CA2704701A1 - Composite downhole tool with reduced slip volume - Google Patents
Composite downhole tool with reduced slip volume Download PDFInfo
- Publication number
- CA2704701A1 CA2704701A1 CA2704701A CA2704701A CA2704701A1 CA 2704701 A1 CA2704701 A1 CA 2704701A1 CA 2704701 A CA2704701 A CA 2704701A CA 2704701 A CA2704701 A CA 2704701A CA 2704701 A1 CA2704701 A1 CA 2704701A1
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- Canada
- Prior art keywords
- slip
- downhole tool
- disposed
- sealing
- tubular
- 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
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- 239000002131 composite material Substances 0.000 title description 7
- 238000007789 sealing Methods 0.000 claims abstract description 87
- 229910052751 metal Inorganic materials 0.000 claims abstract description 19
- 230000003213 activating effect Effects 0.000 claims description 3
- 238000000034 method Methods 0.000 claims 5
- 238000003780 insertion Methods 0.000 claims 1
- 230000037431 insertion Effects 0.000 claims 1
- 239000002184 metal Substances 0.000 abstract description 12
- 230000009977 dual effect Effects 0.000 abstract description 3
- 239000012530 fluid Substances 0.000 description 9
- 241001331845 Equus asinus x caballus Species 0.000 description 6
- 238000004519 manufacturing process Methods 0.000 description 6
- 229910001141 Ductile iron Inorganic materials 0.000 description 3
- 238000003801 milling Methods 0.000 description 3
- 230000015572 biosynthetic process Effects 0.000 description 2
- 238000005755 formation reaction Methods 0.000 description 2
- 239000000463 material Substances 0.000 description 2
- 239000007787 solid Substances 0.000 description 2
- 244000099147 Ananas comosus Species 0.000 description 1
- 235000007119 Ananas comosus Nutrition 0.000 description 1
- 229910001018 Cast iron Inorganic materials 0.000 description 1
- 229910052782 aluminium Inorganic materials 0.000 description 1
- XAGFODPZIPBFFR-UHFFFAOYSA-N aluminium Chemical compound [Al] XAGFODPZIPBFFR-UHFFFAOYSA-N 0.000 description 1
- 239000004568 cement Substances 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 238000007373 indentation Methods 0.000 description 1
- 238000002955 isolation Methods 0.000 description 1
- 239000007769 metal material Substances 0.000 description 1
- 239000010814 metallic waste Substances 0.000 description 1
- 150000002739 metals Chemical class 0.000 description 1
- 230000005012 migration Effects 0.000 description 1
- 238000013508 migration Methods 0.000 description 1
- 230000000638 stimulation Effects 0.000 description 1
- 229920003051 synthetic elastomer Polymers 0.000 description 1
- 239000005061 synthetic rubber Substances 0.000 description 1
- 238000011282 treatment Methods 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
- E21B33/129—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 OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
- E21B33/134—Bridging plugs
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- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Earth Drilling (AREA)
Abstract
A single bi-directional 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
2
3 FIELD OF THE INVENTION
4 The present invention relates to the field of downhole tools, and in particular to downhole tools such as bridge plugs, frac-plugs, and packers.
8 An oil or gas well includes a wellbore extending into a well to some 9 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 11 further, the annular area formed between the casing and the borehole is typically 12 filled with cement to set the casing permanently in the wellbore.
Perforating the 13 casing allows production fluid to enter the wellbore and flow to the surface of the 14 well.
Downhole tools with sealing elements are placed within the wellbore 16 to isolate the production fluid or to manage production fluid flow through the well.
17 For example, a bridge plug or frac-plug placed within the wellbore can isolate upper 18 and lower sections of production zones. Bridge plugs and frac-plugs create a 19 pressure seal in the wellbore to allow pressurized fluids or solids to treat an isolated formation.
21 Packers are typically used to seal an annular area formed between 22 two co-axially disposed tubulars within a wellbore. For example, packers may seal 1 an annulus formed between production tubing disposed within wellbore casing.
2 Alternatively, packers may seal an annulus between the outside of a tubular and an 3 unlined borehole. Routine uses of packers include the protection of casing from 4 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 6 formations or leaks within a wellbore casing or multiple producing zones, thereby 7 preventing the migration of fluid between zones. Packers may also be used to hold 8 kill fluids or treating fluids within the casing annulus.
9 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 11 materials. A sealing member is typically made of a composite or synthetic rubber 12 malleable material that seals off an annulus within the wellbore to prevent the 13 passage of fluids. The sealing member is compressed or swells, thereby expanding 14 radially outward from the tool to engage and seal with a surrounding tubular.
Conventional bridge plug, frac plugs, and packers typically comprise a synthetic 16 sealing member located between upper and lower metallic retaining rings, 17 commonly known as slips, that prevent the downhole tool from moving up or down 18 in the wellbore.
19 One problem associated with conventional element systems of downhole tools arises when the tool is no longer needed to seal an annulus and 21 must be removed from the wellbore. For example, plugs and packers are 22 sometimes intended to be temporary and must be removed to access the wellbore.
23 Rather than de-actuate the tool and bring it to the surface of the well, the tool is 1 typically destroyed with a rotating milling or drilling device. As the mill contacts the 2 tool, the tool is "drilled up" or reduced to small pieces that are either washed out of 3 the wellbore or simply left at the bottom of the wellbore. The more metal parts 4 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 6 or drill bits.
7 Slips have been designed to reduce the amount of metal to reduce 8 drill up time. Although some have attempted to create composite material slips, 9 often pressure holding at temperature has been sacrificed to gain up drill up speed.
12 The conventional two slips of a downhole tool are combined into a 13 single bi-directional slip, thereby reducing the volume of metal and allowing an 14 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 16 sealing elements to the slip. In some embodiments, teeth sections of the slip are 17 separated by a substantially flat circumference section for placing a band around 18 the slip to improve fracturing uniformity. The teeth sections can have any of a 19 variety of configurations, including orientations axially away from the central portion of the slip and orientations axially toward the central portion of the slip.
23 Figure 1 is a cutaway view of a bridge plug according to the prior art;
1 Figure 2 is a cutaway view of a bridge plug according to one 2 embodiment;
3 Figure 3 is a cutaway view of a bi-directional slip according to one 4 embodiment;
Figure 4 is a cross-sectional view of a bi-directional slip according to 6 another embodiment; and 7 Figure 5 is a cross-sectional view of a bi-directional slip according to 8 yet another embodiment.
DESCRIPTION OF EMBODIMENTS
11 Fig. 1 is a cutaway view of a conventional bridge plug 100 according 12 to the prior art. The bridge plug 100 comprises a mandrel 110, about which are 13 disposed various elements, which are typically formed of metal, but can be made of 14 a composite material, such as is described in U.S. Patent No. 7,124,831.
Even when most of the bridge plug 100 is made of composite materials, the two slips 16 are typically made of metal, such as a ductile cast iron.
17 As shown in Fig. 1, a sealing member 120 and other related elements 18 125 are disposed about the mandrel 110. Axial force through the slips 130 and the 19 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 21 to each other, expand to engage with the surrounding tubular and help retain the 22 downhole tool in place in the wellbore. Boost forces from the sealing member 120 23 on the slips 130 increase their holding ability. As described above, the two slips 130 1 are made of metal, typically a ductile cast iron, and increase the mill up time of the 2 downhole tool 100.
3 Turning to Fig. 2, a cutaway view illustrates an improved downhole 4 tool 200 that uses a single bi-directional slip with reduced metal volume, allowing faster mill up time, but providing sufficient retaining ability against uphole and 6 downhole forces when engaged with the surrounding tubular. Instead of confining a 7 single sealing member 120 with two slips 130, in this embodiment, a single slip 210 8 is confined by two sealing systems 220, as described in detail below. The downhole 9 tool 200 can be configured as a bridge plug, a frac plug, a packer, or any other desired downhole tool.
11 As with the conventional downhole tool 100, the downhole tool 200 12 uses a mandrel 110, disposing the remainder of the downhole tool 200 about the 13 mandrel 110. Although shown in Fig. 2 as a hollow core mandrel 110, the mandrel 14 110 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, 16 including the mandrel 110 and the sealing systems 220, is typically non-metallic, 17 and the non-metallic elements are usually manufactured from one or more 18 composite materials.
19 Instead of two unidirectional slips 130, each of which resists movement in a single axial direction and tends to disengage from the surrounding 21 tubular in the opposite axial direction, the embodiment illustrated in Fig.
2 uses a 22 single bi-directional slip 210 that resists movement in either axial direction once 23 activated by the sealing systems 220 to engage with the surrounding tubular.
8 An oil or gas well includes a wellbore extending into a well to some 9 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 11 further, the annular area formed between the casing and the borehole is typically 12 filled with cement to set the casing permanently in the wellbore.
Perforating the 13 casing allows production fluid to enter the wellbore and flow to the surface of the 14 well.
Downhole tools with sealing elements are placed within the wellbore 16 to isolate the production fluid or to manage production fluid flow through the well.
17 For example, a bridge plug or frac-plug placed within the wellbore can isolate upper 18 and lower sections of production zones. Bridge plugs and frac-plugs create a 19 pressure seal in the wellbore to allow pressurized fluids or solids to treat an isolated formation.
21 Packers are typically used to seal an annular area formed between 22 two co-axially disposed tubulars within a wellbore. For example, packers may seal 1 an annulus formed between production tubing disposed within wellbore casing.
2 Alternatively, packers may seal an annulus between the outside of a tubular and an 3 unlined borehole. Routine uses of packers include the protection of casing from 4 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 6 formations or leaks within a wellbore casing or multiple producing zones, thereby 7 preventing the migration of fluid between zones. Packers may also be used to hold 8 kill fluids or treating fluids within the casing annulus.
9 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 11 materials. A sealing member is typically made of a composite or synthetic rubber 12 malleable material that seals off an annulus within the wellbore to prevent the 13 passage of fluids. The sealing member is compressed or swells, thereby expanding 14 radially outward from the tool to engage and seal with a surrounding tubular.
Conventional bridge plug, frac plugs, and packers typically comprise a synthetic 16 sealing member located between upper and lower metallic retaining rings, 17 commonly known as slips, that prevent the downhole tool from moving up or down 18 in the wellbore.
19 One problem associated with conventional element systems of downhole tools arises when the tool is no longer needed to seal an annulus and 21 must be removed from the wellbore. For example, plugs and packers are 22 sometimes intended to be temporary and must be removed to access the wellbore.
23 Rather than de-actuate the tool and bring it to the surface of the well, the tool is 1 typically destroyed with a rotating milling or drilling device. As the mill contacts the 2 tool, the tool is "drilled up" or reduced to small pieces that are either washed out of 3 the wellbore or simply left at the bottom of the wellbore. The more metal parts 4 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 6 or drill bits.
7 Slips have been designed to reduce the amount of metal to reduce 8 drill up time. Although some have attempted to create composite material slips, 9 often pressure holding at temperature has been sacrificed to gain up drill up speed.
12 The conventional two slips of a downhole tool are combined into a 13 single bi-directional slip, thereby reducing the volume of metal and allowing an 14 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 16 sealing elements to the slip. In some embodiments, teeth sections of the slip are 17 separated by a substantially flat circumference section for placing a band around 18 the slip to improve fracturing uniformity. The teeth sections can have any of a 19 variety of configurations, including orientations axially away from the central portion of the slip and orientations axially toward the central portion of the slip.
23 Figure 1 is a cutaway view of a bridge plug according to the prior art;
1 Figure 2 is a cutaway view of a bridge plug according to one 2 embodiment;
3 Figure 3 is a cutaway view of a bi-directional slip according to one 4 embodiment;
Figure 4 is a cross-sectional view of a bi-directional slip according to 6 another embodiment; and 7 Figure 5 is a cross-sectional view of a bi-directional slip according to 8 yet another embodiment.
DESCRIPTION OF EMBODIMENTS
11 Fig. 1 is a cutaway view of a conventional bridge plug 100 according 12 to the prior art. The bridge plug 100 comprises a mandrel 110, about which are 13 disposed various elements, which are typically formed of metal, but can be made of 14 a composite material, such as is described in U.S. Patent No. 7,124,831.
Even when most of the bridge plug 100 is made of composite materials, the two slips 16 are typically made of metal, such as a ductile cast iron.
17 As shown in Fig. 1, a sealing member 120 and other related elements 18 125 are disposed about the mandrel 110. Axial force through the slips 130 and the 19 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 21 to each other, expand to engage with the surrounding tubular and help retain the 22 downhole tool in place in the wellbore. Boost forces from the sealing member 120 23 on the slips 130 increase their holding ability. As described above, the two slips 130 1 are made of metal, typically a ductile cast iron, and increase the mill up time of the 2 downhole tool 100.
3 Turning to Fig. 2, a cutaway view illustrates an improved downhole 4 tool 200 that uses a single bi-directional slip with reduced metal volume, allowing faster mill up time, but providing sufficient retaining ability against uphole and 6 downhole forces when engaged with the surrounding tubular. Instead of confining a 7 single sealing member 120 with two slips 130, in this embodiment, a single slip 210 8 is confined by two sealing systems 220, as described in detail below. The downhole 9 tool 200 can be configured as a bridge plug, a frac plug, a packer, or any other desired downhole tool.
11 As with the conventional downhole tool 100, the downhole tool 200 12 uses a mandrel 110, disposing the remainder of the downhole tool 200 about the 13 mandrel 110. Although shown in Fig. 2 as a hollow core mandrel 110, the mandrel 14 110 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, 16 including the mandrel 110 and the sealing systems 220, is typically non-metallic, 17 and the non-metallic elements are usually manufactured from one or more 18 composite materials.
19 Instead of two unidirectional slips 130, each of which resists movement in a single axial direction and tends to disengage from the surrounding 21 tubular in the opposite axial direction, the embodiment illustrated in Fig.
2 uses a 22 single bi-directional slip 210 that resists movement in either axial direction once 23 activated by the sealing systems 220 to engage with the surrounding tubular.
5 1 Although made of metal, such as a ductile cast iron, the single slip 210 contains 2 less metal than the conventional pair of slips 130.
3 To provide sealing with the tubular, the downhole tool 200 uses two 4 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
3 To provide sealing with the tubular, the downhole tool 200 uses two 4 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
6 provides boost forces to the slip 210, increasing its ability to engage with the tubular
7 and hold the downhole tool 200 in place under high pressure.
8 Each sealing system 220 includes a sealing member 225, which is a
9 malleable, synthetic element. The sealing member 225 can have any desired configuration to seal an annulus within the wellbore. For example, the sealing 11 member 225 can include grooves, ridges, indentations, or protrusions designed to 12 allow the sealing member 225 to conform to variations in the shape of the interior of 13 the surrounding tubular. The sealing member is capable in one embodiment of 14 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 16 used, as well.
17 As illustrated in Fig. 2, according to one embodiment each sealing 18 system 220 comprises, in addition to the sealing member 225, a cone 221 and two 19 each of cones 224, expansion rings 223, and support rings 222. In other embodiments, a second cone 221 is also included. In the embodiment illustrated in 21 Fig. 2, axial force is applied to the sealing system distal to the slip 210 by either a 22 mule shoe 250 or a setting ring 240 and a setting tool (not shown), as described 23 below. In the embodiment with a second cone 221, the additional cone 221 is 1 interposed between the setting ring 240 and support ring 230. Such an 2 embodiment would allow manufacture of a sealing system 220 that could be used 3 unchanged both in downhole tools such as the downhole tool of Fig. 2 and also in 4 conventional downhole tools such as illustrated in Fig. 1.
The sealing system 220, as illustrated in Fig. 2, transfers axial force 6 onto the sealing member 225, compressing the sealing member 225 and thereby 7 sealing with the surrounding tubular. Each cone 224 transfers axial force from the 8 rest of the sealing system 220 onto the sealing member 225, compressing the 9 sealing member 225, and causing the sealing member 225 to expand radially toward the inner surface of the surrounding tubular, sealing with the surrounding 11 tubular.
12 The expansion ring 223 flows and expands in one embodiment across 13 a tapered surface of the cone 224, applying a collapse load through the cone 224 14 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 16 rotating when milling up the downhole tool 200, reducing the mill up time.
The cone 17 224 thus transfers axial force from the expansion ring 223 to the sealing member 18 225 to cause radial expansion of the sealing member 225.
19 The support ring 222 transfers axial force to the expansion ring 223.
In one embodiment, the support ring 222 comprises sections that are designed to 21 hinge radially outwardly, toward the surrounding tubular as sections are forced 22 across a tapered section of the expansion ring 223. At full deployment, the sections 23 expand outwardly sufficient to engage the surrounding tubular.
1 The cone 221 transfers axial force to the support ring 222, forcing it 2 across the expansion ring 223 and causing the support ring 222 to expand as 3 described above. The cone 221 proximal to the slip 210 in turn receives axial force 4 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 6 downhole tool 200, and is typically threadedly attached to the mandrel 110.
The 7 mule shoe 250 is typically pinned in position on the mandrel 110.
8 The setting ring 240 is an annular member that provides a 9 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 11 the sealing system 220. In one embodiment, the support ring 230 has an outer 12 diameter less than the outer diameter of the setting ring 240, providing a shoulder 13 for engagement with the setting tool, which thus slips over the support ring 240 to 14 engage with the shoulder of the setting ring 240 to transfer force from the setting tool to the sealing system 220.
16 The downhole tool 200 can be installed in a weilbore with any desired 17 non-rigid system, such as electric wireline or coiled tubing. A setting tool, such as a 18 Baker E-4 Wireline Setting Assembly commercially available from Baker Hughes, 19 Inc., connects to an upper portion of the mandrel 110. Specifically, an outer movable portion of the setting tool is disposed about the outer diameter of the 21 support ring 230, abutting the first end of the setting ring 240. An inner portion of 22 the setting tool is fastened about the outer diameter of the support ring 230. The 23 setting tool and downhole tool 200 are then run into the well casing to the desired 1 depth where the downhole tool 200 is to be installed.
2 To set or activate the downhole tool 200, the mandrel 110 is held by 3 the wireline, through the inner portion of the setting tool, as an axial force is applied 4 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 6 relative to the mandrel 110.
7 The force asserted against the setting ring 240 is transmitted by the 8 setting ring 240. An equal and opposite force is asserted by the stationary mule 9 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 11 expand and to seal with the surrounding tubular. The force is further transmitted to 12 the slip 210, activating each end of the slip 210 by causing each end of the slip 210 13 to expand and to engage with the surrounding tubular, setting the slip 210 and thus 14 the downhole tool as a whole.
The slip 210 fractures under radial stress. The slip 240 in one 16 embodiment, illustrated in Fig. 2, has a pineapple configuration that includes at least 17 one and typically a plurality of recessed grooves 212, milled or otherwise formed 18 therein as fracture zones, allowing the slip 210 to fracture along the grooves 212 to 19 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 21 mandrel 110. An outer surface of the slip can include two or more outwardly, 22 extending wickers, comprising serrations or edge teeth, with at least one of the 23 wickers oriented toward the setting ring 240, to resist uphole axial movement, and 1 at least one of the wickers oriented toward the mule shoe 250, to resist downhole 2 axial movement. As each end of the slip 210 is driven across the cones 221, the 3 cone 221 drives that end of the slip radially outward from the mandrel 110, in 4 addition to providing axial force through the cones 221 to the support rings 222, and thus to the sealing member 225.
6 In another embodiment, the sealing system 220 illustrated proximal to 7 the mule shoe 250 in Fig. 2 can be replaced with a bias piston. Because such a 8 biasing piston is more complicated than the sealing system 220, the use of a 9 second sealing system 220 instead of a biasing piston is preferred.
The slip 210 of Fig. 2 is illustrated with circumferential rows of wickers 11 211 oriented to resist axially downhole movement adjacent to rows of teeth 12 oriented to resist axially uphole movement. The tooth configuration of the slip 210 13 in Fig. 2 is illustrative and by way of example only. In particular, the number, shape, 14 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 16 example, instead of biasing the teeth 211 and 213 towards either end of the 17 downhole tool 200, the teeth 211 and 213 can extend radially perpendicular from a 18 central axis of the slip 210 and resist movement in either axial direction.
19 Fig. 3 is a cutaway view that illustrates another embodiment of a slip 300. In this embodiment, teeth sections 310 and 330 are separated by a central 21 portion with a substantially flat circumferential configuration around which a band 22 340 is disposed. The band or strap 340 helps ensure that the slip 300, when axial 23 force is exerted on it from both directions, fractures more evenly, providing 1 substantially equal expansion and engagement of the teeth section 310 and 330.
2 Thus, the slip 300 can provide substantially equal resistance to axial movement in 3 either direction.
4 Figs. 4 and 5 are cross-sectional views along the central axis A-A of two other embodiments of a slip 400 and 500. In Fig. 4, the teeth 410 and 430 are 6 oriented toward each end of the slip 400. As in the slip 300 of Fig. 3, a central 7 section can be surrounded with a strap 340, not shown in Fig. 4, for improved 8 evenness of fracture and engagement with the surrounding tubular, although 9 embodiments without the central section can be used. Unlike the teeth of the embodiments of Figs. 2 and 3, which have a complex shape, the teeth 410 and 11 of slip 400 are simple triangular teeth, forming a right triangle perpendicular to the 12 axis A-A with the right angle oriented toward the end of the slip 400.
13 An alternate embodiment is shown in Fig. 5. As in the embodiment of 14 Fig. 4, 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 16 teeth 510 and 530 are reversed from the orientation of the teeth 410 and 430, so 17 that the teeth are oriented toward the central portion 520.
18 The number, shape, and configuration of teeth illustrated in Figs. 2-5 19 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 21 toward the ends of the slip or toward the center. The use of wickers or teeth is 22 illustrative and by way of example only. In some embodiments, other surface 23 treatments other than wickers or teeth can be used to provide gripping ability for the 1 slip.
2 The bi-directional slip and dual sealing systems described herein may 3 be used in conjunction with any downhole tool used for sealing an annulus within a 4 wellbore, such as frac-plugs, bridge plugs, or packers, for example.
In conclusion, by using a single bi-directional slip surrounded by two 6 sealing systems, various embodiments provide a downhole tool with reduced metal 7 content, allowing faster mill up and less metal waste to fall downhole, but without 8 sacrificing the ability to hold the downhole tool in place under high temperature and 9 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 11 increasing the holding power of the single slip.
17 As illustrated in Fig. 2, according to one embodiment each sealing 18 system 220 comprises, in addition to the sealing member 225, a cone 221 and two 19 each of cones 224, expansion rings 223, and support rings 222. In other embodiments, a second cone 221 is also included. In the embodiment illustrated in 21 Fig. 2, axial force is applied to the sealing system distal to the slip 210 by either a 22 mule shoe 250 or a setting ring 240 and a setting tool (not shown), as described 23 below. In the embodiment with a second cone 221, the additional cone 221 is 1 interposed between the setting ring 240 and support ring 230. Such an 2 embodiment would allow manufacture of a sealing system 220 that could be used 3 unchanged both in downhole tools such as the downhole tool of Fig. 2 and also in 4 conventional downhole tools such as illustrated in Fig. 1.
The sealing system 220, as illustrated in Fig. 2, transfers axial force 6 onto the sealing member 225, compressing the sealing member 225 and thereby 7 sealing with the surrounding tubular. Each cone 224 transfers axial force from the 8 rest of the sealing system 220 onto the sealing member 225, compressing the 9 sealing member 225, and causing the sealing member 225 to expand radially toward the inner surface of the surrounding tubular, sealing with the surrounding 11 tubular.
12 The expansion ring 223 flows and expands in one embodiment across 13 a tapered surface of the cone 224, applying a collapse load through the cone 224 14 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 16 rotating when milling up the downhole tool 200, reducing the mill up time.
The cone 17 224 thus transfers axial force from the expansion ring 223 to the sealing member 18 225 to cause radial expansion of the sealing member 225.
19 The support ring 222 transfers axial force to the expansion ring 223.
In one embodiment, the support ring 222 comprises sections that are designed to 21 hinge radially outwardly, toward the surrounding tubular as sections are forced 22 across a tapered section of the expansion ring 223. At full deployment, the sections 23 expand outwardly sufficient to engage the surrounding tubular.
1 The cone 221 transfers axial force to the support ring 222, forcing it 2 across the expansion ring 223 and causing the support ring 222 to expand as 3 described above. The cone 221 proximal to the slip 210 in turn receives axial force 4 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 6 downhole tool 200, and is typically threadedly attached to the mandrel 110.
The 7 mule shoe 250 is typically pinned in position on the mandrel 110.
8 The setting ring 240 is an annular member that provides a 9 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 11 the sealing system 220. In one embodiment, the support ring 230 has an outer 12 diameter less than the outer diameter of the setting ring 240, providing a shoulder 13 for engagement with the setting tool, which thus slips over the support ring 240 to 14 engage with the shoulder of the setting ring 240 to transfer force from the setting tool to the sealing system 220.
16 The downhole tool 200 can be installed in a weilbore with any desired 17 non-rigid system, such as electric wireline or coiled tubing. A setting tool, such as a 18 Baker E-4 Wireline Setting Assembly commercially available from Baker Hughes, 19 Inc., connects to an upper portion of the mandrel 110. Specifically, an outer movable portion of the setting tool is disposed about the outer diameter of the 21 support ring 230, abutting the first end of the setting ring 240. An inner portion of 22 the setting tool is fastened about the outer diameter of the support ring 230. The 23 setting tool and downhole tool 200 are then run into the well casing to the desired 1 depth where the downhole tool 200 is to be installed.
2 To set or activate the downhole tool 200, the mandrel 110 is held by 3 the wireline, through the inner portion of the setting tool, as an axial force is applied 4 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 6 relative to the mandrel 110.
7 The force asserted against the setting ring 240 is transmitted by the 8 setting ring 240. An equal and opposite force is asserted by the stationary mule 9 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 11 expand and to seal with the surrounding tubular. The force is further transmitted to 12 the slip 210, activating each end of the slip 210 by causing each end of the slip 210 13 to expand and to engage with the surrounding tubular, setting the slip 210 and thus 14 the downhole tool as a whole.
The slip 210 fractures under radial stress. The slip 240 in one 16 embodiment, illustrated in Fig. 2, has a pineapple configuration that includes at least 17 one and typically a plurality of recessed grooves 212, milled or otherwise formed 18 therein as fracture zones, allowing the slip 210 to fracture along the grooves 212 to 19 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 21 mandrel 110. An outer surface of the slip can include two or more outwardly, 22 extending wickers, comprising serrations or edge teeth, with at least one of the 23 wickers oriented toward the setting ring 240, to resist uphole axial movement, and 1 at least one of the wickers oriented toward the mule shoe 250, to resist downhole 2 axial movement. As each end of the slip 210 is driven across the cones 221, the 3 cone 221 drives that end of the slip radially outward from the mandrel 110, in 4 addition to providing axial force through the cones 221 to the support rings 222, and thus to the sealing member 225.
6 In another embodiment, the sealing system 220 illustrated proximal to 7 the mule shoe 250 in Fig. 2 can be replaced with a bias piston. Because such a 8 biasing piston is more complicated than the sealing system 220, the use of a 9 second sealing system 220 instead of a biasing piston is preferred.
The slip 210 of Fig. 2 is illustrated with circumferential rows of wickers 11 211 oriented to resist axially downhole movement adjacent to rows of teeth 12 oriented to resist axially uphole movement. The tooth configuration of the slip 210 13 in Fig. 2 is illustrative and by way of example only. In particular, the number, shape, 14 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 16 example, instead of biasing the teeth 211 and 213 towards either end of the 17 downhole tool 200, the teeth 211 and 213 can extend radially perpendicular from a 18 central axis of the slip 210 and resist movement in either axial direction.
19 Fig. 3 is a cutaway view that illustrates another embodiment of a slip 300. In this embodiment, teeth sections 310 and 330 are separated by a central 21 portion with a substantially flat circumferential configuration around which a band 22 340 is disposed. The band or strap 340 helps ensure that the slip 300, when axial 23 force is exerted on it from both directions, fractures more evenly, providing 1 substantially equal expansion and engagement of the teeth section 310 and 330.
2 Thus, the slip 300 can provide substantially equal resistance to axial movement in 3 either direction.
4 Figs. 4 and 5 are cross-sectional views along the central axis A-A of two other embodiments of a slip 400 and 500. In Fig. 4, the teeth 410 and 430 are 6 oriented toward each end of the slip 400. As in the slip 300 of Fig. 3, a central 7 section can be surrounded with a strap 340, not shown in Fig. 4, for improved 8 evenness of fracture and engagement with the surrounding tubular, although 9 embodiments without the central section can be used. Unlike the teeth of the embodiments of Figs. 2 and 3, which have a complex shape, the teeth 410 and 11 of slip 400 are simple triangular teeth, forming a right triangle perpendicular to the 12 axis A-A with the right angle oriented toward the end of the slip 400.
13 An alternate embodiment is shown in Fig. 5. As in the embodiment of 14 Fig. 4, 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 16 teeth 510 and 530 are reversed from the orientation of the teeth 410 and 430, so 17 that the teeth are oriented toward the central portion 520.
18 The number, shape, and configuration of teeth illustrated in Figs. 2-5 19 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 21 toward the ends of the slip or toward the center. The use of wickers or teeth is 22 illustrative and by way of example only. In some embodiments, other surface 23 treatments other than wickers or teeth can be used to provide gripping ability for the 1 slip.
2 The bi-directional slip and dual sealing systems described herein may 3 be used in conjunction with any downhole tool used for sealing an annulus within a 4 wellbore, such as frac-plugs, bridge plugs, or packers, for example.
In conclusion, by using a single bi-directional slip surrounded by two 6 sealing systems, various embodiments provide a downhole tool with reduced metal 7 content, allowing faster mill up and less metal waste to fall downhole, but without 8 sacrificing the ability to hold the downhole tool in place under high temperature and 9 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 11 increasing the holding power of the single slip.
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; and 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.
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; and 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.
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; and 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; and a second cone, disposed between the support ring and the bi-directional slip, configured to activate an end of the slip.
a compressible sealing member, disposed about the mandrel and configured to expand radially when compressed; and 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; and 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, 2, or 3, 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.
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, 2, or 3, 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.
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 to 5, wherein the slip further comprises a band disposed about the third section.
7. The downhole tool of claim 1, 2, or 3, 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 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 any one of claims 1 to 7, wherein the downhole tool is a frac plug.
9. The downhole tool of any one of claims 1 to 7, wherein the downhole tool is bridge plug.
10. The downhole tool of any one of claims 1 to 7, 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 bi-directional slip of the downhole tool with a first sealing system of the downhole tool;
expanding a second portion of a bi-directional 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 bi-directional 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.
positioning the downhole tool at a desired location in the tubular;
expanding a first portion of a bi-directional slip of the downhole tool with a first sealing system of the downhole tool;
expanding a second portion of a bi-directional 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 bi-directional 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 bi-directional 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.
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 or 12, 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.
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, 12, or 13, 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, 12, or 13, 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; and 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.
a bi-directional slip, disposed about an axis of the mandrel and configured to resist axial movement in either direction when activated; and 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.
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; and 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; and 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.
a compressible sealing member, configured to expand radially when compressed; and 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; and 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, 17, or 18, 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 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, 17, or 18, 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;
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; and a band disposed about a central portion of the slip, between the first plurality of wickers and the second plurality of wickers.
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;
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; and a band disposed about a central portion of the slip, between the first plurality of wickers and the second plurality of wickers.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US12/500,476 | 2009-07-09 | ||
| US12/500,476 US20110005779A1 (en) | 2009-07-09 | 2009-07-09 | Composite downhole tool with reduced slip volume |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2704701A1 true CA2704701A1 (en) | 2011-01-09 |
Family
ID=43426623
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2704701A Abandoned CA2704701A1 (en) | 2009-07-09 | 2010-05-18 | Composite downhole tool with reduced slip volume |
Country Status (2)
| Country | Link |
|---|---|
| US (1) | US20110005779A1 (en) |
| CA (1) | CA2704701A1 (en) |
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| Publication number | Publication date |
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| US20110005779A1 (en) | 2011-01-13 |
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| EEER | Examination request | ||
| FZDE | Discontinued |
Effective date: 20130711 |