US20010015277A1 - Packer - Google Patents
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- US20010015277A1 US20010015277A1 US09/746,531 US74653100A US2001015277A1 US 20010015277 A1 US20010015277 A1 US 20010015277A1 US 74653100 A US74653100 A US 74653100A US 2001015277 A1 US2001015277 A1 US 2001015277A1
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- United States
- Prior art keywords
- packer
- housing
- annulus
- fluid
- pressure
- 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.)
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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
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/11—Perforators; Permeators
- E21B43/116—Gun or shaped-charge perforators
-
- 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
- E21B33/126—Packers; Plugs with fluid-pressure-operated elastic cup or skirt
-
- 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
- E21B33/1295—Packers; Plugs with mechanical slips for hooking into the casing actuated by fluid pressure
-
- 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
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/06—Valve arrangements for boreholes or wells in wells
- E21B34/063—Valve or closure with destructible element, e.g. frangible disc
Definitions
- the invention relates to a packer.
- a tubular test string 10 may be inserted into a wellbore that extends into the formation 31 .
- the test string 10 may include a perforating gun 30 that is used to penetrate a well casing 12 and form fractures 29 in the formation 31 .
- the test string 10 may be attached to, for example, a retrievable weight set packer 27 that has an annular elastomer ring 26 to form a seal (when compressed) between the exterior of the test string 10 and the internal surface of the well casing 12 , i.e., the packer 27 seals off an annular region called an annulus 16 of the well.
- a recorder 11 of the test string 10 may take measurements of the test zone pressure.
- the test string 10 typically includes valves to control the flow of fluid into and out of a central passageway of the test string 10 .
- an in-line ball valve 22 may control the flow of well fluid from the test zone 33 up through the central passageway of the test string 10 .
- a circulation valve 20 may control fluid communication between the annulus 16 and the central passageway of the test string 10 .
- the ball valve 22 and the circulation valve 20 may be controlled by commands (e.g., “open valve” or “close valve”) that are sent downhole from the surface of the well.
- each command may be encoded into a predetermined signature of pressure pulses 34 see (FIG. 2) that are transmitted downhole via hydrostatic fluid that is present in the annulus 16 .
- a sensor 25 may receive the pressure pulses 34 so that the command may be extracted by electronics of the string 10 . Afterwards, electronics and hydraulics of the test string 10 operate the valves 20 and 22 to execute the command.
- Two general types of packers typically may be used: the retrievable weight set packer 27 that is depicted in FIG. 1 and a permanent hydraulically set packer 60 that is depicted in FIG. 3.
- an upward force and/or a rotational force may be applied to the string 10 to actuate a mechanism (of the string 10 ) to release the weight of the string 10 upon the ring 26 .
- test string 10 to set the packer 27 may present difficulties for a highly deviated wellbore and for a subsea well in which a vessel is drifting up and down, a movement that introduces additional motion to the test string 10 .
- Additional drill collars 44 may be required to compress the ring 26 .
- Slip joints 46 may be needed to compensate for expansion and contraction of the string 10 .
- the hydraulically set packer 60 may be set by a setting tool that is run downhole on a wireline, or alternatively, the hydraulically set packer 60 may be run downhole on a tubing and set by establishing a predetermined pressure differential between the central passageway of the tubing and the annulus 16 .
- the packer 60 typically remains permanently in the wellbore after being set, a factor that may affect the number of features that are included with the packer 60 .
- a separate downhole trip typically is required to set the packer 60 .
- a special tool may be run downhole with the packer 60 to set the packer 60 in one downhole trip, and afterwards, another downhole trip may be required to run the test string 10 . Because the test string 10 must pass through the inner diameter of a seal bore 62 of the packer 60 , the outer diameter of the perforating gun 30 may be limited, and stinger seals 52 of the test string 10 may be damaged.
- a packer for use inside a casing of a subterranean well includes a resilient element, a housing and a rupture disk.
- the resilient element is adapted to seal off an annulus of the well when compressed
- the housing is adapted to compress the resilient element in response to a pressure exerted by fluid of the annulus on a piston head of the housing.
- the housing includes a port for establishing fluid communication with the annulus.
- the rupture disk is adapted to prevent the fluid in the annulus from entering the port and contacting the piston head until the pressure exerted by the fluid exceeds a predefined threshold and ruptures the rupture disk.
- a method for setting a packer in a subterranean well includes isolating a resilient element from pressure being exerted from a fluid in an annulus of the well until the resilient element is at a predefined depth in the well. When the resilient element is at the predefined depth, the fluid in the annulus is allowed to compress the resilient element to seal off the annulus.
- FIGS. 1 and 3 are schematic views of test strings of the prior art in wells being tested.
- FIG. 2 is a waveform illustrating a pressure pulse command for a tool of the test strings of FIGS. 1 and 3.
- FIGS. 4 is a schematic view of a test string in a well being tested according to an embodiment of the invention.
- FIGS. 5, 7, and 10 are schematic views of a packer of the test string of FIG. 4 according to an embodiment of the invention.
- FIG. 6 is a detailed view of a connection between a tubing and a fastener of the packer of FIG. 4.
- FIG. 8 is a detailed view of a ratchet of the packer of FIG. 4.
- FIG. 9 is a detailed view of stinger seals.
- FIG. 11 is a cross-sectional view of a recorder housing according to an embodiment of the invention.
- FIGS. 12 and 13 are cross-sectional views of the recorder housing taken along lines 12 - 12 and 13 - 13 , respectively, of FIG. 11.
- FIG. 14 is a cross-sectional view of a swab cup assembly according to an embodiment of the invention.
- an embodiment 80 of a hydraulically set, retrievable packer 80 in accordance with the invention may be run downhole with a tubing, or test string 82 , and set (to form a test zone 87 ) by applying pressure to an annulus 72 . More particularly, in some embodiments, construction of the packer 80 permits the packer 80 to be placed in three different configurations: a run-in-hole configuration (FIG. 5), a set configuration (FIG. 7), and a pull-out-of-hole configuration (FIG. 10). The packer 80 is placed in the run-in-hole configuration before being lowered into the wellbore with the string 82 .
- the string 82 (secured by a tubing hanger 75 , for example, for offshore wells) is allowed to linearly expand and contract without requiring slip joints. Because the string 82 is run downhole with the packer 80 , seals (described below) between the string 82 and the packer 80 remain protected as the packer 80 is lowered into or retrieved from the wellbore, and the perforating gun 86 may have an outer diameter larger than a seal bore (described below) of the packer 80 .
- the advantages of the above-described packer may include one or more of the following: the packer may be retrieved upon completion of testing; drill collars may not be required to set the packer; slip joints may not be required; movement or manipulation of the test string may not be required to set the packer; performance in deviated and deep sea wells may be enhanced; downhole gauges may remain stationary during well testing; subsea tree and guns may be positioned before setting the packer; the packer may be compatible with large size guns for better perforating performance; and a bypass valve (described below) of the packer may improve well killing capabilities of the test string.
- the packer 80 has an annular, resilient elastomer ring 84 .
- the packer 80 is constructed to convert pressure exerted by fluid in the annulus 72 of the well into a force to compress the ring 84 .
- This pressure may be a combination of the hydrostatic pressure of the column of fluid in the annulus 72 as well as pressure that is applied from the surface of the well.
- the ring 84 expands radially outward and forms a seal with the interior of the casing 70 .
- the packer 80 is constructed to hold the ring 84 in this compressed state until the packer 80 is placed in the pull-out-of-hole configuration, a configuration in which the packer 80 releases the compressive forces on the ring 84 and allows the ring 84 to return to a relaxed position, as further described below.
- the packer 80 is constructed to allow fluid to flow through the packer 80 when the packer 80 is beginning lowered into or retrieved from the wellbore. To accomplish this, the packer 80 has radial bypass ports 98 that are located above the ring 84 .
- the packer 80 In the run-in-hole configuration, the packer 80 is constructed to establish fluid communication between radial bypass ports 92 located below the ring 84 and the radial ports 98 , and in the pull-out-of-hole configuration, the packer 80 is constructed to establish fluid communication between other radial ports 90 located below the ring 84 and the radial ports 98 .
- the radial ports 98 above the ring 84 are always open. However, when the packer 80 is set, the radial ports 90 and 92 are closed.
- the packer 80 also has radial ports 96 that are used to inject a kill fluid to “kill” the producing formation.
- the ports 96 are located below the ring 84 in a lower housing 108 (described below), and each port 96 is part of a bypass valve 154 .
- the bypass valve 154 remains closed until the pressure exerted by fluid in the lower annulus 71 exceeds a predetermined pressure level to rupture a rupture disc 157 of the bypass valve 154 . Once this occurs, fluid in the annulus enters the port 96 to exert pressure upon a lower surface of a piston head 161 of a mandrel 159 that is coaxial with the packer 80 . Before the rupture disc 157 ruptures, the mandrel 159 blocks the port 96 .
- the rupture disc 157 ruptures, the pressure exerted by the fluid on the lower surface of the piston head 161 is greater than the pressure exerted by gas of an atmospheric chamber 155 on the upper surface of the piston head 161 . As a result, the mandrel 159 moves in an upward direction to open the port 96 .
- the opening of the ports 96 establishes fluid communication between the lower 71 annulus and the upper annulus 72 . Once this occurs, a formation kill fluid is injected into the annulus 72 . The kill fluid flows out of the ports 98 , mixes with gases and other well fluids present in the annulus 71 , enters a perforated tailpipe 88 (located near the gun 86 ) of the string 80 and flows up through a central passageway of the string 10 .
- the packer 80 when the packer 80 is placed in the run-in-hole configuration, the ring 84 is in a relaxed, uncompressed position.
- the packer 80 has a stinger tubing 102 that is coaxial with and shares a central passageway 81 with the string 82 .
- the tubing 102 forms a section of the string 82 and has threaded ends to connect the packer 80 into the string 82 .
- the tubing 102 is circumscribed by the ring 84 , an upper housing 104 , a middle housing 106 and a lower housing 108 .
- the housings 104 , 106 , and 108 are constructed to compress the ring 84 (as described below), and subsequently, when the string 82 is pulled a predetermined distance upward to exert a predetermined longitudinal force on the tubing 102 , the housings 104 , 106 , and 108 are constructed to release the ring 84 (as described below).
- the three housings 104 , 106 , and 108 and the uncompressed ring 84 have approximately the same diameter.
- the ring 84 is located between the upper housing 104 and the middle housing 106 , with the lower housing 108 supporting the middle housing 106 .
- the packer 80 has an inner stinger sleeve, or housing 105 , that circumscribes the tubing 102 and is radially located inside the housings 104 , 106 , and 108 .
- the housing 105 along with the radial ports 90 , 92 and 98 , effectively forms a bypass valve.
- the housing 105 has radial ports that align with the ports 92 when the packer 80 is placed in the run-in-hole configuration to allow fluid communication between the ports 92 and 98 .
- the housing 105 blocks fluid communication between the ports 90 and 92 and the ports 98 when the packer 80 is placed in the set configuration (as depicted in FIG. 7), and the housing 105 permits communication between the ports 90 and 98 when the packer 82 is placed in the pull out of hole configuration (as depicted in FIG. 10).
- the bottom housing 108 is releasably attached to the housing 105
- the top housing 104 is attached to the housing 105 via a ratchet mechanism 138 that is secured to the housing 106 .
- teeth 137 of the housing 104 crawl down teeth 136 that are formed in the housing 105 .
- the compressive forces on the ring 84 are maintained until the packer is placed in the pull-out-of-hole configuration, as described below.
- the radial ports 92 are aligned with ports that extend through the housing 105 .
- the ports in the housing open into an annular region 99 (between the housing 105 and the tubing 102 ) which is in communication with the radial ports 98 .
- the ports 98 are formed from openings in the middle housing 106 and the housing 105 .
- the housing 105 has openings that hold one or more clamps 100 that secure the housing 105 to the tubing 102 .
- the clamps 100 having inclined teeth 101 that are adapted to mate with inclined teeth 103 that are formed on the tubing 102 .
- the interaction between the faces of the teeth 101 and 103 produce upward and radially outward forces on the clamps 100 .
- the upper housing 104 is configured to block radial movement of the clamps 100 and keep the clamps 100 pressed against the teeth 101 of the tubing 102 .
- the packer 80 is placed in the set configuration by applying pressure to the hydrostatic fluid in the annulus 72 .
- the fluid pierces a rupture disc 124 that is located in a radial port 122 of the housing 104 .
- the port 122 establishes fluid communication between the annulus 72 and an upper face 120 of an annular piston head 119 of the upper housing 104 .
- the piston 119 is located below a mating annular piston head 117 of the housing 105 .
- An annular atmosphere chamber 118 is formed above the extension 119 .
- the packer 80 has a built-in damper to control the downward speed of the upper housing 104 .
- the damper is formed from an annular piston head 121 of the housing 105 that extends between the housing 105 and the upper housing 104 .
- the piston head 121 forms an annular space 126 between the upper face of the piston head 121 and the lower face of the piston 119 .
- This annular space 126 contains hydraulic fluid which is forced through a flow restrictor 128 when the lower face of the piston 119 exerts force on the fluid, i.e., when the upper housing 104 moves down.
- the flow restrictor 128 is formed in the piston head 121 and opens into an annular chamber 130 formed below the piston head 121 for receiving the hydraulic fluid.
- the upper housing 104 may have another annular piston head 116 to effectively multiply (e.g., double) the force exerted by the upper housing 104 on the ring 84 .
- another radial port 112 in the upper housing 104 is used to establish fluid communication between the annulus 72 and an upper face of the piston head 116 , in some embodiments, another rupture disc is not used. Instead, an annular extension 123 of the housing 105 is used to initially block the port 112 before the shear pin 107 breaks and the upper housing 104 begins to move.
- the upper housing 104 may be formed from an upper piece 104 a and a lower piece 104 b. Radially spaced shear pins 113 hold the upper 104 a and lower 104 b pieces together until the desired level of compression is reached and the shear pins 113 shear. Upon this occurrence, the two pieces 104 a and 104 b are separated and additional compression on the ring 84 is prevented.
- the packer 80 When in the set configuration, the packer 80 is constructed to push slips 110 radially outwardly to secure the packer 80 to the casing 70 .
- the slips 110 are located between the middle 106 and lower 108 housings.
- the housings 106 and 108 have upper 140 and lower 144 inclined faces that are adapted to mate with inclined faces 142 of the slips 110 and push the slips 10 toward the casing 70 when the housing 104 pushes the middle housing 106 toward the lower housing 108 .
- the string 82 moves freely through the packer 84 .
- the upper housing 104 is configured to slide past the clamps 100 when the housing 104 compresses the ring 84 .
- the clamps 100 release their grip on the tubing 102 , and as a result, the tubing 102 is free to move with respect to the rest of the packer 80 .
- a cylindrical seal bore 160 is constructed in the housing 105 .
- the seal bore 160 provides a smooth interior surface for establishing a seal with annular seals 156 (see also FIG. 9) that circumscribe the tubing 102 .
- the seals 156 remain in the seal bore 160 at all times, i.e., as the packer 80 is run downhole, when the packer 80 is set, and when the packer 80 is retrieved uphole.
- the seal bore 160 protects the seals 156 at all times.
- the seal bore 160 has a length (e.g., twenty feet) that is sufficient to permit thermal expansion and contraction of the string 82 .
- the packer 80 is placed in the pull-out-of-hole configuration by disconnecting the lower housing 108 from the housing 105 , an action that allows the lower housing 108 to slide down and rest on an annular extension 111 of the housing 105 ).
- the radially outward forces exerted against the slips 110 are relaxed to disengage the slips 110 , and the compression forces placed against the ring 84 are removed.
- the lower housing 108 is connected to the housing 105 by a clamp 146 of the housing 105 that has teeth 151 (similar to the teeth 101 of the stinger 100 ) that are adapted to mate with teeth 149 (similar to the teeth 103 ) of the lower housing 108 .
- the teeth 149 push radially inwardly on the teeth 151 and tend to force the housing 105 away from the lower housing 108 .
- a ring 148 that circumscribes the tubing 102 is attached (via screws) to an interior surface of the clamp 146 . The ring 148 counters the radially inward forces to hold the teeth 149 and 151 (and the housing 105 and lower housing 108 ) together.
- the tubing 102 has a collet 158 that is attached near the bottom of the tubing 102 .
- the collet 158 is configured to grab the ring 148 as the end of the tubing 102 passes near the ring 148 .
- the screws that hold the ring 148 to the housing 105 are sheared, and as a result, the collet 158 pulls the ring 148 away from the clamp 146 , an event that permits the housing 105 to come free from the lower housing 108 .
- a recorder housing assembly 400 may be secured to and located downhole of the seal bore 160 .
- the recorder housing assembly 400 houses downwardly extending instrument probes 410 that may be used to measure, for example, the pressure below the seal that is provided by the resilient element 84 .
- the assembly 400 may include hollow upper 402 , middle 409 (see FIG. 13) and lower 412 housings that permit a tubing 401 to freely pass through.
- the tubing 401 in turn, may be secured to the tubing 102 .
- the upper housing 402 provides a threaded connection 408 for securing the assembly 400 to the seal bore 160 and includes recesses 406 (see also FIG. 12) for receiving the upper ends of the instrument probes 410 .
- the recesses 406 provide places for mounting the upper ends of the instrument probes to the upper housing 402 .
- the middle housing 409 includes channels 411 that are parallel to the axis of the tubing 401 and receive the instrument probes 410 .
- the lower housing 412 includes recesses 407 for receiving the lower ends of the instrument probes 410 and for mounting the lower ends to the lower housing 412 .
- the packer 80 may be used to seal off an annulus in a well that has already been perforated.
- a swab cup assembly 300 may be coupled in the test string 82 below the packer 80 .
- the swab cup assembly 300 includes annular swab resilient cups 304 (an upper swab cup 304 a and a lower swab cup 304 b, as examples) that circumscribe a mandrel 302 that shares a central passageway with and is located below the seal bore 160 .
- fluid is circulated down the annulus and up through the central passageway of the packer 80 (and string 82 ).
- this fluid flow causes the swab cups 304 to radially expand (as indicated by the reference numeral 304 a ′ for the lower swab cup 304 a ) to seal off the annulus above the swab cups 403 from the perforated well casing below and allow the pressure above the swab cups 304 to rupture the rupture disc 124 .
- a standoff sleeve 312 that circumscribes the mandrel 302 keeps the upper 304 a and lower 304 b swab cups separated.
- Shear pins 320 radially extend from the mandrel 302 beneath the swab cubs 304 to place a limit on the downward movement by the swab cups 304 and ensure that the sleeve 312 covers radial ports 330 (of the mandrel 302 ) that may otherwise establish communication between the annulus and the central passageway of the mandrel 302 .
- a sealing sleeve 310 may be located between the sleeve 312 and the mandrel 302 .
- the swab cups 304 When the packer 80 is to be retrieved uphole, it may be undesirable for the swab cups 304 to “swab” the well casing. To prevent this from occurring, the pressure in the annulus may be increased to predetermined level to cause the swap cups 304 to shear the shear pins 320 . To accomplish this, a metal sleeve 316 may circumscribe the mandrel 302 and may be located below the lower swab cup 304 b. In this manner, when the pressure in the annulus exceeds the predetermined level, the swab cups 304 cause the sleeve 316 to exert a sufficient force to shear the shear pins 320 .
- the swab cubs 304 and the sleeves 312 and 310 travel down the mandrel 302 and open the ports 330 , a state of the assembly 300 that permits the fluid in the annulus to bypass the swab cups 304 .
- An alternative way to shear the shear pins 320 is to move the string 82 in an upward direction. In this manner, the swap cups 304 grip the inside of the casing to cause the sleeve 316 to shear the shear pins 310 due to the upward travel of the string 82 .
- annular extension 308 of the mandrel 302 may limit upward travel of the swab cups 304 .
- a bottom annular extension 324 of the assembly may limit the downward travel of the swap cups 304 after the shear pins 320 shear.
Abstract
A packer for use inside a casing of a subterranean well includes a resilient element, a housing and a rupture disc. The resilient element is adapted to seal off an annulus of the well when compressed, and the housing is adapted to compress the resilient element in response to a pressure exerted by fluid of the annulus of a piston head of the housing. The housing includes a port for establishing fluid communication with the annulus. The rupture disc is adapted to prevent the fluid in the annulus from entering the port and contacting the piston head until the pressure exerted by the fluid exceeds a predefined threshold and ruptures the rupture disc.
Description
- The invention relates to a packer.
- As shown in FIG. 1, for purposes of measuring characteristics (e.g., formation pressure) of a
subterranean formation 31, atubular test string 10 may be inserted into a wellbore that extends into theformation 31. In order to test a particular region, orzone 33, of theformation 31, thetest string 10 may include a perforating gun 30 that is used to penetrate awell casing 12 and formfractures 29 in theformation 31. To seal off thezone 33 from the surface of the well, thetest string 10 may be attached to, for example, a retrievableweight set packer 27 that has anannular elastomer ring 26 to form a seal (when compressed) between the exterior of thetest string 10 and the internal surface of thewell casing 12, i.e., thepacker 27 seals off an annular region called anannulus 16 of the well. Above thepacker 27, arecorder 11 of thetest string 10 may take measurements of the test zone pressure. - The
test string 10 typically includes valves to control the flow of fluid into and out of a central passageway of thetest string 10. For example, an in-line ball valve 22 may control the flow of well fluid from thetest zone 33 up through the central passageway of thetest string 10. As another example, above thepacker 27, acirculation valve 20 may control fluid communication between theannulus 16 and the central passageway of thetest string 10. - The
ball valve 22 and thecirculation valve 20 may be controlled by commands (e.g., “open valve” or “close valve”) that are sent downhole from the surface of the well. As an example, each command may be encoded into a predetermined signature ofpressure pulses 34 see (FIG. 2) that are transmitted downhole via hydrostatic fluid that is present in theannulus 16. Asensor 25 may receive thepressure pulses 34 so that the command may be extracted by electronics of thestring 10. Afterwards, electronics and hydraulics of thetest string 10 operate thevalves - Two general types of packers typically may be used: the retrievable
weight set packer 27 that is depicted in FIG. 1 and a permanent hydraulicallyset packer 60 that is depicted in FIG. 3. To set the weight set packer 27 (i.e., to compress theelastomer ring 26 to force thering 26 radially outward), an upward force and/or a rotational force may be applied to thestring 10 to actuate a mechanism (of the string 10) to release the weight of thestring 10 upon thering 26. However, rotational and translational manipulations of thetest string 10 to set thepacker 27 may present difficulties for a highly deviated wellbore and for a subsea well in which a vessel is drifting up and down, a movement that introduces additional motion to thetest string 10. Additional drill collars 44 (onedrill collar 44 being shown in FIG. 1) may be required to compress thering 26.Slip joints 46 may be needed to compensate for expansion and contraction of thestring 10. - Referring to FIG. 3, the hydraulically
set packer 60 may be set by a setting tool that is run downhole on a wireline, or alternatively, the hydraulicallyset packer 60 may be run downhole on a tubing and set by establishing a predetermined pressure differential between the central passageway of the tubing and theannulus 16. Among the differences from theweight set packer 27, thepacker 60 typically remains permanently in the wellbore after being set, a factor that may affect the number of features that are included with thepacker 60. Furthermore, a separate downhole trip typically is required to set thepacker 60. For example, a special tool may be run downhole with thepacker 60 to set thepacker 60 in one downhole trip, and afterwards, another downhole trip may be required to run thetest string 10. Because thetest string 10 must pass through the inner diameter of aseal bore 62 of thepacker 60, the outer diameter of the perforating gun 30 may be limited, and stingerseals 52 of thetest string 10 may be damaged. - Thus, there exists a continuing need for a packer that addresses one or more of the above-stated problems.
- In one embodiment of the invention, a packer for use inside a casing of a subterranean well includes a resilient element, a housing and a rupture disk. The resilient element is adapted to seal off an annulus of the well when compressed, and the housing is adapted to compress the resilient element in response to a pressure exerted by fluid of the annulus on a piston head of the housing. The housing includes a port for establishing fluid communication with the annulus. The rupture disk is adapted to prevent the fluid in the annulus from entering the port and contacting the piston head until the pressure exerted by the fluid exceeds a predefined threshold and ruptures the rupture disk.
- In another embodiment, a method for setting a packer in a subterranean well includes isolating a resilient element from pressure being exerted from a fluid in an annulus of the well until the resilient element is at a predefined depth in the well. When the resilient element is at the predefined depth, the fluid in the annulus is allowed to compress the resilient element to seal off the annulus.
- Advantages and other features of the invention will become apparent from the following description and from the claims.
- FIGS. 1 and 3 are schematic views of test strings of the prior art in wells being tested.
- FIG. 2 is a waveform illustrating a pressure pulse command for a tool of the test strings of FIGS. 1 and 3.
- FIGS.4 is a schematic view of a test string in a well being tested according to an embodiment of the invention.
- FIGS. 5, 7, and10 are schematic views of a packer of the test string of FIG. 4 according to an embodiment of the invention.
- FIG. 6 is a detailed view of a connection between a tubing and a fastener of the packer of FIG. 4.
- FIG. 8 is a detailed view of a ratchet of the packer of FIG. 4.
- FIG. 9 is a detailed view of stinger seals.
- FIG. 11 is a cross-sectional view of a recorder housing according to an embodiment of the invention.
- FIGS. 12 and 13 are cross-sectional views of the recorder housing taken along lines12-12 and 13-13, respectively, of FIG. 11.
- FIG. 14 is a cross-sectional view of a swab cup assembly according to an embodiment of the invention.
- Referring to FIG. 4, an
embodiment 80 of a hydraulically set,retrievable packer 80 in accordance with the invention may be run downhole with a tubing, ortest string 82, and set (to form a test zone 87) by applying pressure to anannulus 72. More particularly, in some embodiments, construction of thepacker 80 permits thepacker 80 to be placed in three different configurations: a run-in-hole configuration (FIG. 5), a set configuration (FIG. 7), and a pull-out-of-hole configuration (FIG. 10). Thepacker 80 is placed in the run-in-hole configuration before being lowered into the wellbore with thestring 82. Once thepacker 80 is in position in the wellbore, pressure is transmitted through hydrostatic fluid present in theannulus 72 to place thepacker 80 in the set configuration in which thepacker 80 secures itself to awell casing 70, seals off thetest zone 87, permits thestring 82 to move through thepacker 80, and maintains a seal between the interior of thepacker 80 and the exterior of thestring 82. After testing is complete, an upward force may be applied to thestring 82 to place thepacker 80 in the pull-out-of-hole configuration to disengage thepacker 80 from thecasing 70. - As described further below, due to the design of the
packer 80, the string 82 (secured by atubing hanger 75, for example, for offshore wells) is allowed to linearly expand and contract without requiring slip joints. Because thestring 82 is run downhole with thepacker 80, seals (described below) between thestring 82 and thepacker 80 remain protected as thepacker 80 is lowered into or retrieved from the wellbore, and theperforating gun 86 may have an outer diameter larger than a seal bore (described below) of thepacker 80. - Thus, the advantages of the above-described packer may include one or more of the following: the packer may be retrieved upon completion of testing; drill collars may not be required to set the packer; slip joints may not be required; movement or manipulation of the test string may not be required to set the packer; performance in deviated and deep sea wells may be enhanced; downhole gauges may remain stationary during well testing; subsea tree and guns may be positioned before setting the packer; the packer may be compatible with large size guns for better perforating performance; and a bypass valve (described below) of the packer may improve well killing capabilities of the test string.
- To form a seal between an outer housing of the
packer 80 and the interior of the casing 70 (in the set configuration of the packer 80), thepacker 80 has an annular,resilient elastomer ring 84. In this manner, once in position downhole, thepacker 80 is constructed to convert pressure exerted by fluid in theannulus 72 of the well into a force to compress thering 84. This pressure may be a combination of the hydrostatic pressure of the column of fluid in theannulus 72 as well as pressure that is applied from the surface of the well. When compressed, thering 84 expands radially outward and forms a seal with the interior of thecasing 70. Thepacker 80 is constructed to hold thering 84 in this compressed state until thepacker 80 is placed in the pull-out-of-hole configuration, a configuration in which thepacker 80 releases the compressive forces on thering 84 and allows thering 84 to return to a relaxed position, as further described below. - Because the outer diameter of the ring84 (when the
ring 84 is in the uncompressed state) is closely matched to the inner diameter of thecasing 70, there may be only a small annular clearance between thering 84 and thecasing 70 as thepacker 84 is being retrieved from or lowered into the wellbore. To circumvent the forces present as a result of this small annular clearance, thepacker 80 is constructed to allow fluid to flow through thepacker 80 when thepacker 80 is beginning lowered into or retrieved from the wellbore. To accomplish this, thepacker 80 hasradial bypass ports 98 that are located above thering 84. In the run-in-hole configuration, thepacker 80 is constructed to establish fluid communication betweenradial bypass ports 92 located below thering 84 and theradial ports 98, and in the pull-out-of-hole configuration, thepacker 80 is constructed to establish fluid communication between otherradial ports 90 located below thering 84 and theradial ports 98. Theradial ports 98 above thering 84 are always open. However, when thepacker 80 is set, theradial ports - The
packer 80 also hasradial ports 96 that are used to inject a kill fluid to “kill” the producing formation. Theports 96 are located below thering 84 in a lower housing 108 (described below), and eachport 96 is part of abypass valve 154. Thebypass valve 154 remains closed until the pressure exerted by fluid in the lower annulus 71 exceeds a predetermined pressure level to rupture arupture disc 157 of thebypass valve 154. Once this occurs, fluid in the annulus enters theport 96 to exert pressure upon a lower surface of apiston head 161 of amandrel 159 that is coaxial with thepacker 80. Before therupture disc 157 ruptures, themandrel 159 blocks theport 96. However, after therupture disc 157 ruptures, the pressure exerted by the fluid on the lower surface of thepiston head 161 is greater than the pressure exerted by gas of anatmospheric chamber 155 on the upper surface of thepiston head 161. As a result, themandrel 159 moves in an upward direction to open theport 96. - Because the
ports 98 are always open, the opening of theports 96 establishes fluid communication between the lower 71 annulus and theupper annulus 72. Once this occurs, a formation kill fluid is injected into theannulus 72. The kill fluid flows out of theports 98, mixes with gases and other well fluids present in the annulus 71, enters a perforated tailpipe 88 (located near the gun 86) of thestring 80 and flows up through a central passageway of thestring 10. - Referring to FIG. 5, when the
packer 80 is placed in the run-in-hole configuration, thering 84 is in a relaxed, uncompressed position. At its core, thepacker 80 has astinger tubing 102 that is coaxial with and shares acentral passageway 81 with thestring 82. Thetubing 102 forms a section of thestring 82 and has threaded ends to connect thepacker 80 into thestring 82. Thetubing 102 is circumscribed by thering 84, anupper housing 104, amiddle housing 106 and alower housing 108. When sufficient pressure is applied to theannulus 72, thehousings string 82 is pulled a predetermined distance upward to exert a predetermined longitudinal force on thetubing 102, thehousings housings uncompressed ring 84 have approximately the same diameter. Thering 84 is located between theupper housing 104 and themiddle housing 106, with thelower housing 108 supporting themiddle housing 106. - To hold the
housings packer 80 has an inner stinger sleeve, orhousing 105, that circumscribes thetubing 102 and is radially located inside thehousings housing 105, along with theradial ports housing 105 has radial ports that align with theports 92 when thepacker 80 is placed in the run-in-hole configuration to allow fluid communication between theports housing 105 blocks fluid communication between theports ports 98 when thepacker 80 is placed in the set configuration (as depicted in FIG. 7), and thehousing 105 permits communication between theports packer 82 is placed in the pull out of hole configuration (as depicted in FIG. 10). - Referring also to FIG. 8, the
bottom housing 108 is releasably attached to thehousing 105, and thetop housing 104 is attached to thehousing 105 via aratchet mechanism 138 that is secured to thehousing 106. As the top 104 and bottom 108 housings move closer together to compress thering 84,teeth 137 of thehousing 104 crawl downteeth 136 that are formed in thehousing 105. As a result of this arrangement, the compressive forces on thering 84 are maintained until the packer is placed in the pull-out-of-hole configuration, as described below. - Still referring to FIG. 5, more particularly, the compressive forces that are exerted by the
housings ring 84 are released when the attachment between thelower housing 108 and thehousing 105 is released, as described below. As a result of this release, thebottom housing 108 and the middle housing 106 (supported by the bottom housing 108) fall away from thering 84. - In the run-in-hole configuration, the
radial ports 92 are aligned with ports that extend through thehousing 105. The ports in the housing open into an annular region 99 (between thehousing 105 and the tubing 102) which is in communication with theradial ports 98. Theports 98 are formed from openings in themiddle housing 106 and thehousing 105. - To prevent the housing105 (and
housings tubing 102 when thepacker 80 is in the run-in-hole configuration, thehousing 105 has openings that hold one ormore clamps 100 that secure thehousing 105 to thetubing 102. As shown in FIG. 6, theclamps 100 having inclinedteeth 101 that are adapted to mate withinclined teeth 103 that are formed on thetubing 102. The interaction between the faces of theteeth clamps 100. Although the upward forces keep thehousing 105 from sliding down thetubing 102, the radial forces tend to push theclamps 100 away from thetubing 102. However, in the run-in-hole configuration, theupper housing 104 is configured to block radial movement of theclamps 100 and keep theclamps 100 pressed against theteeth 101 of thetubing 102. - Referring to FIG. 7, once the
packer 80 is in position to be set, thepacker 80 is placed in the set configuration by applying pressure to the hydrostatic fluid in theannulus 72. When the pressure in theannulus 72 exceeds a predetermined level, the fluid pierces arupture disc 124 that is located in aradial port 122 of thehousing 104. When thedisc 124 is pierced, theport 122 establishes fluid communication between theannulus 72 and anupper face 120 of anannular piston head 119 of theupper housing 104. Thepiston 119 is located below a matingannular piston head 117 of thehousing 105. Anannular atmosphere chamber 118 is formed above theextension 119. Thus, when fluid communication is established between theannulus 72 and thepiston head 119, the pressure on the fluid creates a downward force on the piston head 119 (and on the upper housing 104), and when a shear pin 107 (securing theupper housing 104 and thehousing 105 together) shears, theupper housing 104 begins moving downward and begins compressing thering 84. - To ensure that the
ring 84 is slowly compressed, thepacker 80 has a built-in damper to control the downward speed of theupper housing 104. The damper is formed from anannular piston head 121 of thehousing 105 that extends between thehousing 105 and theupper housing 104. Thepiston head 121 forms anannular space 126 between the upper face of thepiston head 121 and the lower face of thepiston 119. Thisannular space 126 contains hydraulic fluid which is forced through aflow restrictor 128 when the lower face of thepiston 119 exerts force on the fluid, i.e., when theupper housing 104 moves down. The flow restrictor 128 is formed in thepiston head 121 and opens into anannular chamber 130 formed below thepiston head 121 for receiving the hydraulic fluid. - Because the surface area of the upper face of the
piston head 119 is limited by the interior diameter of thecasing 70, in some embodiments, theupper housing 104 may have anotherannular piston head 116 to effectively multiply (e.g., double) the force exerted by theupper housing 104 on thering 84. Although anotherradial port 112 in theupper housing 104 is used to establish fluid communication between theannulus 72 and an upper face of thepiston head 116, in some embodiments, another rupture disc is not used. Instead, anannular extension 123 of thehousing 105 is used to initially block theport 112 before theshear pin 107 breaks and theupper housing 104 begins to move. Once theport 112 moves past theextension 123, fluid from theannulus 72 enters anannular region 114 between the lower face of theextension 123 and the upper face of thepiston head 116, and thereafter, a downward force is exerted by thepiston head 116 until thepacker 84 is set. - To establish a desired level of compression force on the ring84 (i.e., to establish a force limit on the resilient element 84), the
upper housing 104 may be formed from anupper piece 104 a and alower piece 104 b. Radially spaced shear pins 113 hold the upper 104 a and lower 104 b pieces together until the desired level of compression is reached and the shear pins 113 shear. Upon this occurrence, the twopieces ring 84 is prevented. - When in the set configuration, the
packer 80 is constructed to pushslips 110 radially outwardly to secure thepacker 80 to thecasing 70. Theslips 110 are located between the middle 106 and lower 108 housings. Thehousings inclined faces 142 of theslips 110 and push theslips 10 toward thecasing 70 when thehousing 104 pushes themiddle housing 106 toward thelower housing 108. - Once the
packer 80 is set, thestring 82 moves freely through thepacker 84. To accomplish this, theupper housing 104 is configured to slide past theclamps 100 when thehousing 104 compresses thering 84. As a result, there are no radially inward forces exerted against theclamps 100 to hold theclamps 100 against thetubing 102. Thus, theclamps 100 release their grip on thetubing 102, and as a result, thetubing 102 is free to move with respect to the rest of thepacker 80. - A cylindrical seal bore160, is constructed in the
housing 105. The seal bore 160 provides a smooth interior surface for establishing a seal with annular seals 156 (see also FIG. 9) that circumscribe thetubing 102. Theseals 156 remain in the seal bore 160 at all times, i.e., as thepacker 80 is run downhole, when thepacker 80 is set, and when thepacker 80 is retrieved uphole. Thus, the seal bore 160 protects theseals 156 at all times. The seal bore 160 has a length (e.g., twenty feet) that is sufficient to permit thermal expansion and contraction of thestring 82. - As shown in FIG. 10, the
packer 80 is placed in the pull-out-of-hole configuration by disconnecting thelower housing 108 from thehousing 105, an action that allows thelower housing 108 to slide down and rest on anannular extension 111 of the housing 105). As a result of this disconnection, the radially outward forces exerted against the slips 110 (by the middle 106 and lower 108 housings) are relaxed to disengage theslips 110, and the compression forces placed against thering 84 are removed. To accomplish this, thelower housing 108 is connected to thehousing 105 by aclamp 146 of thehousing 105 that has teeth 151 (similar to theteeth 101 of the stinger 100) that are adapted to mate with teeth 149 (similar to the teeth 103) of thelower housing 108. Theteeth 149 push radially inwardly on theteeth 151 and tend to force thehousing 105 away from thelower housing 108. However, aring 148 that circumscribes thetubing 102 is attached (via screws) to an interior surface of theclamp 146. Thering 148 counters the radially inward forces to hold theteeth 149 and 151 (and thehousing 105 and lower housing 108) together. - To release the connection between the
housing 105 and thelower housing 108, thetubing 102 has acollet 158 that is attached near the bottom of thetubing 102. Thecollet 158 is configured to grab thering 148 as the end of thetubing 102 passes near thering 148. When a predetermined force is applied upwardly on thetubing 102, the screws that hold thering 148 to thehousing 105 are sheared, and as a result, thecollet 158 pulls thering 148 away from theclamp 146, an event that permits thehousing 105 to come free from thelower housing 108. - Referring to FIG. 11, in some embodiments, a
recorder housing assembly 400 may be secured to and located downhole of the seal bore 160. Therecorder housing assembly 400 houses downwardly extending instrument probes 410 that may be used to measure, for example, the pressure below the seal that is provided by theresilient element 84. Theassembly 400 may include hollow upper 402, middle 409 (see FIG. 13) and lower 412 housings that permit atubing 401 to freely pass through. Thetubing 401, in turn, may be secured to thetubing 102. - The
upper housing 402 provides a threadedconnection 408 for securing theassembly 400 to the seal bore 160 and includes recesses 406 (see also FIG. 12) for receiving the upper ends of the instrument probes 410. Therecesses 406 provide places for mounting the upper ends of the instrument probes to theupper housing 402. Themiddle housing 409 includeschannels 411 that are parallel to the axis of thetubing 401 and receive the instrument probes 410. Thelower housing 412 includesrecesses 407 for receiving the lower ends of the instrument probes 410 and for mounting the lower ends to thelower housing 412. - The
packer 80 may be used to seal off an annulus in a well that has already been perforated. Referring to FIG. 14, to ensure that the required pressure is established in the annulus to rupture therupture disc 124, aswab cup assembly 300 may be coupled in thetest string 82 below thepacker 80. In this manner, in some embodiments, theswab cup assembly 300 includes annular swab resilient cups 304 (anupper swab cup 304 a and alower swab cup 304 b, as examples) that circumscribe amandrel 302 that shares a central passageway with and is located below the seal bore 160. For purposes of causing the swab cups 304 to radially expand, fluid is circulated down the annulus and up through the central passageway of the packer 80 (and string 82). In this manner, this fluid flow causes the swab cups 304 to radially expand (as indicated by thereference numeral 304 a′ for thelower swab cup 304 a) to seal off the annulus above the swab cups 403 from the perforated well casing below and allow the pressure above the swab cups 304 to rupture therupture disc 124. - A
standoff sleeve 312 that circumscribes themandrel 302 keeps the upper 304 a and lower 304 b swab cups separated. Shear pins 320 radially extend from themandrel 302 beneath theswab cubs 304 to place a limit on the downward movement by the swab cups 304 and ensure that thesleeve 312 covers radial ports 330 (of the mandrel 302) that may otherwise establish communication between the annulus and the central passageway of themandrel 302. A sealingsleeve 310 may be located between thesleeve 312 and themandrel 302. - When the
packer 80 is to be retrieved uphole, it may be undesirable for the swab cups 304 to “swab” the well casing. To prevent this from occurring, the pressure in the annulus may be increased to predetermined level to cause the swap cups 304 to shear the shear pins 320. To accomplish this, ametal sleeve 316 may circumscribe themandrel 302 and may be located below thelower swab cup 304 b. In this manner, when the pressure in the annulus exceeds the predetermined level, the swab cups 304 cause thesleeve 316 to exert a sufficient force to shear the shear pins 320. Once this occurs, theswab cubs 304 and thesleeves mandrel 302 and open theports 330, a state of theassembly 300 that permits the fluid in the annulus to bypass the swab cups 304. - An alternative way to shear the shear pins320 is to move the
string 82 in an upward direction. In this manner, the swap cups 304 grip the inside of the casing to cause thesleeve 316 to shear the shear pins 310 due to the upward travel of thestring 82. - Among the other features of the
swab cup assembly 300, anannular extension 308 of themandrel 302 may limit upward travel of the swab cups 304. A bottomannular extension 324 of the assembly may limit the downward travel of the swap cups 304 after the shear pins 320 shear. - While the invention has been disclosed with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations as fall within the true spirit and scope of the invention.
Claims (28)
1. A packer for use inside a casing of a subterranean well, comprising:
a resilient element adapted to seal off an annulus of the well when compressed;
a housing adapted to compress the resilient element in response to a pressure exerted by fluid of the annulus on a piston head of the housing, the housing including a port for establishing fluid communication with the annulus; and
a rupture disc adapted to prevent the fluid in the annulus from entering the port and contacting the piston head until the pressure exerted by the fluid exceeds a predefined threshold and ruptures the rupture disc.
2. The packer of , wherein the housing is further adapted to form a first chamber in contact with a first surface of the piston head to receive the fluid and a second chamber in contact with another surface of the piston head and containing a gas to exert a lower pressure than the pressure exerted by the fluid in the annulus.
claim 1
3. The packer of , wherein the gas has an atmospheric pressure.
claim 2
4. The packer of , further comprising:
claim 1
a tubing being circumscribed by the housing; and
a fastener configured to in a first position, secure the housing to the tubing, and in a second position, release the housing from the tubing in response to the pressure exerted by the fluid in the annulus.
5. The packer of , further comprising:
claim 1
a tubing being circumscribed by the first housing; and
a recorder housing coupled to the first housing and adapted to permit the tubing to slide through the recorder housing.
6. The packer of , wherein
claim 5
the recorder housing comprises instrument probes, and
the recording housing is coupled to the first housing to cause the instrument probes to remain stationary when the tubing moves.
7. The packer of , further comprising:
claim 1
a tubing that is circumscribed by the housing;
a seal bore coaxial and secured to the housing; and
seals adapted to form a seal between an interior surface of the seal bore and an exterior surface of the tubing.
8. The packer of , wherein the seal bore is adapted to protect the seals while the packer is run downhole.
claim 7
9. The packer of , wherein the seal bore is adapted to protect the seals while the packer is retrieved uphole.
claim 7
10. The packer of , wherein the seal bore is adapted to permanently protect the seals.
claim 7
11. The packer of , wherein
claim 1
the housing has another piston head adapted to respond to the pressure exerted by the fluid in the annulus to cause the housing to exert an additional compression force on the resilient element after the rupture disc ruptures.
12. The packer of further comprising:
claim 1
a fastener configured to in a first position, secure the housing to the casing in response to the pressure of the fluid in the annulus.
13. The packer of , wherein in a second position, the fastener is configured to release the housing from the casing, the packer further comprising:
claim 12
a tubing being circumscribed by the housing; and
a collet configured to place the fastener in the second position in response to upward movement of the tubing by a predefined distance.
14. The packer of , wherein the housing further comprises:
claim 1
a valve adapted to selectively allow the fluid in the annulus to bypass the resilient element.
15. The packer of , wherein the valve is adapted to close in response to the pressure exerted by the fluid in the annulus to compress the resilient element.
claim 14
16. The packer of , wherein the valve is adapted to open in response to the packer being pulled out of the well.
claim 14
17. The packer of , wherein the valve is adapted to allow fluid to bypass the resilient element as the packer is run downhole.
claim 14
18. The packer of , comprising:
claim 1
a valve adapted to prevent fluid communication between the annulus and a portion of the well below the resilient element until the pressure of the fluid in the annulus exceeds another predefined threshold.
19. The packer of , wherein the valve comprises:
claim 18
another rupture disc adapted to prevent the fluid communication between the annulus and the portion of the well below the resilient element until the pressure of the fluid in the annulus exceeds said another predefined threshold to rupture said another rupture disc and opens the valve.
20. The packer of , further comprising:
claim 1
another housing adapted to apply a compression force to the resilient element; and
a shear pin adapted to couple said another housing to the first housing when the compression force is below an approximate threshold and shear to decouple said another housing from the first housing when the compression force exceeds the approximate threshold.
21. The packer of , further comprising:
claim 1
at least one annular swab cup to seal off the annulus below the resilient element to create a region in the annulus above the resilient element for pressurizing the fluid.
22. The packer of , further comprising:
claim 21
a shear pin adapted to prevent movement of said at least one swab cup until the pressure exerted by the well fluid in the annulus exceeds another predefined threshold to cause the shear pin to shear and permit said at least one swab cup to move;
a tubing being circumscribed by said at least one swab cup, the tubing having a passageway for bypassing said at least one swab cup and a port for establishing communication between the annulus above said at least one swab cup and the passageway; and
a sleeve connected to said at least one swab cup, the sleeve adapted to block communication through the port until said at least one swab cup moves.
23. The packer of , further comprising:
claim 21
another sleeve adapted receive a force from said at least one swab cup indicative of the pressure and shear the shear pin when the pressure exceeds said another predefined threshold.
24. The packer of 1, further comprising:
claim 2
a tubing; and
another sleeve circumscribing the tubing and adapted to shear the shear pin in response to movement of the tubing.
25. A method for setting a packer in a subterranean well, comprising:
isolating a resilient element from pressure being exerted from a fluid in an annulus of the well until the resilient element is at a predefined depth in the well; and
when the resilient element is at the predefined depth, allowing the fluid in the annulus to compress the resilient element to seal off the annulus.
26. The method of , wherein the act of isolating comprises:
claim 25
rupturing a rupture disk to allow the fluid in the annulus to compress the resilient element when the pressure being exerted from the fluid exceeds a predefined threshold.
27. The method of , wherein the act of allowing comprises:
claim 25
preventing the pressure from compressing the resilient element until the pressure exceeds a predefined threshold; and
after the pressure exceeds the predefined threshold, permitting the pressure to compress the resilient element.
28. The method of , wherein the act of isolating comprises:
claim 25
exerting atmospheric pressure against a piston head before the pressure exceeds a predefined threshold; and
allowing the pressure from the fluid in the annulus to contact the piston head to compress the resilient element after the pressure in the fluid in the annulus exceeds the predefined threshold.
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US6315050B2 (en) | 2001-11-13 |
GB2365471B (en) | 2003-07-23 |
GB0123834D0 (en) | 2001-11-28 |
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US6186227B1 (en) | 2001-02-13 |
NO20015097L (en) | 2001-12-19 |
CA2367491C (en) | 2007-06-12 |
AU4476700A (en) | 2000-11-02 |
NO326234B1 (en) | 2008-10-20 |
NO20015097D0 (en) | 2001-10-19 |
BR0009774B1 (en) | 2011-08-23 |
US6564876B2 (en) | 2003-05-20 |
WO2000063520A1 (en) | 2000-10-26 |
BR0009774A (en) | 2002-03-05 |
US20010002621A1 (en) | 2001-06-07 |
GB2365471A (en) | 2002-02-20 |
BR0017494B1 (en) | 2012-10-16 |
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