US20110005779A1 - Composite downhole tool with reduced slip volume - Google Patents
Composite downhole tool with reduced slip volume Download PDFInfo
- Publication number
- US20110005779A1 US20110005779A1 US12/500,476 US50047609A US2011005779A1 US 20110005779 A1 US20110005779 A1 US 20110005779A1 US 50047609 A US50047609 A US 50047609A US 2011005779 A1 US2011005779 A1 US 2011005779A1
- Authority
- US
- United States
- Prior art keywords
- slip
- downhole tool
- disposed
- sealing
- wickers
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B33/129—Packers; Plugs with mechanical slips for hooking into the casing
- E21B33/1293—Packers; Plugs with mechanical slips for hooking into the casing with means for anchoring against downward and upward movement
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B33/134—Bridging plugs
Definitions
- the present invention relates to the field of downhole tools, and in particular to downhole tools such as bridge plugs, frac-plugs, and packers.
- An oil or gas well includes a wellbore extending into a well to some depth below the surface.
- the wellbore is lined with tubulars or casing to strengthen the walls of the borehole.
- the annular area formed between the casing and the borehole is typically filled with cement to set the casing permanently in the wellbore. Perforating the casing allows production fluid to enter the wellbore and flow to the surface of the well.
- Downhole tools with sealing elements are placed within the wellbore to isolate the production fluid or to manage production fluid flow through the well.
- a bridge plug or frac-plug placed within the wellbore can isolate upper and lower sections of production zones. Bridge plugs and frac-plugs create a pressure seal in the wellbore to allow pressurized fluids or solids to treat an isolated formation.
- Packers are typically used to seal an annular area formed between two co-axially disposed tubulars within a wellbore.
- packers may seal an annulus formed between production tubing disposed within wellbore casing.
- packers may seal an annulus between the outside of a tubular and an unlined borehole.
- Routine uses of packers include the protection of casing from pressure, both well and stimulation pressures, as well as the protection of the wellbore casing from corrosive fluids.
- Other common uses include the isolation of formations or leaks within a wellbore casing or multiple producing zones, thereby preventing the migration of fluid between zones.
- Packers may also be used to hold kill fluids or treating fluids within the casing annulus.
- the downhole tools are usually constructed of cast iron, aluminum, or other alloyed metals, but can be made of non-metallic materials, such as composite materials.
- a sealing member is typically made of a composite or synthetic rubber malleable material that seals off an annulus within the wellbore to prevent the passage of fluids. The sealing member is compressed or swells, thereby expanding radially outward from the tool to engage and seal with a surrounding tubular.
- Conventional bridge plug, frac plugs, and packers typically comprise a synthetic sealing member located between upper and lower metallic retaining rings, commonly known as slips, that prevent the downhole tool from moving up or down in the wellbore.
- Slips have been designed to reduce the amount of metal to reduce drill up time. Although some have attempted to create composite material slips, often pressure holding at temperature has been sacrificed to gain up drill up speed.
- teeth sections of the slip are separated by a substantially flat circumference section for placing a band around the slip to improve fracturing uniformity.
- the teeth sections can have any of a variety of configurations, including orientations axially away from the central portion of the slip and orientations axially toward the central portion of the slip.
- FIG. 1 is a cutaway view of a bridge plug according to the prior art
- FIG. 2 is a cutaway view of a bridge plug according to one embodiment
- FIG. 3 is a cutaway view of a bi-directional slip according to one embodiment
- FIG. 4 is a cross-sectional view of a bi-directional slip according to another embodiment.
- FIG. 5 is a cross-sectional view of a bi-directional slip according to yet another embodiment.
- FIG. 1 is a cutaway view of a conventional bridge plug 100 according to the prior art.
- the bridge plug 100 comprises a mandrel 110 , about which are disposed various elements, which are typically formed of metal, but can be made of a composite material, such as is described in U.S. Pat. No. 7,124,831, which is incorporated herein by reference in its entirety for all purposes.
- the two slips 130 are typically made of metal, such as a ductile cast iron.
- a sealing member 120 and other related elements 125 are disposed about the mandrel 110 .
- Axial force through the slips 130 and the other elements 125 compress the sealing member 120 , causing it to expand and to seal with the surrounding tubular (not shown).
- the two slips 130 oriented opposite to each other, expand to engage with the surrounding tubular and help retain the downhole tool in place in the wellbore.
- Boost forces from the sealing member 120 on the slips 130 increase their holding ability.
- the two slips 130 are made of metal, typically a ductile cast iron, and increase the mill up time of the downhole tool 100 .
- FIG. 2 a cutaway view illustrates an improved downhole tool 200 that uses a single bidirectional slip with reduced metal volume, allowing faster mill up time, but providing sufficient retaining ability against uphole and downhole forces when engaged with the surrounding tubular.
- a single slip 210 is confined by two sealing systems 220 , as described in detail below.
- the downhole tool 200 can be configured as a bridge plug, a frac plug, a packer, or any other desired downhole tool.
- the downhole tool 200 uses a mandrel 110 , disposing the remainder of the downhole tool 200 about the mandrel 110 .
- the mandrel 110 can be a solid core mandrel or can be a hollow core mandrel that is plugged with a core plug (not shown in FIG. 2 ) as desired.
- Most of the downhole tool 200 including the mandrel 110 and the sealing systems 220 , is typically non-metallic, and the non-metallic elements are usually manufactured from one or more composite materials.
- the embodiment illustrated in FIG. 2 uses a single bi-directional slip 210 that resists movement in either axial direction once activated by the sealing systems 220 to engage with the surrounding tubular.
- the single slip 210 contains less metal than the conventional pair of slips 130 .
- the downhole tool 200 uses two sealing systems 220 , one axially on either end of the slip 210 .
- Each sealing system 220 in addition to sealing the downhole tool 200 with the surrounding tubular, also provides boost forces to the slip 210 , increasing its ability to engage with the tubular and hold the downhole tool 200 in place under high pressure.
- Each sealing system 220 includes a sealing member 225 , which is a malleable, synthetic element.
- the sealing member 225 can have any desired configuration to seal an annulus within the wellbore.
- the sealing member 225 can include grooves, ridges, indentations, or protrusions designed to allow the sealing member 225 to conform to variations in the shape of the interior of the surrounding tubular.
- the sealing member is capable in one embodiment of withstanding temperatures of 232° C. (450° F.) and pressure differentials of up to 103,000 kPa (15,000 psi). Other temperature and pressure configurations can be used, as well.
- each sealing system 220 comprises, in addition to the sealing member 225 , a cone 221 and two each of cones 224 , expansion rings 223 , and support rings 222 .
- a second cone 221 is also included.
- axial force is applied to the sealing system distal to the slip 210 by either a mule shoe 250 or a setting ring 240 and a setting tool (not shown), as described below.
- the additional cone 221 is interposed between the setting ring 240 and support ring 230 .
- Such an embodiment would allow manufacture of a sealing system 220 that could be used unchanged both in downhole tools such as the downhole tool of FIG. 2 and also in conventional downhole tools such as illustrated in FIG. 1 .
- the sealing system 220 transfers axial force onto the sealing member 225 , compressing the sealing member 225 and thereby sealing with the surrounding tubular.
- Each cone 224 transfers axial force from the rest of the sealing system 220 onto the sealing member 225 , compressing the sealing member 225 , and causing the sealing member 225 to expand radially toward the inner surface of the surrounding tubular, sealing with the surrounding tubular.
- the expansion ring 223 flows and expands in one embodiment across a tapered surface of the cone 224 , applying a collapse load through the cone 224 on the mandrel 110 , which helps prevent slippage of the system 220 one activated.
- the collapse load also prevents the cone 224 and sealing member 225 from rotating when milling up the downhole tool 200 , reducing the mill up time.
- the cone 224 thus transfers axial force from the expansion ring 223 to the sealing member 225 to cause radial expansion of the sealing member 225 .
- the support ring 222 transfers axial force to the expansion ring 223 .
- the support ring 222 comprises sections that are designed to hinge radially outwardly, toward the surrounding tubular as sections are forced across a tapered section of the expansion ring 223 . At full deployment, the sections expand outwardly sufficient to engage the surrounding tubular.
- the cone 221 transfers axial force to the support ring 222 , forcing it across the expansion ring 223 and causing the support ring 222 to expand as described above.
- the cone 221 proximal to the slip 210 in turn receives axial force in the opposite direction, and transfers boost force to the end of the slip 210 .
- the mule shoe 250 is positioned on the downhole end of the downhole tool 200 , and is typically threadedly attached to the mandrel 110 .
- the mule shoe 250 is typically pinned in position on the mandrel 110 .
- the setting ring 240 is an annular member that provides a substantially flat surface for use with a setting tool (not shown), and transfers axial force from the setting tool to the sealing system 220 through the other elements of the sealing system 220 .
- the support ring 230 has an outer diameter less than the outer diameter of the setting ring 240 , providing a shoulder for engagement with the setting tool, which thus slips over the support ring 240 to engage with the shoulder of the setting ring 240 to transfer force from the setting tool to the sealing system 220 .
- the downhole tool 200 can be installed in a wellbore with any desired non-rigid system, such as electric wireline or coiled tubing.
- a setting tool such as a Baker E- 4 Wireline Setting Assembly commercially available from Baker Hughes, Inc., connects to an upper portion of the mandrel 110 .
- an outer movable portion of the setting tool is disposed about the outer diameter of the support ring 230 , abutting the first end of the setting ring 240 .
- An inner portion of the setting tool is fastened about the outer diameter of the support ring 230 .
- the setting tool and downhole tool 200 are then run into the well casing to the desired depth where the downhole tool 200 is to be installed.
- the mandrel 110 is held by the wireline, through the inner portion of the setting tool, as an axial force is applied through the outer movable portion of the setting tool to the setting ring 240 .
- the axial forces cause the outer portions of the downhole tool 200 to move axially relative to the mandrel 110 .
- the force asserted against the setting ring 240 is transmitted by the setting ring 240 .
- An equal and opposite force is asserted by the stationary mule shoe 250 on the other end of the downhole tool 200 .
- the force from both ends is transmitted to the sealing systems 220 , which causes the sealing members 225 to expand and to seal with the surrounding tubular.
- the force is further transmitted to the slip 210 , activating each end of the slip 210 by causing each end of the slip 210 to expand and to engage with the surrounding tubular, setting the slip 210 and thus the downhole tool as a whole.
- the slip 210 fractures under radial stress.
- the slip 240 in one embodiment, illustrated in FIG. 2 , has a pineapple configuration that includes at least one and typically a plurality of recessed grooves 212 , milled or otherwise formed therein as fracture zones, allowing the slip 210 to fracture along the grooves 212 to engage the teeth of the slip 210 with the inner surface of the surrounding tubular.
- the slip 210 is disposed between the sealing systems 220 about the mandrel 110 .
- An outer surface of the slip can include two or more outwardly, extending wickers, comprising serrations or edge teeth, with at least one of the wickers oriented toward the setting ring 240 , to resist uphole axial movement, and at least one of the wickers oriented toward the mule shoe 250 , to resist downhole axial movement.
- the cone 221 drives that end of the slip radially outward from the mandrel 110 , in addition to providing axial force through the cones 221 to the support rings 222 , and thus to the sealing member 225 .
- the sealing system 220 illustrated proximal to the mule shoe 250 in FIG. 2 can be replaced with a bias piston. Because such a biasing piston is more complicated than the sealing system 220 , the use of a second sealing system 220 instead of a biasing piston is preferred.
- the slip 210 of FIG. 2 is illustrated with circumferential rows of wickers 211 oriented to resist axially downhole movement adjacent to rows of teeth 213 oriented to resist axially uphole movement.
- the tooth configuration of the slip 210 in FIG. 2 is illustrative and by way of example only.
- the number, shape, and configuration of teeth are illustrative and by way of example only, and other numbers, shapes, and configurations of teeth can be used as desired.
- the teeth 211 and 213 instead of biasing the teeth 211 and 213 towards either end of the downhole tool 200 , the teeth 211 and 213 can extend radially perpendicular from a central axis of the slip 210 and resist movement in either axial direction.
- FIG. 3 is a cutaway view that illustrates another embodiment of a slip 300 .
- teeth sections 310 and 330 are separated by a central portion with a substantially flat circumferential configuration around which a band 340 is disposed.
- the band or strap 340 helps ensure that the slip 300 , when axial force is exerted on it from both directions, fractures more evenly, providing substantially equal expansion and engagement of the teeth section 310 and 330 .
- the slip 300 can provide substantially equal resistance to axial movement in either direction.
- FIGS. 4 and 5 are cross-sectional views along the central axis A-A of two other embodiments of a slip 400 and 500 .
- the teeth 410 and 430 are oriented toward each end of the slip 400 .
- a central section can be surrounded with a strap 340 , not shown in FIG. 4 , for improved evenness of fracture and engagement with the surrounding tubular, although embodiments without the central section can be used.
- the teeth 410 and 430 of slip 400 are simple triangular teeth, forming a right triangle perpendicular to the axis A-A with the right angle oriented toward the end of the slip 400 .
- FIG. 5 An alternate embodiment is shown in FIG. 5 .
- the teeth sections 510 and 530 comprise simple triangular teeth separated by a central section 520 for the attachment of the band 340 .
- the orientation of the teeth 510 and 530 are reversed from the orientation of the teeth 410 and 430 , so that the teeth are oriented toward the central portion 520 .
- FIGS. 2-5 are illustrative and by way of example only, and any number, shape, and configuration of teeth can be used as desired, including orientation axially either toward the ends of the slip or toward the center.
- the use of wickers or teeth is illustrative and by way of example only. In some embodiments, other surface treatments other than wickers or teeth can be used to provide gripping ability for the slip.
- bi-directional slip and dual sealing systems described herein may be used in conjunction with any downhole tool used for sealing an annulus within a wellbore, such as frac-plugs, bridge plugs, or packers, for example.
- various embodiments provide a downhole tool with reduced metal content, allowing faster mill up and less metal waste to fall downhole, but without sacrificing the ability to hold the downhole tool in place under high temperature and pressure conditions.
- the two sealing systems in addition to doubly sealing with the surrounding tubular, provide boost force on the single slip in both directions, thus increasing the holding power of the single slip.
Abstract
A single bidirectional slip for a downhole tool reduces the volume of metal and allows an increased drill up speed. A dual sealing element system, with one sealing element above and one below the bi-directional slip, provides boost forces going through the sealing elements to the slip. The wickers of the slip can be separated by a substantially flat circumference section for placing a band around the slip to improve fracturing uniformity. The wickers can have any of a variety of configurations, including orientations axially away from the central portion of the slip and orientations axially toward the central portion of the slip.
Description
- The present invention relates to the field of downhole tools, and in particular to downhole tools such as bridge plugs, frac-plugs, and packers.
- An oil or gas well includes a wellbore extending into a well to some depth below the surface. Typically, the wellbore is lined with tubulars or casing to strengthen the walls of the borehole. To strengthen the walls of the borehole further, the annular area formed between the casing and the borehole is typically filled with cement to set the casing permanently in the wellbore. Perforating the casing allows production fluid to enter the wellbore and flow to the surface of the well.
- Downhole tools with sealing elements are placed within the wellbore to isolate the production fluid or to manage production fluid flow through the well. For example, a bridge plug or frac-plug placed within the wellbore can isolate upper and lower sections of production zones. Bridge plugs and frac-plugs create a pressure seal in the wellbore to allow pressurized fluids or solids to treat an isolated formation.
- Packers are typically used to seal an annular area formed between two co-axially disposed tubulars within a wellbore. For example, packers may seal an annulus formed between production tubing disposed within wellbore casing. Alternatively, packers may seal an annulus between the outside of a tubular and an unlined borehole. Routine uses of packers include the protection of casing from pressure, both well and stimulation pressures, as well as the protection of the wellbore casing from corrosive fluids. Other common uses include the isolation of formations or leaks within a wellbore casing or multiple producing zones, thereby preventing the migration of fluid between zones. Packers may also be used to hold kill fluids or treating fluids within the casing annulus.
- The downhole tools are usually constructed of cast iron, aluminum, or other alloyed metals, but can be made of non-metallic materials, such as composite materials. A sealing member is typically made of a composite or synthetic rubber malleable material that seals off an annulus within the wellbore to prevent the passage of fluids. The sealing member is compressed or swells, thereby expanding radially outward from the tool to engage and seal with a surrounding tubular. Conventional bridge plug, frac plugs, and packers typically comprise a synthetic sealing member located between upper and lower metallic retaining rings, commonly known as slips, that prevent the downhole tool from moving up or down in the wellbore.
- One problem associated with conventional element systems of downhole tools arises when the tool is no longer needed to seal an annulus and must be removed from the wellbore. For example, plugs and packers are sometimes intended to be temporary and must be removed to access the wellbore. Rather than de-actuate the tool and bring it to the surface of the well, the tool is typically destroyed with a rotating milling or drilling device. As the mill contacts the tool, the tool is “drilled up” or reduced to small pieces that are either washed out of the wellbore or simply left at the bottom of the wellbore. The more metal parts making up the tool, the longer the milling operation takes. Metallic components also typically require numerous trips in and out of the wellbore to replace worn out mills or drill bits.
- Slips have been designed to reduce the amount of metal to reduce drill up time. Although some have attempted to create composite material slips, often pressure holding at temperature has been sacrificed to gain up drill up speed.
- The conventional two slips of a downhole tool are combined into a single bi-directional slip, thereby reducing the volume of metal and allowing an increased drill up speed. A dual sealing element system, with one sealing element above and one below the bidirectional slip, provides boost forces going through the sealing elements to the slip. In some embodiments, teeth sections of the slip are separated by a substantially flat circumference section for placing a band around the slip to improve fracturing uniformity. The teeth sections can have any of a variety of configurations, including orientations axially away from the central portion of the slip and orientations axially toward the central portion of the slip.
- The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate an implementation of apparatus and methods consistent with the present invention and, together with the detailed description, serve to explain advantages and principles consistent with the invention. In the drawings,
-
FIG. 1 is a cutaway view of a bridge plug according to the prior art; -
FIG. 2 is a cutaway view of a bridge plug according to one embodiment; -
FIG. 3 is a cutaway view of a bi-directional slip according to one embodiment; -
FIG. 4 is a cross-sectional view of a bi-directional slip according to another embodiment; and -
FIG. 5 is a cross-sectional view of a bi-directional slip according to yet another embodiment. -
FIG. 1 is a cutaway view of aconventional bridge plug 100 according to the prior art. Thebridge plug 100 comprises amandrel 110, about which are disposed various elements, which are typically formed of metal, but can be made of a composite material, such as is described in U.S. Pat. No. 7,124,831, which is incorporated herein by reference in its entirety for all purposes. Even when most of thebridge plug 100 is made of composite materials, the twoslips 130 are typically made of metal, such as a ductile cast iron. - As shown in
FIG. 1 , asealing member 120 and otherrelated elements 125 are disposed about themandrel 110. Axial force through theslips 130 and theother elements 125 compress thesealing member 120, causing it to expand and to seal with the surrounding tubular (not shown). The twoslips 130, oriented opposite to each other, expand to engage with the surrounding tubular and help retain the downhole tool in place in the wellbore. Boost forces from the sealingmember 120 on theslips 130 increase their holding ability. As described above, the twoslips 130 are made of metal, typically a ductile cast iron, and increase the mill up time of thedownhole tool 100. - Turning to
FIG. 2 , a cutaway view illustrates an improveddownhole tool 200 that uses a single bidirectional slip with reduced metal volume, allowing faster mill up time, but providing sufficient retaining ability against uphole and downhole forces when engaged with the surrounding tubular. Instead of confining asingle sealing member 120 with twoslips 130, in this embodiment, asingle slip 210 is confined by twosealing systems 220, as described in detail below. Thedownhole tool 200 can be configured as a bridge plug, a frac plug, a packer, or any other desired downhole tool. - As with the
conventional downhole tool 100, thedownhole tool 200 uses amandrel 110, disposing the remainder of thedownhole tool 200 about themandrel 110. Although shown inFIG. 2 as ahollow core mandrel 110, themandrel 110 can be a solid core mandrel or can be a hollow core mandrel that is plugged with a core plug (not shown inFIG. 2 ) as desired. Most of thedownhole tool 200, including themandrel 110 and thesealing systems 220, is typically non-metallic, and the non-metallic elements are usually manufactured from one or more composite materials. - Instead of two
unidirectional slips 130, each of which resists movement in a single axial direction and tends to disengage from the surrounding tubular in the opposite axial direction, the embodiment illustrated inFIG. 2 uses asingle bi-directional slip 210 that resists movement in either axial direction once activated by thesealing systems 220 to engage with the surrounding tubular. Although made of metal, such as a ductile cast iron, thesingle slip 210 contains less metal than the conventional pair ofslips 130. - To provide sealing with the tubular, the
downhole tool 200 uses twosealing systems 220, one axially on either end of theslip 210. Eachsealing system 220, in addition to sealing thedownhole tool 200 with the surrounding tubular, also provides boost forces to theslip 210, increasing its ability to engage with the tubular and hold thedownhole tool 200 in place under high pressure. - Each
sealing system 220 includes asealing member 225, which is a malleable, synthetic element. The sealingmember 225 can have any desired configuration to seal an annulus within the wellbore. For example, the sealingmember 225 can include grooves, ridges, indentations, or protrusions designed to allow the sealingmember 225 to conform to variations in the shape of the interior of the surrounding tubular. The sealing member is capable in one embodiment of withstanding temperatures of 232° C. (450° F.) and pressure differentials of up to 103,000 kPa (15,000 psi). Other temperature and pressure configurations can be used, as well. - As illustrated in
FIG. 2 , according to one embodiment each sealingsystem 220 comprises, in addition to the sealingmember 225, acone 221 and two each ofcones 224, expansion rings 223, and support rings 222. In other embodiments, asecond cone 221 is also included. In the embodiment illustrated inFIG. 2 , axial force is applied to the sealing system distal to theslip 210 by either amule shoe 250 or asetting ring 240 and a setting tool (not shown), as described below. In the embodiment with asecond cone 221, theadditional cone 221 is interposed between the settingring 240 andsupport ring 230. Such an embodiment would allow manufacture of asealing system 220 that could be used unchanged both in downhole tools such as the downhole tool ofFIG. 2 and also in conventional downhole tools such as illustrated inFIG. 1 . - The
sealing system 220, as illustrated inFIG. 2 , transfers axial force onto the sealingmember 225, compressing the sealingmember 225 and thereby sealing with the surrounding tubular. Eachcone 224 transfers axial force from the rest of thesealing system 220 onto the sealingmember 225, compressing the sealingmember 225, and causing the sealingmember 225 to expand radially toward the inner surface of the surrounding tubular, sealing with the surrounding tubular. - The
expansion ring 223 flows and expands in one embodiment across a tapered surface of thecone 224, applying a collapse load through thecone 224 on themandrel 110, which helps prevent slippage of thesystem 220 one activated. The collapse load also prevents thecone 224 and sealingmember 225 from rotating when milling up thedownhole tool 200, reducing the mill up time. Thecone 224 thus transfers axial force from theexpansion ring 223 to the sealingmember 225 to cause radial expansion of the sealingmember 225. - The
support ring 222 transfers axial force to theexpansion ring 223. In one embodiment, thesupport ring 222 comprises sections that are designed to hinge radially outwardly, toward the surrounding tubular as sections are forced across a tapered section of theexpansion ring 223. At full deployment, the sections expand outwardly sufficient to engage the surrounding tubular. - The
cone 221 transfers axial force to thesupport ring 222, forcing it across theexpansion ring 223 and causing thesupport ring 222 to expand as described above. Thecone 221 proximal to theslip 210 in turn receives axial force in the opposite direction, and transfers boost force to the end of theslip 210. - The
mule shoe 250 is positioned on the downhole end of thedownhole tool 200, and is typically threadedly attached to themandrel 110. Themule shoe 250 is typically pinned in position on themandrel 110. - The
setting ring 240 is an annular member that provides a substantially flat surface for use with a setting tool (not shown), and transfers axial force from the setting tool to thesealing system 220 through the other elements of thesealing system 220. In one embodiment, thesupport ring 230 has an outer diameter less than the outer diameter of thesetting ring 240, providing a shoulder for engagement with the setting tool, which thus slips over thesupport ring 240 to engage with the shoulder of thesetting ring 240 to transfer force from the setting tool to thesealing system 220. - The
downhole tool 200 can be installed in a wellbore with any desired non-rigid system, such as electric wireline or coiled tubing. A setting tool, such as a Baker E-4 Wireline Setting Assembly commercially available from Baker Hughes, Inc., connects to an upper portion of themandrel 110. Specifically, an outer movable portion of the setting tool is disposed about the outer diameter of thesupport ring 230, abutting the first end of thesetting ring 240. An inner portion of the setting tool is fastened about the outer diameter of thesupport ring 230. The setting tool anddownhole tool 200 are then run into the well casing to the desired depth where thedownhole tool 200 is to be installed. - To set or activate the
downhole tool 200, themandrel 110 is held by the wireline, through the inner portion of the setting tool, as an axial force is applied through the outer movable portion of the setting tool to thesetting ring 240. The axial forces cause the outer portions of thedownhole tool 200 to move axially relative to themandrel 110. - The force asserted against the setting
ring 240 is transmitted by thesetting ring 240. An equal and opposite force is asserted by thestationary mule shoe 250 on the other end of thedownhole tool 200. The force from both ends is transmitted to the sealingsystems 220, which causes the sealingmembers 225 to expand and to seal with the surrounding tubular. The force is further transmitted to theslip 210, activating each end of theslip 210 by causing each end of theslip 210 to expand and to engage with the surrounding tubular, setting theslip 210 and thus the downhole tool as a whole. - The
slip 210 fractures under radial stress. Theslip 240 in one embodiment, illustrated inFIG. 2 , has a pineapple configuration that includes at least one and typically a plurality of recessedgrooves 212, milled or otherwise formed therein as fracture zones, allowing theslip 210 to fracture along thegrooves 212 to engage the teeth of theslip 210 with the inner surface of the surrounding tubular. - The
slip 210 is disposed between the sealingsystems 220 about themandrel 110. An outer surface of the slip can include two or more outwardly, extending wickers, comprising serrations or edge teeth, with at least one of the wickers oriented toward thesetting ring 240, to resist uphole axial movement, and at least one of the wickers oriented toward themule shoe 250, to resist downhole axial movement. As each end of theslip 210 is driven across thecones 221, thecone 221 drives that end of the slip radially outward from themandrel 110, in addition to providing axial force through thecones 221 to the support rings 222, and thus to the sealingmember 225. - In another embodiment, the
sealing system 220 illustrated proximal to themule shoe 250 inFIG. 2 can be replaced with a bias piston. Because such a biasing piston is more complicated than thesealing system 220, the use of asecond sealing system 220 instead of a biasing piston is preferred. - The
slip 210 ofFIG. 2 is illustrated with circumferential rows ofwickers 211 oriented to resist axially downhole movement adjacent to rows ofteeth 213 oriented to resist axially uphole movement. The tooth configuration of theslip 210 inFIG. 2 is illustrative and by way of example only. In particular, the number, shape, and configuration of teeth are illustrative and by way of example only, and other numbers, shapes, and configurations of teeth can be used as desired. For example, instead of biasing theteeth downhole tool 200, theteeth slip 210 and resist movement in either axial direction. -
FIG. 3 is a cutaway view that illustrates another embodiment of aslip 300. In this embodiment,teeth sections band 340 is disposed. The band orstrap 340 helps ensure that theslip 300, when axial force is exerted on it from both directions, fractures more evenly, providing substantially equal expansion and engagement of theteeth section slip 300 can provide substantially equal resistance to axial movement in either direction. -
FIGS. 4 and 5 are cross-sectional views along the central axis A-A of two other embodiments of aslip FIG. 4 , theteeth slip 400. As in theslip 300 ofFIG. 3 , a central section can be surrounded with astrap 340, not shown inFIG. 4 , for improved evenness of fracture and engagement with the surrounding tubular, although embodiments without the central section can be used. Unlike the teeth of the embodiments ofFIGS. 2 and 3 , which have a complex shape, theteeth slip 400 are simple triangular teeth, forming a right triangle perpendicular to the axis A-A with the right angle oriented toward the end of theslip 400. - An alternate embodiment is shown in
FIG. 5 . As in the embodiment ofFIG. 4 , theteeth sections central section 520 for the attachment of theband 340. The orientation of theteeth teeth central portion 520. - The number, shape, and configuration of teeth illustrated in
FIGS. 2-5 are illustrative and by way of example only, and any number, shape, and configuration of teeth can be used as desired, including orientation axially either toward the ends of the slip or toward the center. The use of wickers or teeth is illustrative and by way of example only. In some embodiments, other surface treatments other than wickers or teeth can be used to provide gripping ability for the slip. - The bi-directional slip and dual sealing systems described herein may be used in conjunction with any downhole tool used for sealing an annulus within a wellbore, such as frac-plugs, bridge plugs, or packers, for example.
- In conclusion, by using a single bidirectional slip surrounded by two sealing systems, various embodiments provide a downhole tool with reduced metal content, allowing faster mill up and less metal waste to fall downhole, but without sacrificing the ability to hold the downhole tool in place under high temperature and pressure conditions. The two sealing systems, in addition to doubly sealing with the surrounding tubular, provide boost force on the single slip in both directions, thus increasing the holding power of the single slip.
- While certain exemplary embodiments have been described in details and shown in the accompanying drawings, it is to be understood that such embodiments are merely illustrative of and not devised without departing from the basic scope thereof, which is determined by the claims that follow.
Claims (20)
1. A downhole tool for insertion into a tubular, comprising:
a non-metallic mandrel;
a bi-directional slip, disposed about an axis of the mandrel and configured to resist axial movement in either direction when activated;
a pair of non-metallic sealing systems, each capable of sealing with the tubular, activating a portion of the bi-directional slip, and disposed about the axis of the mandrel at opposite ends of the bi-directional slip.
2. The downhole tool of claim 1 , wherein each of the pair of non-metallic sealing systems comprises:
a sealing member, configured to expand radially upon the application of axial force on the sealing member; and
a pair of non-metallic element systems, disposed with opposite ends of the sealing member, configured to compress the sealing member upon the application of axial force on the element systems and to activate a portion of the bi-directional slip.
3. The downhole tool of claim 1 , wherein each of the pair of sealing systems comprises:
a compressible sealing member, disposed about the mandrel and configured to expand radially when compressed;
a non-metallic sealing element system, disposed about the mandrel between the sealing member and the slip, comprising:
a first cone, disposed adjacent to the sealing member;
a support ring;
an expansion ring; disposed between the first cone and the support ring;
a second cone, disposed between the support ring and the bi-directional slip, configured to activate an end of the slip.
4. The downhole tool of claim 1 , wherein the slip comprises:
a first section, configured to resist axial movement in first direction when activated; and
a second section, configured to resist axial movement in a second direction when activated, the second direction opposite the first direction.
5. The downhole tool of claim 1 , wherein the slip comprises:
a first section, configured to resist axial movement in first direction when activated;
a second section, configured to resist axial movement in a second direction when activated, the second direction opposite the first direction; and
a third section, disposed between the first section and the second section.
6. The downhole tool of claim 5 , wherein the slip further comprises:
a band disposed about the third section.
7. The downhole tool of claim 1 , wherein the slip comprises:
a first plurality of wickers, configured to resist axial movement of the slip in a first direction when any of the first plurality of wickers are engaged with an inner surface of the tubular; and
a second plurality of wickers, disposed with the first plurality of wickers and configured to resist axial movement of the slip in a second direction, opposite the first direction, when any of the second plurality of wickers are engaged with the inner surface of the tubular.
8. The downhole tool of claim 1 , wherein the downhole tool is a frac plug.
9. The downhole tool of claim 1 , wherein the downhole tool is bridge plug.
10. The downhole tool of claim 1 , wherein the downhole tool is a packer.
11. A method of setting a downhole tool in a tubular, comprising:
positioning the downhole tool at a desired location in the tubular;
expanding a first portion of a bidirectional slip of the downhole tool with a first sealing system of the downhole tool;
expanding a second portion of a bidirectional slip of the downhole tool with a second sealing system of the downhole tool;
engaging the first portion of the bi-directional slip with the tubular; and
engaging the second portion of the bidirectional slip with the tubular,
wherein the first portion of the slip is configured to resist movement along a central axis of the downhole tool in a first direction when engaged with the tubular, and
wherein the second portion of the slip is configured to resist movement along the central axis of the downhole tool in a second direction, opposite the first direction, when engaged with the tubular.
12. The method of claim 11 , wherein expanding a first portion of a bidirectional slip of the downhole tool over a first sealing system of the downhole tool comprises:
sealing the first sealing system with the tubular;
driving a conical element of the first sealing system into the first portion of the slip;
fracturing the first portion of the slip along a predetermined fracture zone; and
expanding the fractured first portion of the slip over a surface of the conical element.
13. The method of claim 11 , further comprising:
sealing the second sealing system with the tubular;
driving a conical element of the second sealing system into the second portion of the slip;
fracturing the second portion of the slip along a predetermined fracture zone; and
expanding the fractured second portion of the slip over a surface of the conical element of the second sealing system.
14. The method of claim 11 , wherein the first direction is toward the second portion of the slip, and the second direction is toward the first portion of the slip.
15. The method of claim 11 , wherein the first direction is away from the second portion of the slip and the second direction is away from the first portion of the slip.
16. A system for setting a downhole tool having a mandrel in a tubular, comprising:
a bi-directional slip, disposed about an axis of the mandrel and configured to resist axial movement in either direction when activated;
a pair of non-metallic element systems, each capable of activating a portion of the bi-directional slip and disposed about the axis of the mandrel at opposite ends of the bi-directional slip.
17. The system of claim 16 , wherein each of the pair of non-metallic element systems comprises:
a sealing member, configured to expand radially to seal with the tubular when compressed axially; and
a pair of non-metallic element subsystems, disposed with opposite ends of the sealing member, configured to compress the sealing member upon the application of axial force on the non-metallic element subsystems.
18. The system of claim 16 , wherein each of the pair of non-metallic element systems comprises:
a compressible sealing member, configured to expand radially when compressed;
a non-metallic sealing element subsystem, disposed coaxially between the sealing member and the slip, comprising:
a first non-metallic cone, disposed adjacent to the sealing member;
a non-metallic support ring;
a non-metallic expansion ring; disposed between the first non-metallic cone and the non-metallic support ring;
a second non-metallic cone, disposed between the non-metallic support ring and the bi-directional slip, configured to activate an end of the slip.
19. The system of claim 16 , wherein the slip comprises:
a first plurality of wickers, configured to resist axial movement of the slip in a first direction when any of the first plurality of wickers are engaged with an inner surface of the tubular; and
a second plurality of wickers, disposed with the first plurality of wickers and configured to resist axial movement of the slip in a second direction, opposite the first direction, when any of the second plurality of wickers are engaged with the inner surface of the tubular.
20. The system of claim 16 , wherein the slip comprises:
a first plurality of wickers, configured to resist axial movement of the slip in a first direction when any of the first plurality of wickers are engaged with an inner surface of the tubular; and
a second plurality of wickers, disposed with the first plurality of wickers and configured to resist axial movement of the slip in a second direction, opposite the first direction, when any of the second plurality of wickers are engaged with the inner surface of the tubular.
a band disposed about a central portion of the slip, between the first plurality of wickers and the second plurality of wickers.
Priority Applications (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US12/500,476 US20110005779A1 (en) | 2009-07-09 | 2009-07-09 | Composite downhole tool with reduced slip volume |
CA2704701A CA2704701A1 (en) | 2009-07-09 | 2010-05-18 | Composite downhole tool with reduced slip volume |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US12/500,476 US20110005779A1 (en) | 2009-07-09 | 2009-07-09 | Composite downhole tool with reduced slip volume |
Publications (1)
Publication Number | Publication Date |
---|---|
US20110005779A1 true US20110005779A1 (en) | 2011-01-13 |
Family
ID=43426623
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US12/500,476 Abandoned US20110005779A1 (en) | 2009-07-09 | 2009-07-09 | Composite downhole tool with reduced slip volume |
Country Status (2)
Country | Link |
---|---|
US (1) | US20110005779A1 (en) |
CA (1) | CA2704701A1 (en) |
Cited By (48)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20100155050A1 (en) * | 2008-12-23 | 2010-06-24 | Frazier W Lynn | Down hole tool |
US20100263876A1 (en) * | 2009-04-21 | 2010-10-21 | Frazier W Lynn | Combination down hole tool |
US20110079383A1 (en) * | 2009-10-05 | 2011-04-07 | Porter Jesse C | Interchangeable drillable tool |
US20110297368A1 (en) * | 2010-06-07 | 2011-12-08 | Weatherford/Lamb, Inc. | Swellable Packer Slip Mechanism |
USD657807S1 (en) * | 2011-07-29 | 2012-04-17 | Frazier W Lynn | Configurable insert for a downhole tool |
USD672794S1 (en) * | 2011-07-29 | 2012-12-18 | Frazier W Lynn | Configurable bridge plug insert for a downhole tool |
USD684612S1 (en) * | 2011-07-29 | 2013-06-18 | W. Lynn Frazier | Configurable caged ball insert for a downhole tool |
USD694281S1 (en) | 2011-07-29 | 2013-11-26 | W. Lynn Frazier | Lower set insert with a lower ball seat for a downhole plug |
USD694280S1 (en) | 2011-07-29 | 2013-11-26 | W. Lynn Frazier | Configurable insert for a downhole plug |
USD698370S1 (en) | 2011-07-29 | 2014-01-28 | W. Lynn Frazier | Lower set caged ball insert for a downhole plug |
USD703713S1 (en) * | 2011-07-29 | 2014-04-29 | W. Lynn Frazier | Configurable caged ball insert for a downhole tool |
WO2014186082A1 (en) * | 2013-05-14 | 2014-11-20 | Baker Hughes Incorporated | Slip with altering load distribution feature |
US8899317B2 (en) | 2008-12-23 | 2014-12-02 | W. Lynn Frazier | Decomposable pumpdown ball for downhole plugs |
US9062522B2 (en) | 2009-04-21 | 2015-06-23 | W. Lynn Frazier | Configurable inserts for downhole plugs |
WO2014004571A3 (en) * | 2012-06-28 | 2015-07-09 | Team Oil Tools, Lp | Downhole tool with composite slip system |
US9109428B2 (en) | 2009-04-21 | 2015-08-18 | W. Lynn Frazier | Configurable bridge plugs and methods for using same |
US9115549B2 (en) | 2012-06-28 | 2015-08-25 | Team Oil Tools, L.P. | Method and apparatus for injecting gas into a reservoir |
US9127527B2 (en) | 2009-04-21 | 2015-09-08 | W. Lynn Frazier | Decomposable impediments for downhole tools and methods for using same |
US9163477B2 (en) | 2009-04-21 | 2015-10-20 | W. Lynn Frazier | Configurable downhole tools and methods for using same |
US9181772B2 (en) | 2009-04-21 | 2015-11-10 | W. Lynn Frazier | Decomposable impediments for downhole plugs |
US9217319B2 (en) | 2012-05-18 | 2015-12-22 | Frazier Technologies, L.L.C. | High-molecular-weight polyglycolides for hydrocarbon recovery |
US9309744B2 (en) | 2008-12-23 | 2016-04-12 | Magnum Oil Tools International, Ltd. | Bottom set downhole plug |
USRE46028E1 (en) | 2003-05-15 | 2016-06-14 | Kureha Corporation | Method and apparatus for delayed flow or pressure change in wells |
US20160251921A1 (en) * | 2009-01-22 | 2016-09-01 | Petrowell Limited | Expandable Slip System |
US9441449B1 (en) | 2014-03-16 | 2016-09-13 | Elie Robert Abi Aad | Swellable packer |
US9506309B2 (en) | 2008-12-23 | 2016-11-29 | Frazier Ball Invention, LLC | Downhole tools having non-toxic degradable elements |
US9562415B2 (en) | 2009-04-21 | 2017-02-07 | Magnum Oil Tools International, Ltd. | Configurable inserts for downhole plugs |
US9587475B2 (en) | 2008-12-23 | 2017-03-07 | Frazier Ball Invention, LLC | Downhole tools having non-toxic degradable elements and their methods of use |
US9708878B2 (en) | 2003-05-15 | 2017-07-18 | Kureha Corporation | Applications of degradable polymer for delayed mechanical changes in wells |
US20170370176A1 (en) * | 2014-04-02 | 2017-12-28 | Magnum Oil Tools International, Ltd. | Split ring sealing assemblies |
US9976379B2 (en) | 2015-09-22 | 2018-05-22 | Halliburton Energy Services, Inc. | Wellbore isolation device with slip assembly |
US9976381B2 (en) | 2015-07-24 | 2018-05-22 | Team Oil Tools, Lp | Downhole tool with an expandable sleeve |
US10119360B2 (en) | 2016-03-08 | 2018-11-06 | Innovex Downhole Solutions, Inc. | Slip segment for a downhole tool |
US10156119B2 (en) | 2015-07-24 | 2018-12-18 | Innovex Downhole Solutions, Inc. | Downhole tool with an expandable sleeve |
US10227842B2 (en) | 2016-12-14 | 2019-03-12 | Innovex Downhole Solutions, Inc. | Friction-lock frac plug |
US10408012B2 (en) | 2015-07-24 | 2019-09-10 | Innovex Downhole Solutions, Inc. | Downhole tool with an expandable sleeve |
US10507478B2 (en) | 2016-03-30 | 2019-12-17 | The Patent Well LLC | Clear sprayable sealant for aircraft parts and assemblies |
US10605018B2 (en) | 2015-07-09 | 2020-03-31 | Halliburton Energy Services, Inc. | Wellbore anchoring assembly |
US10815749B2 (en) | 2016-05-12 | 2020-10-27 | Halliburton Energy Services, Inc. | Loosely assembled wellbore isolation assembly |
US10989016B2 (en) | 2018-08-30 | 2021-04-27 | Innovex Downhole Solutions, Inc. | Downhole tool with an expandable sleeve, grit material, and button inserts |
WO2021150547A1 (en) * | 2020-01-24 | 2021-07-29 | Halliburton Energy Services, Inc. | High performance regular and high expansion elements for oil and gas applications |
US11125039B2 (en) | 2018-11-09 | 2021-09-21 | Innovex Downhole Solutions, Inc. | Deformable downhole tool with dissolvable element and brittle protective layer |
US11203913B2 (en) | 2019-03-15 | 2021-12-21 | Innovex Downhole Solutions, Inc. | Downhole tool and methods |
US11261683B2 (en) | 2019-03-01 | 2022-03-01 | Innovex Downhole Solutions, Inc. | Downhole tool with sleeve and slip |
US11299957B2 (en) * | 2018-08-30 | 2022-04-12 | Avalon Research Ltd. | Plug for a coiled tubing string |
US11396787B2 (en) | 2019-02-11 | 2022-07-26 | Innovex Downhole Solutions, Inc. | Downhole tool with ball-in-place setting assembly and asymmetric sleeve |
US11572753B2 (en) | 2020-02-18 | 2023-02-07 | Innovex Downhole Solutions, Inc. | Downhole tool with an acid pill |
US11965391B2 (en) | 2018-11-30 | 2024-04-23 | Innovex Downhole Solutions, Inc. | Downhole tool with sealing ring |
Citations (10)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US2578900A (en) * | 1946-09-28 | 1951-12-18 | Baker Oil Tools Inc | Well packer |
US2714931A (en) * | 1951-08-08 | 1955-08-09 | Lane Wells Co | Removable bridging plug |
US3497003A (en) * | 1968-07-11 | 1970-02-24 | Schlumberger Technology Corp | Frangible solid slips with retaining band |
US3749167A (en) * | 1972-05-26 | 1973-07-31 | Schlumberger Technology Corp | Well tool anchoring apparatus |
US5884699A (en) * | 1996-02-26 | 1999-03-23 | Halliburton Energy Services, Inc. | Retrievable torque-through packer having high strength and reduced cross-sectional area |
US5944102A (en) * | 1996-03-06 | 1999-08-31 | Halliburton Energy Services, Inc. | High temperature high pressure retrievable packer |
US6302217B1 (en) * | 1998-01-08 | 2001-10-16 | Halliburton Energy Services, Inc. | Extreme service packer having slip actuated debris barrier |
US6581681B1 (en) * | 2000-06-21 | 2003-06-24 | Weatherford/Lamb, Inc. | Bridge plug for use in a wellbore |
US7124831B2 (en) * | 2001-06-27 | 2006-10-24 | Weatherford/Lamb, Inc. | Resin impregnated continuous fiber plug with non-metallic element system |
US7690424B2 (en) * | 2005-03-04 | 2010-04-06 | Petrowell Limited | Well bore anchors |
-
2009
- 2009-07-09 US US12/500,476 patent/US20110005779A1/en not_active Abandoned
-
2010
- 2010-05-18 CA CA2704701A patent/CA2704701A1/en not_active Abandoned
Patent Citations (10)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US2578900A (en) * | 1946-09-28 | 1951-12-18 | Baker Oil Tools Inc | Well packer |
US2714931A (en) * | 1951-08-08 | 1955-08-09 | Lane Wells Co | Removable bridging plug |
US3497003A (en) * | 1968-07-11 | 1970-02-24 | Schlumberger Technology Corp | Frangible solid slips with retaining band |
US3749167A (en) * | 1972-05-26 | 1973-07-31 | Schlumberger Technology Corp | Well tool anchoring apparatus |
US5884699A (en) * | 1996-02-26 | 1999-03-23 | Halliburton Energy Services, Inc. | Retrievable torque-through packer having high strength and reduced cross-sectional area |
US5944102A (en) * | 1996-03-06 | 1999-08-31 | Halliburton Energy Services, Inc. | High temperature high pressure retrievable packer |
US6302217B1 (en) * | 1998-01-08 | 2001-10-16 | Halliburton Energy Services, Inc. | Extreme service packer having slip actuated debris barrier |
US6581681B1 (en) * | 2000-06-21 | 2003-06-24 | Weatherford/Lamb, Inc. | Bridge plug for use in a wellbore |
US7124831B2 (en) * | 2001-06-27 | 2006-10-24 | Weatherford/Lamb, Inc. | Resin impregnated continuous fiber plug with non-metallic element system |
US7690424B2 (en) * | 2005-03-04 | 2010-04-06 | Petrowell Limited | Well bore anchors |
Cited By (60)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US10280703B2 (en) | 2003-05-15 | 2019-05-07 | Kureha Corporation | Applications of degradable polymer for delayed mechanical changes in wells |
US9708878B2 (en) | 2003-05-15 | 2017-07-18 | 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 |
US8496052B2 (en) | 2008-12-23 | 2013-07-30 | Magnum Oil Tools International, Ltd. | Bottom set down hole tool |
US8899317B2 (en) | 2008-12-23 | 2014-12-02 | W. Lynn Frazier | Decomposable pumpdown ball for downhole plugs |
US20100155050A1 (en) * | 2008-12-23 | 2010-06-24 | Frazier W Lynn | Down hole tool |
US9309744B2 (en) | 2008-12-23 | 2016-04-12 | Magnum Oil Tools International, Ltd. | Bottom set downhole plug |
USD697088S1 (en) | 2008-12-23 | 2014-01-07 | W. Lynn Frazier | Lower set insert for a downhole plug for use in a wellbore |
US9587475B2 (en) | 2008-12-23 | 2017-03-07 | Frazier Ball Invention, LLC | Downhole tools having non-toxic degradable elements and their methods of use |
US9506309B2 (en) | 2008-12-23 | 2016-11-29 | Frazier Ball Invention, LLC | Downhole tools having non-toxic degradable elements |
USD694282S1 (en) | 2008-12-23 | 2013-11-26 | W. Lynn Frazier | Lower set insert for a downhole plug for use in a wellbore |
US10267121B2 (en) * | 2009-01-22 | 2019-04-23 | Weatherford Technology Holdings, Llc | Expandable slip system |
US20160251921A1 (en) * | 2009-01-22 | 2016-09-01 | Petrowell Limited | Expandable Slip System |
US9062522B2 (en) | 2009-04-21 | 2015-06-23 | W. Lynn Frazier | Configurable inserts for downhole plugs |
US9562415B2 (en) | 2009-04-21 | 2017-02-07 | Magnum Oil Tools International, Ltd. | Configurable inserts for downhole plugs |
US9181772B2 (en) | 2009-04-21 | 2015-11-10 | W. Lynn Frazier | Decomposable impediments for downhole plugs |
US9109428B2 (en) | 2009-04-21 | 2015-08-18 | W. Lynn Frazier | Configurable bridge plugs and methods for using same |
US20100263876A1 (en) * | 2009-04-21 | 2010-10-21 | Frazier W Lynn | Combination down hole tool |
US9127527B2 (en) | 2009-04-21 | 2015-09-08 | W. Lynn Frazier | Decomposable impediments for downhole tools and methods for using same |
US9163477B2 (en) | 2009-04-21 | 2015-10-20 | W. Lynn Frazier | Configurable downhole tools and methods for using same |
US8408290B2 (en) * | 2009-10-05 | 2013-04-02 | Halliburton Energy Services, Inc. | Interchangeable drillable tool |
US20110079383A1 (en) * | 2009-10-05 | 2011-04-07 | Porter Jesse C | Interchangeable drillable tool |
US8397802B2 (en) * | 2010-06-07 | 2013-03-19 | Weatherford/Lamb, Inc. | Swellable packer slip mechanism |
US20110297368A1 (en) * | 2010-06-07 | 2011-12-08 | Weatherford/Lamb, Inc. | Swellable Packer Slip Mechanism |
USD703713S1 (en) * | 2011-07-29 | 2014-04-29 | W. Lynn Frazier | Configurable caged ball insert for a downhole tool |
USD684612S1 (en) * | 2011-07-29 | 2013-06-18 | W. Lynn Frazier | Configurable caged ball insert for a downhole tool |
USD672794S1 (en) * | 2011-07-29 | 2012-12-18 | Frazier W Lynn | Configurable bridge plug insert for a downhole tool |
USD657807S1 (en) * | 2011-07-29 | 2012-04-17 | Frazier W Lynn | Configurable insert for a downhole tool |
USD694281S1 (en) | 2011-07-29 | 2013-11-26 | W. Lynn Frazier | Lower set insert with a lower ball seat for a downhole plug |
USD694280S1 (en) | 2011-07-29 | 2013-11-26 | W. Lynn Frazier | Configurable insert for a downhole plug |
USD698370S1 (en) | 2011-07-29 | 2014-01-28 | W. Lynn Frazier | Lower set caged ball insert for a downhole plug |
US9217319B2 (en) | 2012-05-18 | 2015-12-22 | Frazier Technologies, L.L.C. | High-molecular-weight polyglycolides for hydrocarbon recovery |
WO2014004571A3 (en) * | 2012-06-28 | 2015-07-09 | Team Oil Tools, Lp | Downhole tool with composite slip system |
US9115549B2 (en) | 2012-06-28 | 2015-08-25 | Team Oil Tools, L.P. | Method and apparatus for injecting gas into a reservoir |
WO2014186082A1 (en) * | 2013-05-14 | 2014-11-20 | Baker Hughes Incorporated | Slip with altering load distribution feature |
GB2528418B (en) * | 2013-05-14 | 2018-01-24 | Baker Hughes Incoporated | Slip with altering load distribution feature |
GB2528418A (en) * | 2013-05-14 | 2016-01-20 | Baker Hughes Incoporated | Slip with altering load distribution feature |
US9441449B1 (en) | 2014-03-16 | 2016-09-13 | Elie Robert Abi Aad | Swellable packer |
US20170370176A1 (en) * | 2014-04-02 | 2017-12-28 | Magnum Oil Tools International, Ltd. | Split ring sealing assemblies |
US10662732B2 (en) * | 2014-04-02 | 2020-05-26 | Magnum Oil Tools International, Ltd. | Split ring sealing assemblies |
US10605018B2 (en) | 2015-07-09 | 2020-03-31 | Halliburton Energy Services, Inc. | Wellbore anchoring assembly |
US10156119B2 (en) | 2015-07-24 | 2018-12-18 | Innovex Downhole Solutions, Inc. | Downhole tool with an expandable sleeve |
US9976381B2 (en) | 2015-07-24 | 2018-05-22 | Team Oil Tools, Lp | Downhole tool with an expandable sleeve |
US10408012B2 (en) | 2015-07-24 | 2019-09-10 | Innovex Downhole Solutions, Inc. | Downhole tool with an expandable sleeve |
US9976379B2 (en) | 2015-09-22 | 2018-05-22 | Halliburton Energy Services, Inc. | Wellbore isolation device with slip assembly |
US10119360B2 (en) | 2016-03-08 | 2018-11-06 | Innovex Downhole Solutions, Inc. | Slip segment for a downhole tool |
US10507478B2 (en) | 2016-03-30 | 2019-12-17 | The Patent Well LLC | Clear sprayable sealant for aircraft parts and assemblies |
US10815749B2 (en) | 2016-05-12 | 2020-10-27 | Halliburton Energy Services, Inc. | Loosely assembled wellbore isolation assembly |
US10227842B2 (en) | 2016-12-14 | 2019-03-12 | Innovex Downhole Solutions, Inc. | Friction-lock frac plug |
US10989016B2 (en) | 2018-08-30 | 2021-04-27 | Innovex Downhole Solutions, Inc. | Downhole tool with an expandable sleeve, grit material, and button inserts |
US11299957B2 (en) * | 2018-08-30 | 2022-04-12 | Avalon Research Ltd. | Plug for a coiled tubing string |
US11125039B2 (en) | 2018-11-09 | 2021-09-21 | Innovex Downhole Solutions, Inc. | Deformable downhole tool with dissolvable element and brittle protective layer |
US11965391B2 (en) | 2018-11-30 | 2024-04-23 | Innovex Downhole Solutions, Inc. | Downhole tool with sealing ring |
US11396787B2 (en) | 2019-02-11 | 2022-07-26 | Innovex Downhole Solutions, Inc. | Downhole tool with ball-in-place setting assembly and asymmetric sleeve |
US11261683B2 (en) | 2019-03-01 | 2022-03-01 | Innovex Downhole Solutions, Inc. | Downhole tool with sleeve and slip |
US11203913B2 (en) | 2019-03-15 | 2021-12-21 | Innovex Downhole Solutions, Inc. | Downhole tool and methods |
WO2021150547A1 (en) * | 2020-01-24 | 2021-07-29 | Halliburton Energy Services, Inc. | High performance regular and high expansion elements for oil and gas applications |
GB2605896A (en) * | 2020-01-24 | 2022-10-19 | Halliburton Energy Services Inc | High performance regular and high expansion elements for oil and gas applications |
GB2605896B (en) * | 2020-01-24 | 2023-11-15 | Halliburton Energy Services Inc | High performance regular and high expansion elements for oil and gas applications |
US11572753B2 (en) | 2020-02-18 | 2023-02-07 | Innovex Downhole Solutions, Inc. | Downhole tool with an acid pill |
Also Published As
Publication number | Publication date |
---|---|
CA2704701A1 (en) | 2011-01-09 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US20110005779A1 (en) | Composite downhole tool with reduced slip volume | |
US7789135B2 (en) | Non-metallic mandrel and element system | |
US6769491B2 (en) | Anchoring and sealing system for a downhole tool | |
US7665516B2 (en) | Permanent anchoring device | |
US6827150B2 (en) | High expansion packer | |
CA2494290C (en) | Disposable downhole tool with segmented compression element and method | |
US6752216B2 (en) | Expandable packer, and method for seating an expandable packer | |
CA2873198C (en) | Multi-stage well isolation and fracturing | |
US6378606B1 (en) | High temperature high pressure retrievable packer with barrel slip | |
US9194209B2 (en) | Hydraulicaly fracturable downhole valve assembly and method for using same | |
US20170145780A1 (en) | Downhole Tool having Slips Set by Stacked Rings | |
US8875799B2 (en) | Covered retaining shoe configurations for use in a downhole tool |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
AS | Assignment |
Owner name: WEATHERFORD/LAMB, INC., TEXAS Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:LEMBCKE, JEFFREY;REEL/FRAME:022936/0772 Effective date: 20090701 |
|
STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |