US2013008671 A1 US 2013008671A1
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mandrel
plug
wellbore
slip
lower
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US13/530,897
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John F. Booth
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Booth John F
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    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00Sealing or packing boreholes or wells
    • E21B33/10Sealing or packing boreholes or wells in the borehole
    • E21B33/12Packers; Plugs
    • E21B33/128Packers; Plugs with a member expanded radially by axial pressure
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00Sealing or packing boreholes or wells
    • E21B33/10Sealing or packing boreholes or wells in the borehole
    • E21B33/12Packers; Plugs
    • E21B33/1208Packers; Plugs characterised by the construction of the sealing or packing means
    • E21B33/1216Anti-extrusion means, e.g. means to prevent cold flow of rubber packing

Abstract

Disclosed is a wellbore plug having a design that allows the mandrel of the plug to be made of concrete or other easy-to-drill materials. Disclosed is a wellbore plug assembly with slip and packing assemblies configured to hold the plug in place during setting and use without tensioning the mandrel, thereby allowing the mandrel to be made from easily drillable material, such as concrete.

Description

    CROSS REFERENCE TO RELATED APPLICATIONS
  • This application claims priority from U.S. Provisional Patent Application No. 61/505,195, filed Jul. 7, 2011, entitled “Wellbore Plug and Method,” which is hereby incorporated by reference in its entity.
  • BACKGROUND Technical Field
  • These inventions relate generally to methods and apparatus for drilling and completing subterranean wells and, more particularly, drillable wellbore plugs designed to have mandrels made of concrete or other easy-to-drill materials or shapes.
  • In the drilling of wells and in mining applications, it is necessary to temporarily isolate sections of a wellbore. For example, a common method sets a plurality of plugs to isolate and successively treat sections of the wellbore. As used herein, the term “plug” is used to refer to bridge plugs, packers, frac plugs, cementing shoes, squeeze plugs and the like utilized at subterranean wellbore locations. This isolation method has been accomplished using “drillable wellbore plugs,” i.e., plugs that are set in the wellbore at subterranean locations to control flow in the wellbore and subsequently are broken up into small pieces with a cutting tool, such as a bit, mill or the like to reopen the wellbore. As used herein, the direction “up” when used with respect to the wellbore refers to the direction along the wellbore toward the wellhead without regard to the orientation of the wellbore without respect to gravitational directions. The term “down” is used to refer to the direction along the wellbore away from the wellhead. In the attached figures, the upper ends (the end closest along the wellbore to the wellhead) of the illustrated plug embodiments are orientated at the top of the drawings.
  • Halliburton Energy Services, Inc., Baker Hughes, Inc., BJ Services Company and Weatherford International, Inc. each have manufactured and used wellbore plugs with mandrels and other components made from plastic materials. Plugs with mandrels and other components made in whole or part from non-metallic plastic materials are easier to drill out of the wellbore than plugs made from metallic materials. The description of suitable plastic materials is described in the patents listed below. These companies have patented and disclosed various aspects of these plugs. See U.S. Pat. Nos. 5,224,540; 5,271,468; 5,390,737; 5,540,279; 5,701,959; 6,491,108; 6,578,633; 6,708,768; 6,708,770; 6,712,153; 6,167,963; and 6,769,491, which are incorporated herein by reference for all purposes.
  • While these patented wellbore plugs have some structural differences, they all utilize mandrels made from high-strength plastic material and use the “double-slip” arrangement which has a slip above the packing element and an opposed slip below the element. The article by E. E. Smart, entitled “How To Select The Right Packer For The Job” in the July 1978 issue of Petroleum Engineering International, describes various downhole wellbore plug configurations. The “double-slip” configuration is identified in the article as “Type Six.” As used herein, the term “double-slip” type wellbore plug refers to a self supporting plug for installation to restrict or control flow through the wellbore. The double-slip type plug comprises a mandrel with a packing assembly positioned on the mandrel between upper and lower opposed slip assemblies and wherein a lower slip support in the form of a radial extending surface is positioned to contact the lower slips. “Double-slip” type wellbore plugs include: packers, bridge plugs, frac plugs and the like.
  • The mandrel in these double-slip plugs forms the structural backbone or frame on which the other plug components are supported. The mandrel constitutes the major portion of the plug that must be successfully drilled out. As used herein, the term “mandrel” is used to refer to an elongated at least partially tubular member. It is anticipated that an interior sleeve made of metallic or nonmetallic material (such as shown in FIG. 25 of U.S. Pat. No. 6,708,768) can be positioned in the mandrel to provide a lining for the mandrel's bore. The term “mandrel” does not include any interior sleeves or plugs. As used herein, the term “mandrel” can include a tubular member having cylindrical outer surfaces or non-cylindrical outer surfaces (such as that illustrated in the FIGS. 13A and, 14-17 of U.S. Pat. No. 6,491,108). Also, as used herein, a mandrel can have a generally uniform cross section along its length (such as that illustrated in the FIG. 1 of U.S. Pat. No. 5,701,959) and can have a larger cross section portion, such as the lower sleeve member (such as that illustrated in the FIG. 5 of U.S. Pat. No. 5,701,959). The term “mandrel” as used herein, does not include exterior structures or attachments, such as the lower sleeve member, without regard to whether not the sleeve is attached or integrally formed with the mandrel.
  • As used herein, “slip assemblies” refer to a plurality of slips located around the mandrel between an annular wedge and an annular shoulder comprising a slip support. The annular wedge can have a cone-shaped exterior surface or can have flat surfaces on its exterior. The slip support can be a shoulder on at a sleeve mounted or integrally formed on the mandrel or on the setting tool. The plurality of slips can be made separate (as shown in the FIG. 2B of U.S. Pat. No. 5,540,279) or joined together initially (as shown in the FIG. 12 of U.S. Pat. No. 5,224,540) to break apart and separate upon being set. The slips can have teeth integrally formed in the slip or inserts for engaging the wellbore. The opposed slip assemblies function, when set, to engage or grip the wellbore to hold a deformable packing assembly axially compressed to close or seal the space between the mandrel and the wellbore wall. As used herein, the term “packing assembly” refers to one or more annular deformable members or “packing elements” which when axially compressed deform radially. A packing assembly may include, but not necessarily include, shoes, extrusion limiters and the like.
  • In a process called “setting,” the plug is connected to a “setting tool,” and lowered into the well, and forces are applied to the components of the plug. Breakable setting rods attached to the mandrel (U.S. Pat. No. 6,708,768), shear sleeves attached to the mandrel (U.S. Pat. No. 5,224,540), shear pins penetrating the mandrel, and deformable disks pressing against the lower end of the mandrel (United States Patent Application Publication Number 2007/051722) have been proposed as “releasable means” to releasably attach the mandrel to the setting tool. In the conventional prior art setting process, the setting tool pulls the upper end of the mandrel upward in an axial direction while pushing the slip assemblies toward each other to axially compress the packing assembly and to axially move and radially deform the packing element(s) to engage and seal off the wellbore around the plug's mandrel. As used herein “axial force” is a forces applied to the mandrel in direction parallel to the axis of the mandrel's bore. Axial forces are to be distinguished from radial forces, such as those applied transverse to the axis. During the setting process in prior art plugs, axial forces applied to the mandrel create tension and shear stresses in the mandrel and as the packing and slip assemblies are compressed, forces tending to collapse the mandrel are applied to the outer surface of the mandrel. During setting, the mandrel is subjected to the combined stresses caused by the compression forces of the packing and slip assemblies and tension and axial forces applied to the mandrel by the setting tool.
  • The forces applied to the plug as it is set vary with plug design and wellbore size and downhole pressure conditions. For purposes of description, the forces applied to and stresses experienced by the plug during setting will be identified as “setting” forces and stresses. In some instances, more thousands of pounds of tension force is applied to the mandrel during setting. Typically, the setting tool utilizes releasable means such as frangible setting sleeves (U.S. Pat. No. 5,271,468), setting studs (U.S. Pat. No. 6,708,768), shear pins (U.S. Pat. No. 5,271,468), and the like to separate the plug from the setting tool when the desired setting force has been applied. After the plug is set, the setting forces applied to the plug during the setting process are discontinued. After setting, the packing assembly is held compressed by the slip assemblies, engaging the wellbore wall. The slips transfer these “holding” forces to the casing wall. “Holding” forces and stresses are used to refer to forces applied to and stresses experienced by the plug after the plug is set. The double-slip configuration is sometimes called “the floating mandrel configuration,” because, once set, the setting tension on the mandrel is removed and the mandrel is designed to slide back and forth through the packing assembly and slip assemblies. In contrast, the mandrels in non double-slip plugs, such as those illustrated in the FIG. 3 of U.S. Pat. No. 6,581,681 the holding force is carried by the mandrel, and the mandrel remains in tension after the plug is set.
  • While conventional plugs are in use or held in place, differential pressures across the plug can induce tension and compressive stresses in the mandrel. For example, when pressure from below is applied to a set plug of the type illustrated in the FIG. 8 of U.S. Pat. No. 5,271,468, the mandrel will float up against the lower slip support, placing the mandrel in tension. The pressure will be transferred to the packing element which will cause compressive stress in the mandrel.
  • Plugs of the double-slip configuration have a disadvantage of requiring substantially higher setting forces than the other configurations of plugs, and therefore the plugs' components, in particular the mandrel, experience substantially higher internal tension stresses during setting. The need for substantially higher setting forces is due, in part, to the fact that during setting of the opposed slip, assemblies must be dragged together along the casing wall to compress the packing assemblies. This requirement of higher setting forces is well known in the industry, e.g., The Western Company's 1987 U.S. Pat. No. 4,708,202.
  • To accommodate the high stresses encountered by the mandrel during the setting and use, these prior art nonmetallic plugs use mandrels with relatively thick walls. For example, see Halliburton Energy Company's U.S. Pat. No. 5,271,468. In some cases, metallic, tubular members are inserted into the interior of the mandrel, e.g., BJ Services Company's U.S. Pat. No. 6,708,768 issued Mar. 23, 2004.
  • These prior art non-metallic mandrels are required to be made from relatively thick walled high-strength plastic materials, such as composites, to withstand the tension stresses imposed upon the mandrel during setting. While mandrels made from high-strength plastic materials are easier to drill out than mandrels made from metallic materials, problems have been experienced in the drilling out of these mandrels. As used here in “drilling out” has the classic meaning of breaking a plug up into pieces by contacting it with rotating tools having cutting edges, such as a bit or mill.
  • Once set in the wellbore and a pressure differential is present, the typical dual slip plug's mandrel, experiences tension stresses caused by the holding forces. For example, if the mandrels passageway is closed, tension forces may be applied to the mandrel due to pressure differentials.
  • SUMMARY OF THE INVENTION
  • The present invention provides a drillable, downhole wellbore tool with mandrels made from easy-to-drill materials such as concrete. The present invention provides a tool design and setting method that substantially reduces if not eliminates the tension stresses imposed on the plug's mandrel during setting and when in use which, in turn, permits the wellbore plug's mandrel to be made of concrete or other easy-to-drill materials.
  • According to a feature of the present invention, a double-slip configuration plug design, setting tool and setting method are provided which uses a setting rod connected to the mandrel near the bottom end of the tool (the end opposite from the setting the tool). During the setting method, force is applied to the mandrel through the setting rod which substantially eliminates tension in the mandrel during the setting procedures. When this invention is embodied in a frac plug, the top of the mandrel is closed off by a flapper valve or ball drop check valve which eliminates tension forces on the mandrel when pressure is applied across the tool. When the invention is embodied in a packer or bridge plug embodiment, the mandrel is closed off at both the top and bottom by check valves to eliminate tension in the mandrel. These designs substantially eliminate the application of tension and shear forces to the mandrel during the setting process and during use. This permits mandrels to be made with smaller cross section designs and from materials that need not have relatively high strengths in tension. Examples of suitable mandrel materials include cementitious materials, such as concrete, plastics, sintered materials and the like.
  • As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. The term “concrete” is used to refer to a properly proportioned mixture of hydraulic cement and one or more of the following: water, aggregate and chemical or mineral additives. The term “wellbore” refers to the drilled hole, including any cased or uncased portions of the well. The “borehole” usually refers to the inside wellbore wall, that is, the rock face or wall that bounds the drilled hole. A wellbore can have portions that are vertical, horizontal, or anything in between, and it can have portions that are straight, curved, or branched. Directional terms, when used herein in reference to tools or the wellbores, such as “above,” “below,” “up,” “down,” ‘upper,” “lower,” “up hole,” “down hole,” “top”, “bottom” and similar terms are relative terms used to indicate a direction along or position in the wellbore with respect to the wellhead, regardless of whether the tool or wellbore portion is vertical, horizontal or the orientation of gravity.
  • BRIEF DESCRIPTION OF THE DRAWINGS
  • The drawings are incorporated into and form a part of the specification to illustrate at least one embodiment and example of the present inventions. Together with the written description, the drawings serve to illustrate and explain the principles of the invention. The drawing figures are only for the purpose of illustrating at least one preferred example of at least one embodiment of the invention and are not to be construed as limiting the invention to only the illustrated and described example or examples. The various inherent advantages and features of the various embodiments of the present invention are apparent from a consideration of the drawings in which:
  • FIG. 1 is a longitudinal section view of a frac plug type wellbore plug of the present inventions, having a cement mandrel, illustrated attached to a setting tool;
  • FIG. 2 is a longitudinal sectional view on the frac plug type wellbore plug of FIG. 1, illustrated set in a wellbore at a subterranean location;
  • FIG. 3 is a partial sectional view of a bridge plug type wellbore plug, having a plastic mandrel according to the present inventions; and
  • FIG. 4 is a partial sectional view of another embodiment of a bridge plug type wellbore plug, having a sintered metal mandrel, according to the present inventions.
  • DETAILED DESCRIPTION OF THE INVENTION
  • Referring now to the drawings wherein like reference characters designate like or corresponding parts throughout the several views, there is shown in FIG. 1 an embodiment of an improved double-slip type wellbore plug assembly 10 according to the present inventions. The plug embodiment selected for use in describing the present inventions comprises what is known in the industry as a frac plug. As will be described in detail, the frac plug, once set in the wellbore, permits hydrocarbon production flow along the wellbore upward through the plug, while preventing frac fluids pumped into the well to flow in a downward or downhole direction. For purposes of description, plug assembly 10 is illustrated in the figures with the upper end of the plug 28 orientated toward the top of the drawing page and lower end of the plug 26 toward the bottom of the page. It is to be understood that the embodiment selected for use as an example is not intended to limit the inventions to the selected configuration.
  • Plug assembly 10, illustrated in FIG. 1, comprises a tubular-shaped mandrel 12. In this embodiment the mandrel is made from cement material. Although the tubular-shaped mandrel illustrated in FIG. 1 has a cylindrical exterior surface, it is envisioned that the mandrel could assume other shapes, for example, it could have flats on its exterior to minimize rotation of the exterior components during drill out. In this embodiment, a thin wall inner sleeve 14 abuts the internal wall of the mandrel passageway 15. The inner sleeve can be made of metal such as copper or industrial plastic material. In the present embodiment, mandrel 12 was molded or formed around inner sleeve 14. An upper sleeve 16 and a lower sleeve 18 are also present and may be attached to the exterior or mandrel 12 by pins 20. An upward facing shoulder on lower sleeve 18 acts as lower slip supporting shoulder 52 of lower slip assembly 50. It is envisioned, of course, that the upper or lower sleeves could be integrally formed on the exterior of the mandrel 12 or could be attached to the mandrel by bonding, pins, threads, or the like.
  • A setting rod 22 is positioned inside sleeve 14 in sliding relationship and is connected to plug assembly 10 only at or near the lower end 26 of the plug. In the illustrated embodiment, a releasable means in the form of a shear pin 24 (preferably brass) extends through setting rod 22 and mandrel 12 and into lower sleeve 18. The term “setting rod” is used herein to include both rigid solid and hollow rods (sleeves) and flexible (cables) of various cross-sectional shapes. It is noted that the shear pin 24 is located below the slip assemblies and packing assembly. The term “below” is used to indicate that shear pin 24 is further away from 28 than the slip and packing assemblies. In this configuration, during setting the location of the shear pin 24 prevents shear stresses from occurring between the mandrel and lower sleeve. It is envisioned that the openings in the mandrel for the shear pins 24 could be enlarged or slot shaped to eliminate contact between the mandrel and shear pin 24. Shear pin 24 acts as the mechanical connection between setting rod 22 and lower sleeve 18 to transfer setting forces from the rod outward to the sleeve, without stressing the mandrel. As illustrated, shear pin 24 extends radially outward below and under slip supporting shoulder 52. The term “under” is used to indicate that shear pin 24 extends behind the shoulder of slip support 52 when viewed from the upper end of the plug. For example, the annular area behind or under the lower slip supporting shoulder 252 is identified by the letter “U” in FIG. 3. Preferably, shear pin 24 extends radially outward substantially the full radial extent of shoulder 52. The benefit of this configuration is that it eliminates shear between the mandrel and the lower sleeve by transferring the setting force from the rod to sleeve 18. This result is present even when sleeve 318 is integrally formed on the mandrel's exterior as illustrated in FIG. 3. This pin is typically formed from brass. As pointed out, only one pin is illustrated, however, more could be present and typically the number of pins is determined by the required setting force.
  • According to another feature of the present inventions, it is noted that shear pin 24 is located below and under the upward facing shoulder 52 of lower sleeve 18. The upper end of setting rod 22 extends a short distance above the upper end 28 of the plug assembly 10 and upper end of the mandrel 12. It is envisioned that the rod could terminate below the upper end as long as the rod can be engaged and tensioned during setting. As will be described, during setting, the setting tool pulls the setting rod upward, and when the desired setting force is reached, the portion of the shear pin 24 inside the mandrel shears, separating setting rod 22 from mandrel 12. Once pin 24 shears, the rod is free to slide up out of plug assembly 10. The clearance between the rod and sleeve (or mandrel passageway if no sleeve is present) is a matter of preference, it only being necessary that the rod fit in a manner that slows it to slide out of the mandrel without inducing substantial tension stress in the mandrel, i.e., sliding engagement. In the preferred embodiment, setting rod 22 has either a “slip fit” or “press fit” in the sleeve (or mandrel if no sleeve is present). When the rod fits closely inside sleeve 14, an additional advantage is present, i.e., the rod reinforces mandrel 12 against collapse during setting. However, if this advantage is not desired, the rod need only have a large enough cross section to carry the setting forces and could conceivably leave a substantial clearance between the rod and passageway 15. “Slip fit” is used herein to refer to a close sliding fit in which setting rod 22 can be slid through sleeve 14 with a small amount of force. “Press fit” refers to a situation where more than a small amount of force is required. It is not envisioned that with the magnitude of force exerted by the setting tool (even with an interference fit) a stuck setting rod 22 would be pulled from mandrel 12 during setting. Indeed, the exterior of setting rod 22 can be lubricated to reduce friction, resisting removal of setting rod 22 from the plug. It is also envisioned that the setting rod 22, sleeve 14 and/or passageway 15 need not be cylindrical shaped and can, like the mandrel, assume other shapes. Setting rod 22 could be placed in the sleeve either before or after mandrel 12 is formed on the sleeve. During installation, setting rod 22 could first be connected to the plug assembly 10 and then to the setting tool. Alternatively, setting rod 22 could be connected to the setting tool and then inserted into and pinned to the plug. Only one shear pin 24 is illustrated; however, as is known in the industry, more pins can be present, depending on the setting force required to set the plug.
  • Mounted around mandrel 12 between sleeves 16 and 18 is a classic, double-slip type tool arrangement with a upper slip assembly 30, packing assembly 40 and lower slip assembly 50. Setting rod 22 also spans the space under the slip and packing assemblies. The designs of the slip and packing assemblies are conventional and can assume any of the designs well known in the art, such as those disclosed in the above identified United States patents, which are incorporated herein by reference. For example, slip assemblies 30 and 50 comprise slips 32 and wedges 34 which can be made in whole or in part from metallic or nonmetallic materials. Packing assembly 40 is illustrated as comprising a single annular, elastomeric element 42 and extrusion control members 44. It is envisioned that the packing assembly could comprise a plurality of resilient annular members, anti-extrusion members, backup rings, and the like, such as those disclosed in the above-identified United States patents which are incorporated herein by reference. In this embodiment, the upper slip support comprises a downward facing shoulder 36 on annular ring 38 which abuts the upper slip assembly 30. Ring 38 is mounted for axial movement along the exterior of mandrel 12. Upward facing shoulder 52 on sleeve 18 acts as the lower slip support and is positioned abutting the lower slip assembly 50. As is well known in the industry, shear pins 39 can be provided as shown in FIG. 1, holding the slip wedges in place to prevent premature axial movement. During setting, shear pins 39 shear and allow the two slip wedges to move axially toward each other.
  • Well bore plug assembly 10 is illustrated in FIG. 1, attached at connection 65 to a setting tool 60. While only a portion of the setting tool 60 is illustrated, designs of setting tools are well known in the industry and typically comprise an annular-shaped pulling or tensioning elements 62 and an annular-shaped pushing or compressing elements 64. Wellbore plug 10 is connected to setting tool 60 with pushing or compressing elements 64 telescoped over upper sleeve 16 and contacting the ring 38, as shown in FIG. 1. Pulling or tensioning elements 62 is attached to setting rod 22, in this case, by threaded engagement 65. It is envisioned that different means, such as pins of the like, could be used to attach setting rod 22 to pulling or tensioning elements 62. It is noted that neither the setting tool nor the setting rod is connected to upper end of mandrel 12, as with conventional plugs. In the FIG. 1 embodiment, the sole connection of the setting rod 22 to the plug is the shear pin 24. In use, the well bore plug assembly 10 is attached to setting tool 60 and lowered or moved to the desired wellbore location. Next, the setting tool 60 is actuated, causing compressing element 64 to be forced down in the direction of arrows B while pulling element 62 is pulled upward in the direction of arrow at A. This action by the setting tool will axially shorten and radially expand packing assembly 40 and the upper and lower slip assemblies 30 and 50 to their set positions as illustrated in FIG. 2. When the force applied by setting rod 22 exceeds the shear strength of the shear pin 24, setting tool 60 disengages from wellbore plug assembly 10, pulling setting rod 22 up out of the passageway 15 of mandrel 12. Thereafter, setting tool 60 and setting rod 22 are removed from the wellbore, leaving plug 10 installed in the wellbore in a set condition illustrated in FIG. 2. A ball valve 102 is then dropped or pumped onto the seat 104.
  • According to the present invention, pin 24 connecting the setting rod 22 passes through the mandrel 12 and sleeve 18 at a location below shoulder 52 and below the slip and packing assemblies. Pin 24 extends radially outward to the outer wall of the lower sleeve 18. This pin (wedges) 24 is the sole element structurally connecting the setting rod 22 to the plug 10. It is to be appreciated that because setting rod 22 passes through the mandrel adjacent to the lower end 26 of the plug, axial tension force is not applied to the mandrel and tension stresses are not induced along the length of mandrel 12 during setting. Thus, when the setting tool applies upward force to setting rod 22, pin 34 transfers that force through sleeve 18 to upward facing shoulder 52 without applying force to mandrel 12. In this manner, the slips and packing element are moved into set positions without the setting tool applying axial force to the mandrel. Indeed, the setting forces are carried by setting rod 22 to a point on the plug positioned under upward facing shoulder 52. Eliminating the high setting induced axial tension stresses in the mandrel present in prior art designs allows the mandrel to be designed with a smaller cross section and to be made from lower tensile strength, easier to drill materials, such as low strength molded plastics, cementitious materials and hydraulic cement.
  • In this embodiment, upward facing shoulder 52 is held against the lower slips by force transferred to sleeve 18 by setting rod 22 through shear pin 24. The presence of the setting rod 22 provides an additional advantage of reinforcing mandrel 12 against collapse during the setting process. During setting compressive forces are applied to the mandrel 12 by packing assemblies and/or slip assemblies. These compressive forces would tend to collapse mandrel 12. Collapse of the mandrel is resisted by the rigidity of setting rod 22. Once the plug is set, the compressive forces are reduced.
  • By configuring the plug as illustrated in FIG. 1, mandrel 12 will not experience the high tension or shear stresses which normally occur in prior art “double-slip” type plugs during setting. This allows mandrel 12 to be made from easy-to-drill materials that are strong in compression but not necessarily strong in tension. In the first example, the mandrel illustrated in FIG. 1 comprises commercial grade, hydraulic cement formed or molded on or around the exterior of a thin sleeve 14. The sleeve 14 is not intended to be structural and can be made of easy-to-drill material such as brass, plastic or the like. Preferably, the sleeve 14 can be as thin as from about five thousands to a quarter of an inch thick. The purpose of the sleeve 14 is to provide a form for passageway 15; however, sleeve 14 could be eliminated, with setting rod 22 contacting the interior wall of passageway 15 in mandrel 12. (See FIG. 3).
  • Setting rod 22, as illustrated in FIG. 1, has a solid cross section. In another example illustrated in FIG. 3, it is envisioned that setting rod 222 could be hollow, forming a central passageway through the plug when the rod is in place. As an alternative to shearing a pin, it is envisioned that the setting rod could have a weakened portion 208 (like is typical in setting sleeves) designed to sever when the desired setting force is achieved, whereby a short hollow section of the rod remains in the mandrel. The pin 224 would still be present to transfer force to the integrally formed sleeve 218.
  • Once the wellbore plug assembly 10 is set in the wellbore, the slip assemblies and packing assembly assume the general configuration illustrated in FIG. 2. In FIG. 2, the wellbore plug assembly 10 is illustrated set in gripping and sealing engagement with the wellbore 100. In this embodiment, the wellbore 100 is illustrated as being cased, and a ball valve 102 has been pumped or dropped down the wellbore to rest on valve seat 104 and formed on the upper end of plug 10. Typically, frac ball 102 is dropped into the well after the setting tool is removed and acts as a check valve to prevent downward flow through the interior of mandrel 12 while permitting flow upward. Note that the valve and its seat are positioned on top of the mandrel so that when high pressure is applied to the top of the plug, compression forces are applied to the upper end of the mandrel. Well treating operations can be performed above the plug, for example, frac, cement, or other treatment fluids and mixtures can be pumped down the well and out into the surrounding formations. The treating fluids and mixtures contact the plug and are blocked from flowing along the wellbore past the plug. The well treatment fluids are therefore forced to flow into the formations around the well. While the function of the frac plug has been described in terms of flow, it can also be described as preventing or blocking flow when the pressure above the frac plug is higher than the pressure below the frac plug and permitting flow when pressure below the frac plug is higher than pressure above the frac plug.
  • The frac plug embodiment illustrated in FIG. 2 is in the position it assumes when a higher pressure is present above the plug 10. As previously described, mandrel 12 can float, i.e., telescope up and down through packing assembly 40 and upper and lower slip assemblies 30 and 50. When pressure is applied from above as represented by arrow P, mandrel 12 and upper and lower sleeves 16 and 18 will be forced down until downward facing shoulder 36 contacts the slips 32 of the upper slip assembly 30. In this position, when high pressure is applied to the plug, holding forces will not cause tension stress in the mandrel 12.
  • FIG. 3 illustrates another embodiment in which the wellbore plug assembly is in the form of a bridge plug assembly 200. Although not illustrated, the upper end of the plug is similar to the example illustrated in FIGS. 1 and 2. The plug is illustrated prior to setting with the setting rod 222 in place. In this embodiment, a seat 204 is formed on the lower end of the mandrel 212 and a ball 202 is positioned adjacent to seat 204. A spring (not shown) can be present to urge the ball 202 in a direction toward seat 204. Also, as illustrated the lower sleeve 218 and its lower slip support annular shoulder 252 comprise an integral part of mandrel 212. The ball 202 is held inside bridge plug assembly 200 by pin 206. Although not illustrated in FIG. 3, the upper end of bridge plug assembly 200 has a frac ball 102 and seat 104 as is illustrated in the embodiment shown in FIGS. 1 and 2. As previously described, when pressure above the plug is higher than it is below the plug, frac ball 102 will seal on seat 104, preventing flow downward through the plug. If the pressure is reversed and high pressure is present below, the ball 202 will seal on seat 204, causing mandrel 112 to float or telescope upward until upward facing shoulder 52 on the sleeve formed on mandrel 212 contacts lower slip assembly 50. Thus, without regard to pressure direction, mandrel 212 is never substantially loaded in tension. In FIG. 3, the setting rod 222 is hollow, and the lower sleeve is integrally formed on the mandrel. Setting rod 222 has a weakened portion 208 along which setting rod 222 parts during setting, leaving a short section of hollow rod in the mandrel. In the FIG. 3 example, the mandrel 212 and integral sleeve 218 comprises cementitious material, and setting rod 222 comprises metallic material.
  • In FIG. 4, an alternative embodiment of a bridge plug 300 is illustrated in the set position with the setting rod removed and pin 324 sheared. Like FIG. 3, the mandrel of FIG. 4 is not lined with a sleeve. Upper and lower flapper valves 302 and 304, respectively, are mounted at the upper and lower ends of mandrel 312. The upper flapper valve 302 is located to apply compressive forces to the top of the mandrel when pressure is applied to the closed valve. The lower flapper valve 304 is located to apply compressive forces to the bottom of the mandrel when pressure is applied from below. Upper flapper valves 302 is pivoted at pivot 306 in upper sleeve 316 to seal off downward flow through the center of mandrel 312 by contacting seat 308. The flapper valves (like the ball valve in FIG. 2) act as check valves to close the mandrel interior at the end of the plug where the higher pressure is present. The valve on the low pressure end opens to prevent high pressures from being trapped in the mandrel. It is envisioned that other types of check valves could be used. This venting prevents pressure differential generated forces from creating tension stresses in the mandrel during use of the plug. It is envisioned that in the non frac plug embodiments, that the lower end valves could be eliminated by utilizing a setting rod that has a necked down or otherwise weakened portion adjacent the lower end. When during setting the tool reached setting force, the setting rod parts adjacent the lower end leaving a short length to close the lower end of the mandrel.
  • A spring (not shown) urges these valves toward the closed position as the setting rod is removed. Lower flapper valves 304 is pivoted at 310 to contact seat 314 to seal off upward flow through the center of mandrel 312. Sleeve 338 contains the upper slip support (not shown). If a frac plug configuration is desired, lower flapper valves 304 is eliminated. The upper sleeve 316 is illustrated, abutting the upper end 330 of the mandrel 312. In this embodiment, the sleeve is eliminated from the interior bore of the mandrel. Lower sleeve 318 with lower slip supporting shoulder 352 is integrally formed on mandrel 312. As in FIG. 3, the mandrel will telescope up and down with pressure, substantially eliminating tension forces in the mandrel. In the third example, the mandrel and one or more of the sleeves comprises concrete. Alternatively, in the fourth example, the mandrel comprises plastic material.
  • According to the method of the present invention of temporarily plugging a wellbore at a subterranean location and treating the wellbore above the plug, a double-slip plug with a hollow mandrel preferably made of cementitious material, hydraulic cement, or concrete is provided. A setting rod is releasably connected to the plug adjacent the lower end with the rod positioned to extend upward through the mandrel and under the slip and packing assemblies. The rod is connected to the plug at a point below the lower slip support. Preferably, a pin extends through the setting rod, mandrel and radially out behind the slip support. A setting tool is attached to the upper end of the rod. Next, the setting tool and plug are positioned in the wellbore at a subterranean location. Thereafter, the setting tool is actuated to pull on the setting rod to set the slip and packing assemblies without tensioning the mandrel or creating shear stress between the mandrel and lower slip support. The setting rod is removed from the plug during the setting process. The setting tool and rod are removed from the wellbore. A check valve is permitted to close at the top of the plug. In the bridge plug embodiment, a check valve is permitted to close at the bottom of the plug. Next, well treatment fluids and mixtures are placed in the wellbore and contact and create a differential pressure across the plug without placing the mandrel in tension. The plug is removed from the well by drilling it out.
  • The mandrel according to the present inventions is formed in whole or part from cementitious materials, such as concrete. The term “concrete” is used to refer to a properly proportioned mixture of hydraulic cement such as Portland cement and one or more of the following: water, aggregate and chemical or mineral additives.
  • Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed herein are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art, having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is, therefore, evident that the particular illustrative embodiments disclosed above may be altered or modified, and all such variations are considered within the scope and spirit of the present invention.
  • Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

Claims (20)

1. An improved plug for installation in the wellbore at a subterranean location, the plug having an upper end for being positioned in the wellbore closest to the wellhead and a lower end for being positioned furthest away from the wellhead, the plug comprising a tubular mandrel, having an axially extending passageway, a packing assembly comprising an annular member comprising deformable material, the annular member being of a size and shape such that when it is axially compressed it extends radially into contact with the wellbore, upper and lower opposed slip assemblies positioned on the mandrel, wherein the upper and lower slip assemblies each comprise an annular member with a wedge surface, a slip support comprising an annular shoulder and a plurality of slips located around the mandrel between an annular wedge surface and the annular shoulder of the slip support, the slips being of a size and shape that when the slip assemblies are axially compressed, the slips extend radially into contact with the wellbore, the packing assembly being positioned on the mandrel between the upper and lower opposed slip assemblies and, wherein the improvement comprises the mandrel substantially comprises cementitious material.
2. The wellbore plug of claim 1, wherein the cementitious material comprises concrete.
3. The wellbore plug of claim 1, additionally comprising a setting rod extending into the mandrel passageway in sliding relationship with the mandrel.
4. The wellbore plug of claim 3, wherein the setting rod is releasably connected to the lower end of the wellbore plug.
5. The wellbore plug of claim 3, wherein lower slip assembly comprises a sleeve on the mandrel, wherein the sleeve has an upward facing radial shoulder and wherein the setting rod extends through the mandrel passageway from the upper end of the mandrel and, wherein the setting rod is connected to the lower slip support.
6. The wellbore plug of claim 1, wherein the upper and lower slip assemblies each comprise an annular member with a wedge surface, a slip support comprising an annular shoulder, and a plurality of slips located around the mandrel between an annular wedge surface and the annular shoulder of the slip support, the slips being of a size and shape that when the slip assemblies are axially compressed, the slips extend radially into contact with the wellbore.
7. The wellbore plug of claim 1, wherein the lower slip support is formed on a sleeve connected to the lower end of the mandrel.
8. The wellbore plug of claim 4, wherein the lower slip support is formed integrally on the mandrel.
9. An improved plug for installation in the wellbore at a subterranean location, the plug having an upper end for being positioned in the wellbore closest to the wellhead and a lower end for being positioned furthest away from the wellhead, the plug comprising a tubular mandrel, having an axially extending passageway, a packing assembly comprising an annular member comprising deformable material, the annular member being of a size and shape such that when it is axially compressed it extends radially into contact with the wellbore, upper and lower opposed slip assemblies positioned on the mandrel, wherein the upper and lower slip assemblies each comprise an annular member with a wedge surface, a slip support comprising an annular shoulder and a plurality of slips located around the mandrel between an annular wedge surface and the annular shoulder of the slip support, the slips being of a size and shape that when the slip assemblies are axially compressed, the slips extend radially into contact with the wellbore, the packing assembly being positioned on the mandrel between the upper and lower opposed slip assemblies, a setting rod extending into the axially extending passageway in sliding relationship with the mandrel and, wherein the improvement comprises the setting rod connected to the lower slip support.
10. The wellbore plug of claim 9, wherein the lower slip support is formed on a sleeve mounted adjacent the lower end of the mandrel and wherein the setting rod is releasably connected to the sleeve at a point substantially adjacent to or below the annular shoulder.
11. The wellbore plug of claim 9, wherein the lower slip support is an annular shoulder is formed mandrel adjacent the lower end of the mandrel and wherein the setting rod is releasably connected to the mandrel at a point substantially adjacent to or below the annular shoulder.
12. The wellbore plug of claim 9, wherein the setting rod is selected from the group consisting of a hollow member, a cable and a solid member.
13. The wellbore plug according to claim 9, wherein releasable means is selected from the group consisting of a shear pin and a breakable portion of the setting rod.
14. The wellbore plug according to claim 9, wherein interior sleeve forms a lining along at least a portion of the passageway wall of the mandrel.
15. The wellbore plug according to claim 9, additionally comprising a check valve located on the mandrel adjacent the mandrel's end, the valve is mounted to block flow into the mandrel passageway and permits flow out of the mandrel passageway.
16. The wellbore plug of claim 9, wherein the mandrel substantially comprises material from the group consisting of cementitious material, sintered metal material and plastic material.
17. A method of setting and using a plug at a subterranean location in a wellbore to contact wellbore fluids, comprising the steps of:
providing a wellbore plug, comprising an upper end for being positioned in the wellbore closest to the wellhead and a lower end for being positioned furthest away from the wellhead, a tubular-shaped mandrel, a packing assembly positioned on the mandrel comprising an annular member comprising deformable material, the annular member being of a size and shape such that when it is axially compressed, it extends radially into contact with the wellbore, upper and lower opposed slip assemblies positioned on the mandrel, wherein the upper and lower slip assemblies each comprise an annular member with a wedge surface, a slip support comprising an annular shoulder and a plurality of slips located around the mandrel between an annular wedge surface and the annular shoulder of the slip support, the slips being of a size and shape that when the slip assemblies are axially compressed, the slips extend radially into contact with the wellbore, the packing assembly positioned on the mandrel between the upper and lower opposed slip assemblies;
attaching the plug to a setting tool;
positioning the plug and setting tool in the wellbore at a subterranean location with the upper end of the plug positioned closest to the wellhead; and
setting the plug in the wellbore, without applying axial force to the mandrel, by moving the slips and packing element to the set position into engagement with the wellbore.
18. The method of claim 17, wherein the moving step comprises using the setting tool to apply force to the upper slip assembly in a direction toward the lower end of the plug, and simultaneously applying force to the lower slip support in a direction toward the upper end of the plug, without applying axial force to the mandrel.
19. The method of claim 17, wherein the attaching step additionally comprises positioning a setting rod to extend into the mandrel in sliding relationship and releasably connecting the setting rod to the lower slip support at a point substantially adjacent to or below the radial shoulder of the lower slip support.
20. The method of claim 17, wherein the moving step comprises using the setting tool to push in the downward direction on the slip support of the upper slip assembly while pulling in the upward direction on the slip support of the lower slip assembly, without applying axial force to the mandrel.
US13/530,897 2011-07-07 2012-06-22 Wellbore plug and method Abandoned US20130008671A1 (en)

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US20130146307A1 (en) * 2011-12-08 2013-06-13 Baker Hughes Incorporated Treatment plug and method of anchoring a treatment plug and then removing a portion thereof
WO2014143384A1 (en) * 2013-03-15 2014-09-18 Baker Hughes Incorporated One-way flowable anchoring system and method of treating and producing a well
US9033060B2 (en) 2012-01-25 2015-05-19 Baker Hughes Incorporated Tubular anchoring system and method
US9080403B2 (en) 2012-01-25 2015-07-14 Baker Hughes Incorporated Tubular anchoring system and method
US9085968B2 (en) 2012-12-06 2015-07-21 Baker Hughes Incorporated Expandable tubular and method of making same
US9217319B2 (en) 2012-05-18 2015-12-22 Frazier Technologies, L.L.C. High-molecular-weight polyglycolides for hydrocarbon recovery
US9284803B2 (en) 2012-01-25 2016-03-15 Baker Hughes Incorporated One-way flowable anchoring system and method of treating and producing a well
US9309733B2 (en) 2012-01-25 2016-04-12 Baker Hughes Incorporated Tubular anchoring system and method
USRE46028E1 (en) 2003-05-15 2016-06-14 Kureha Corporation Method and apparatus for delayed flow or pressure change in wells
US9366106B2 (en) 2011-04-28 2016-06-14 Baker Hughes Incorporated Method of making and using a functionally gradient composite tool
US9506309B2 (en) 2008-12-23 2016-11-29 Frazier Ball Invention, LLC Downhole tools having non-toxic degradable elements
US9587475B2 (en) 2008-12-23 2017-03-07 Frazier Ball Invention, LLC Downhole tools having non-toxic degradable elements and their methods of use
US9605508B2 (en) 2012-05-08 2017-03-28 Baker Hughes Incorporated Disintegrable and conformable metallic seal, and method of making the same
US9631138B2 (en) 2011-04-28 2017-04-25 Baker Hughes Incorporated Functionally gradient composite article
US9643144B2 (en) 2011-09-02 2017-05-09 Baker Hughes Incorporated Method to generate and disperse nanostructures in a composite material
US9682425B2 (en) 2009-12-08 2017-06-20 Baker Hughes Incorporated Coated metallic powder and method of making the same
US9708878B2 (en) 2003-05-15 2017-07-18 Kureha Corporation Applications of degradable polymer for delayed mechanical changes in wells
US9707739B2 (en) 2011-07-22 2017-07-18 Baker Hughes Incorporated Intermetallic metallic composite, method of manufacture thereof and articles comprising the same
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US9816339B2 (en) 2013-09-03 2017-11-14 Baker Hughes, A Ge Company, Llc Plug reception assembly and method of reducing restriction in a borehole
US9833838B2 (en) 2011-07-29 2017-12-05 Baker Hughes, A Ge Company, Llc Method of controlling the corrosion rate of alloy particles, alloy particle with controlled corrosion rate, and articles comprising the particle
US9856547B2 (en) 2011-08-30 2018-01-02 Bakers Hughes, A Ge Company, Llc Nanostructured powder metal compact
US9910026B2 (en) 2015-01-21 2018-03-06 Baker Hughes, A Ge Company, Llc High temperature tracers for downhole detection of produced water
US9925589B2 (en) 2011-08-30 2018-03-27 Baker Hughes, A Ge Company, Llc Aluminum alloy powder metal compact
US9926763B2 (en) 2011-06-17 2018-03-27 Baker Hughes, A Ge Company, Llc Corrodible downhole article and method of removing the article from downhole environment
US9926766B2 (en) 2012-01-25 2018-03-27 Baker Hughes, A Ge Company, Llc Seat for a tubular treating system
US10016810B2 (en) 2015-12-14 2018-07-10 Baker Hughes, A Ge Company, Llc Methods of manufacturing degradable tools using a galvanic carrier and tools manufactured thereof
US10092953B2 (en) 2011-07-29 2018-10-09 Baker Hughes, A Ge Company, Llc Method of controlling the corrosion rate of alloy particles, alloy particle with controlled corrosion rate, and articles comprising the particle
US10156119B2 (en) 2015-07-24 2018-12-18 Innovex Downhole Solutions, Inc. Downhole tool with an expandable sleeve
US10221637B2 (en) 2015-08-11 2019-03-05 Baker Hughes, A Ge Company, Llc Methods of manufacturing dissolvable tools via liquid-solid state molding
US10227842B2 (en) 2016-12-14 2019-03-12 Innovex Downhole Solutions, Inc. Friction-lock frac plug
US10301909B2 (en) 2011-08-17 2019-05-28 Baker Hughes, A Ge Company, Llc Selectively degradable passage restriction
US10378303B2 (en) 2015-03-05 2019-08-13 Baker Hughes, A Ge Company, Llc Downhole tool and method of forming the same
WO2019168507A1 (en) * 2018-02-27 2019-09-06 Halliburton Energy Services, Inc. Downhole check valve assembly with a locking mechanism
WO2019168503A1 (en) * 2018-02-27 2019-09-06 Halliburton Energy Services, Inc. Downhole check valve assembly with a ratchet mechanism
US10408012B2 (en) 2015-07-24 2019-09-10 Innovex Downhole Solutions, Inc. Downhole tool with an expandable sleeve

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US10280703B2 (en) 2003-05-15 2019-05-07 Kureha Corporation Applications of degradable polymer for delayed mechanical changes in wells
USRE46028E1 (en) 2003-05-15 2016-06-14 Kureha Corporation Method and apparatus for delayed flow or pressure change in wells
US9708878B2 (en) 2003-05-15 2017-07-18 Kureha Corporation Applications of degradable polymer for delayed mechanical changes in wells
US9506309B2 (en) 2008-12-23 2016-11-29 Frazier Ball Invention, LLC Downhole tools having non-toxic degradable elements
US9587475B2 (en) 2008-12-23 2017-03-07 Frazier Ball Invention, LLC Downhole tools having non-toxic degradable elements and their methods of use
US9682425B2 (en) 2009-12-08 2017-06-20 Baker Hughes Incorporated Coated metallic powder and method of making the same
US9366106B2 (en) 2011-04-28 2016-06-14 Baker Hughes Incorporated Method of making and using a functionally gradient composite tool
US9631138B2 (en) 2011-04-28 2017-04-25 Baker Hughes Incorporated Functionally gradient composite article
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US9926763B2 (en) 2011-06-17 2018-03-27 Baker Hughes, A Ge Company, Llc Corrodible downhole article and method of removing the article from downhole environment
US9707739B2 (en) 2011-07-22 2017-07-18 Baker Hughes Incorporated Intermetallic metallic composite, method of manufacture thereof and articles comprising the same
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US10092953B2 (en) 2011-07-29 2018-10-09 Baker Hughes, A Ge Company, Llc Method of controlling the corrosion rate of alloy particles, alloy particle with controlled corrosion rate, and articles comprising the particle
US10301909B2 (en) 2011-08-17 2019-05-28 Baker Hughes, A Ge Company, Llc Selectively degradable passage restriction
US9925589B2 (en) 2011-08-30 2018-03-27 Baker Hughes, A Ge Company, Llc Aluminum alloy powder metal compact
US9802250B2 (en) 2011-08-30 2017-10-31 Baker Hughes Magnesium alloy powder metal compact
US9856547B2 (en) 2011-08-30 2018-01-02 Bakers Hughes, A Ge Company, Llc Nanostructured powder metal compact
US9643144B2 (en) 2011-09-02 2017-05-09 Baker Hughes Incorporated Method to generate and disperse nanostructures in a composite material
US20130146307A1 (en) * 2011-12-08 2013-06-13 Baker Hughes Incorporated Treatment plug and method of anchoring a treatment plug and then removing a portion thereof
US9926766B2 (en) 2012-01-25 2018-03-27 Baker Hughes, A Ge Company, Llc Seat for a tubular treating system
US9033060B2 (en) 2012-01-25 2015-05-19 Baker Hughes Incorporated Tubular anchoring system and method
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US10378303B2 (en) 2015-03-05 2019-08-13 Baker Hughes, A Ge Company, Llc Downhole tool and method of forming the same
US10156119B2 (en) 2015-07-24 2018-12-18 Innovex Downhole Solutions, Inc. Downhole tool with an expandable sleeve
US10408012B2 (en) 2015-07-24 2019-09-10 Innovex Downhole Solutions, Inc. Downhole tool with an expandable sleeve
US10221637B2 (en) 2015-08-11 2019-03-05 Baker Hughes, A Ge Company, Llc Methods of manufacturing dissolvable tools via liquid-solid state molding
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US10227842B2 (en) 2016-12-14 2019-03-12 Innovex Downhole Solutions, Inc. Friction-lock frac plug
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WO2019168503A1 (en) * 2018-02-27 2019-09-06 Halliburton Energy Services, Inc. Downhole check valve assembly with a ratchet mechanism

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