BACKGROUND
1. Field of the Disclosure
This disclosure relates generally to completion strings deployed in wellbores for the production of hydrocarbons from subsurface formations, including completion strings deployed for fracturing, sand packing and flooding, which strings include one or more expansion joints or tools to accommodate for the expansion and contraction of the strings during completion of such wellbores and during the production of hydrocarbons from such wellbores.
2. Background of the Art
Wellbores are drilled in subsurface formations for the production of hydrocarbons (oil and gas). Modern wells can extend to great well depths, often more than 15,000 ft. Hydrocarbons are trapped in various traps or zones in the subsurface formations at different depths. Such zones are referred to as reservoirs or hydrocarbon-bearing formations or production zones. Some reservoirs have high mobility, which is a measure of the ease of the hydrocarbons to flow from such reservoirs into the wells drilled through the reservoirs under natural downhole pressures. Some reservoirs have low mobility and the hydrocarbons trapped therein are unable to move with ease from such reservoirs into the wells drilled therethrough. Stimulation methods are typically employed to improve the mobility of the hydrocarbons through the low mobility reservoirs. One such method, referred to as fracturing (also referred to as “fracing” or “fracking”), is often utilized to create cracks in the reservoir rock to enable the fluid from the reservoir (formation fluid) to flow from the reservoir into the wellbore. To fracture multiple zones, an assembly containing an outer string with an inner string therein is run in or deployed in the wellbore. The outer string typically includes a series of devices corresponding to each zone conveyed by a tubing into the wellbore. The inner string includes devices attached to a tubing to operate certain devices in the outer string and facilitate fracturing and/or other well treatment operations. To fracture and sand pack a zone, a fluid containing a proppant (sand) is supplied under pressure to each zone, sequentially or to more than one zone at the same time. During fracturing operations the fluid supplied from the surface lowers the temperature of the outer string, which can cause the string to contract or shrink. One or more expansion tools or joins are provided in the outer string to accommodate changes in the length of the outer string due to the thermal fluctuations downhole without creating additional stress along the outer string geometry.
The disclosure herein provides a string for placement in a wellbore that may include one or more expansion tools or joints.
SUMMARY
In one aspect, an apparatus for use in a wellbore is disclosed that in one non-limiting embodiment includes a string for deployment into the wellbore, wherein the string includes at least one packer and an expansion device downhole of the packer, and wherein the expansion tool further includes: a release device and a lock device inside a movable housing, wherein the lock device prevents shifting of the release device until the lock device is moved to an unlocked position by application of a first force to the lock device, and wherein the release device is movable to a release position by application of a second force after the lock device has been moved to the unlock position, and wherein the movable housing is capable of moving over the release device after the release device has been moved to the release position to absorb at least one of contraction and expansion of the string.
In another aspect, a method of performing a treatment operation in a wellbore is disclosed that in one non-limiting embodiment includes: placing a string in the wellbore, the string including a packer and an expansion tool downhole of the packer, wherein the expansion device includes a release device held in position by a lock device during run-in of the string into the wellbore; locating the packer at desired location; unlocking the lock device when the expansion tool is in the wellbore; releasing the release device by a tool conveyed from a surface location into the wellbore to cause the expansion tool to attain an expanded position so as to enable the expansion tool to absorb expansion and/or shrinkage of the string during the treatment operation; setting the packer in the wellbore; and performing the treatment operation.
Examples of the more important features of a well treatment system and methods that have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features that will be described hereinafter and which will form the subject of the claims.
BRIEF DESCRIPTION OF THE DRAWINGS
For a detailed understanding of the apparatus and methods disclosed herein, reference should be made to the accompanying drawings and the detailed description thereof, wherein like elements are generally given same numerals and wherein:
FIG. 1 shows an exemplary cased hole multi-zone wellbore containing a service assembly deployed therein that includes an outer string that includes a service tool section corresponding to each zone and wherein the outer string further includes an expansion tool corresponding to each zone, according to one non-limiting embodiment of the present disclosure;
FIGS. 2A, 2B, and 2C show a cross-section of a non-limiting embodiment of an expansion tool in a run-in position that may be utilized in a string in a wellbore, such as the outer string shown in FIG. 1;
FIGS. 3A and 3B show the cross-section of the expansion tool of FIGS. 2A, 2B, and 2C in an armed position after the string has been deployed in the wellbore;
FIGS. 4A and 4B show the cross-section of the expansion tool of FIGS. 3A and 3B in the released or deployed position;
FIGS. 5A and 5B show a cross-section of a non-limiting embodiment of a disconnect device that may be incorporated into the expansion tool of FIGS. 2A, 2B, and 2C;
FIG. 6 shows a cross-section of a non-limiting embodiment of a lock device that may be incorporated into the expansion tool of FIGS. 2A, 2B, and 2C;
FIG. 7 shows a cross-section of a non-limiting embodiment of a lock device that may be incorporated into the expansion tool of FIGS. 2A, 2B, and 2C; and
FIG. 8 shows a cross-section of a non-limiting embodiment of a release device that may be incorporated into the expansion tool of FIGS. 2A, 2B, and 2C.
DETAILED DESCRIPTION OF THE DRAWINGS
FIG. 1 is a line diagram of a section of a wellbore system 100 that is shown to include a wellbore 101 formed in formation 102 for performing a treatment operation therein, such as fracturing the formation (also referred to herein as fracing or fracking), gravel packing, flooding, etc. The wellbore 101 is lined with a casing 104, such as a string of jointed metal pipes sections, known in the art. The space or annulus 103 between the casing 104 and the wellbore 101 is filled with cement 106. The particular embodiment of FIG. 1 is shown for selectively fracking and gravel packing one or more zones in any selected or desired sequence or order. However, wellbore 101 may be configured to perform other treatment or service operations, including, but not limited to, gravel packing and flooding a selected zone to move fluid in the zone toward a production well (not shown).The formation 102 is shown to include multiple production zones (or zones) Z1-Zn which may be fractured or treated for the production of hydrocarbons therefrom. Each such zone is shown to include perforations that extend from the casing 104, through cement 106 and to a certain depth in the formation 102. In FIG. 1, Zone Z1 is shown to include perforations 108a, Zone Z2 perforations 108b, and Zone Zn perforations 108n. The perforations in each zone provide fluid passages for fracturing each such zone. The perforations also provide fluid passages for formation fluid 150 to flow from the formation 102 to the inside 104a of the casing 104. The wellbore 101 includes a sump packer 109 proximate to the bottom 101a of the wellbore 101. The sump packer 109 is typically deployed after installing casing 104 and cementing the wellbore 101. After casing, cementing, sump packer deployment, perforating and cleanup operations, the wellbore 101 is ready for treatment operations, such as fracturing and gravel packing of each of the production zones Z1-Zn. The fluid 150 in the formation 102 is at a formation pressure (P1) and the wellbore 101 is filled with a fluid 152, such as completion fluid, which fluid provides hydrostatic pressure (P2) inside the wellbore 101. The hydrostatic pressure P2 is greater than the formation pressure P1 along the depth of the wellbore 101, which prevents flow of the fluid 150 from the formation 102 into the casing 104 and prevents blow-outs.
Still referring to FIG. 1, to treat (for example fracture) one or more zones Z1-Zn, a system assembly 110 is run inside the casing 104. In one non-limiting embodiment, the system assembly 110 includes an outer string 120 and an inner string 160 placed inside the outer string 120. The outer string 120 includes a pipe 122 and a number of devices associated with each of the zones Z1-Zn for performing treatment operations described in detail below. In one non-limiting embodiment, the outer string 120 includes a lower packer 124a, an upper packer 124m and intermediate packers 124b, 124c, etc. The lower packer 124a isolates the sump packer 109 from hydraulic pressure exerted in the outer string 120 during fracturing and sand packing of the production zones Z1-Zn. In this case the number of packers in the outer string 120 is one more than the number of zones Z1-Zn. In some cases, the lower packer 109, however, may be utilized as the lower packer 124a. In one non-limiting embodiment, the intermediate packers 124b, 124c, etc. may be configured to be independently deployed in any desired order so as to fracture and pack any of the zones Z1-Zn in any desired order. In another embodiment, some or all of the packers may be configured to be deployed at the same time or substantially at the same time. The packers 124a-124m may be hydraulically or mechanically set or deployed. The outer string 120 further includes a screen adjacent to each zone. For example, screen S1 is shown placed adjacent to zone Z1, screen S2 adjacent to zone Z2 and screen Sn adjacent to zone Zn. The lower packer 124a and intermediate packer 124b, when deployed, will isolate zone Z1 from the remaining zones: packers 124b and 124c will isolate zone Z2 and packers 124m-1 and 124m will isolate zone Zn. In one non-limiting embodiment, each packer has an associated packer activation device that allows selective deployment of its corresponding packer in any desired order. In FIG. 1, a packer activation/deactivation device 129a is associated with the lower packer 124a, device 129b with intermediate packer 124b, device 129c with intermediate packer 124c and device 129m with the upper packer 129m.
Still referring to FIG. 1, in one non-limiting embodiment, each of the screens S1-Sn may be made by serially connecting two or more screen sections with interconnecting connection members and fluid flow devices for allowing fluid to flow along the screen sections. The screens also include fluid flow control devices, such as sliding sleeve valves 127a (screen S1), 127b (screen S2), 127n (screen Sn) to provide flow of the fluid 150 from the formation 102 into the outer string 120. The outer string 120 also includes, above each screen a flow control device, referred to as a slurry outlet or a gravel exit, which may be a sliding sleeve valve or another valve, to provide fluid communication between the inside 120a of the outer string 120 and each of the zones Z1-Zn. As shown in FIG. 1, a slurry outlet 125a is provided for zone Z1 between screen S1 and its intermediate packer 124b, slurry outlet 125b for zone Z2 and slurry outlet 127n for zone Zn. The outer string 120 is run in the wellbore with the slurry outlets (125a-125n) and flow devices 127a-127n closed. The slurry outlets and the flow devices can be opened downhole. The outer string 120 also includes a zone indicating profile or locating profile for each zone, such as profile 190 for zone Z1.
Still referring to FIG. 1, the inner string 160 (also referred to herein as the service string) includes a tubular member 161 that in one embodiment carries an opening shifting tool 162 and a closing shifting tool 164. The inner string 160 further may include a reversing valve 166 that enables the removal of treatment fluid from the wellbore after treating each zone, and an up-strain locating tool 168 for locating a location uphole of the set down locations, such as location 194 for zone Z1, when the inner string is pulled uphole, and a set down tool or set down locating tool 170 is set. In one aspect, the set down tool 170 may be configured to locate each zone and then set down the inner string 160 at each such location for performing a treatment operation. The inner string 160 further includes a crossover tool 174 (also referred to herein as the “frac port”) for providing a fluid path 175 between the inner string 160 and the outer string 120.
To perform a treatment operation in a particular zone, for example zone Z1, lower packer 124a and upper packer 124m are set or deployed. Setting the upper packer 124m and lower packer 124a anchors the outer string 120 inside the casing 104. The production zone Z1 is then isolated from all the other zones. To isolate zone Z1 from the remaining zones Z2-Zn, the inner string 160 is manipulated so as to cause the opening tool 164 to open a monitoring valve 127a in screen S1. The inner string 160 is then manipulated (moved up and/or down) inside the outer string 120 so that the set down tool 170 locates the locating or indicating profile 190. The set down tool 170 is then manipulated to cause it to set down inside the string 120. When the set down tool 170 is set, the frac port 174 is adjacent to the slurry outlet 125a and thereby isolating or sealing a section that contains the slurry outlet 125a and the frac port 174, while providing fluid communication between the inner string 160 and the slurry outlet 125a. The packer 124b is then set to isolate zone Z1 unless previously set. Once the packer 124b has been set, frac sleeve 125a is opened, as shown in FIG. 1, to supply slurry or another fluid to zone Z1 to perform a fracturing or a treatment operation as shown by arrows 180. When the outer string 120 and inner string 160 are deployed in the wellbore, the temperature inside the wellbore is close to the formation temperature. During a treatment operation, a fluid or slurry, such as a combination of water and guar along with proppant (typically sand), is supplied from the surface, which fluid is at a surface temperature substantially below the downhole temperature. This lower temperature can cause the outer string to undergo changes in length. Once the treatment operations have been completed, the outer string again may undergo length changes due to higher downhole temperature. The disclosure herein, in one aspect, provides an expansion tool (also referred to herein as the expansion joint) to accommodate for the changes in the outer string length. In one aspect, an expansion tool is placed below certain packers, such as an expansion tool 195b below packer 124b, expansion tool 195c below packer 124c and expansion tool 195m below packer 124m. In some situations, the inner string 160 can become stuck inside the outer string 120 due to excessive amount of sand settling near the frac port which prevents removal of the inner string 60 from the outer string without secondary operations.
FIGS. 2A, 2B, and 2C show a cross-section of a non-limiting embodiment of an expansion tool or device 200 in a run-in position that may be utilized in a suitable string deployed in a wellbore, including, but not limited to, the outer string 120 shown in FIG. 1. The expansion tool 200 includes a top sub 201 having a connection 202 for connection to a tubing uphole of the tool 200 and a bottom sub 206 having a connection 208 for connection to a tubing downhole of the expansion tool 200. The expansion tool 200 has a central bore 209 along a central axis 205. The expansion tool 200 further includes a housing 219 comprising an upper housing 210 axially connected to a lower housing 212 at a threaded connection 211. In a non-limiting embodiment, the expansion tool 200 includes a release collet 220, a release device or sleeve 240 and a lock device or sleeve 260 serially disposed inside the housing 219. The release collet 220 is attached at its upper end 221 to the top sub 201, such as by threads 223. The release collet 220 includes a tubular member 224 that includes a collet 222 having a number of collet fingers 222a, 222b, etc. Each collet finger has a profiled end. For example, finger 222a has a profiled end 230a, finger 222b has a profiled end 230b, etc. In the run-in position of the expansion tool 200 shown in FIGS. 2A, 2B, and 2C, the end 230a of collet finger 222a is shown to include: a lock end or lock face 228a that abuts against or is enclosed by a lock profile 215 along an inner surface of the upper housing 210; and an outer surface or profile 232a. Similarly, end 230b of finger 222b includes a lock face 228b and an outer surface or profile 232b. The upper housing 210 may slide or move along a portion 226 of the longitudinal member 224, wherein a seal is formed between the upper housing 210 and the longitudinal member 224 of the release collet 220. In this position, the housing 219 is prevented from moving downhole (i.e., to the right in the configuration of FIGS. 2A, 2B, and 2C) due to the locking of the ends 228a, 228b with the end 215 of the housing 210.
Still referring to FIGS. 2A, 2B, and 2C, the release sleeve 240 has a longitudinal member 242 that has an upper end 244a below the finger ends 232a, 232b and a collet 250 at the other end 244b. The collet 250 includes a solid end 254 and a number of sections, each such section having a double-ended profile. In FIGS. 2A, 2B, and 2C, the collect sections are shown as 254a, 254b, etc., wherein section 254a includes a face 256a that rests against or is proximate to an inner profile 213 of the lower housing 212 and a second face 258a uphole of the face 256a. When the release sleeve 240 is pushed downhole (to the right in FIGS. 2A, 2B, and 2C), the collet section 254a will deflect radially and allow the face 256a to move to the right over the face 213 of the lower housing 212. In the run-in position this radial deflection is prevented by the sleeve 264. Other finger ends are similarly profiled. The release sleeve 240 is configured to move axially inside the lower housing 212 along an indented section 215a of the lower housing 212. The expansion tool 200 in the position shown in FIGS. 2A, 2B, and 2C is in the run-in position, i.e., the tool is ready to be conveyed into the wellbore. In the run-in position, the release sleeve 240 is prevented from moving to the right as the face 256a of the end 254a and end 256b of the end 254b are against or supported by the face 213 of the lower housing 212, which prevents movement of the release sleeve 240 to the right. The release sleeve 240 is prevented from moving uphole (to the left in FIGS. 2A, 2B, and 2C) because the profile 232a, 232b, etc. of the finger 230a, 230b, etc. prevent the profile 249 of the release sleeve 240 to move past the fingers 230a, 230b. Thus, in the run-in position, the release sleeve 240 remains between the release collet 220 and the lock device 260.
Still referring to FIGS. 2A, 2B, and 2C, the lock device 260 includes a tubular member 262 that has an upper section 264 inside the collet section 255 of the release sleeve and can slide over the collet fingers 254a, 254b, etc. The lock device 260 has an upper seal section 270 formed by a seal, such as o-ring 272a, between the member 262 and the lower housing 212 and a lower seal section 272 formed by a seal, such as o-ring 272b, between the member 262 and the lower housing 212. In one aspect, the area A1 of the seal section 270 is greater than the area A2 of the seal section 272. In one aspect, the area A1 may be defined by the diameter d1 of the seal 272a and the area A2 may be defined by the diameter d2 of the seal 272b. In one aspect, the difference between the areas A1 and A2 is such that when a fluid pressure above a selected amount or threshold is applied to inside the lock device 260, the member 262 and thus lock device 260 will move downhole (to the right). Until the selected pressure is applied to the lock device, a shear pin 276 prevents movement of the member 262, and thus keeps the lock device 260 from moving or activating, inside the housings 219. Wickers 278 on a lock ring 288 and wickers 264 on the lock sleeve 260 may be provided, as shown in FIGS. 2A, 2B, and 2C, to prevent movement of the lock device 260 to the left (uphole). Also, solid end 254 of the release sleeve 240 prevents movement of the lock device 260 uphole (to the left). In this position, lock device 260 remains between the release sleeve 240 and at a distance d3 from the end 217 of the lower housing 212. The distance d3 between the end 266 of the lock sleeve and the end 217 of the lower housing 212 defines the travel of the lock device 260, when the shear pin 276 is sheared as described below in reference to FIGS. 4A and 4B. Wickers 268 on the lock ring 288 are provided to lock with the wickers 278 on the lower housing 212 to prevent movement of the lock device 260 to the left, once the lock device 260 has moved to the right as described in more detail below in reference to FIGS. 3A and 3B.
In operation, the expansion tool 200 is placed between two tubular members in a string, such as string 120, shown in FIG. 1. The string 120 is then deployed into the well. Referring now to FIGS. 3A and 3B, the pressure inside the string 120 and thus inside the passage 209 is raised to a level sufficient to create a selected or desired pressure differential between the areas A1 and A2 to cause the lock sleeve 260 to move to the right and thus shear the shear pin 276. Shearing of the shear pin 276 (as shown by sheared portions 276a and 276b) causes the lock sleeve 260 to move to the right by the distance d3, causing the end 266 of the lock sleeve 260 to abut against the end 217 of the lower housing 212. Also, wickers 268 on the lock device 260 engage with the wickers 278 on the lower ring 288. The expansion tool 200, as shown in FIGS. 3A and 3B, is referred to be in the armed position and is ready to be moved into the final position, referred to herein as the “released position” or “deployed position,” upon the application of a selected mechanical force to the release sleeve 240, as described below in reference to FIGS. 3A, 3B, 4A and 4B.
Referring now to FIGS. 3A, 3B, 4A and 4B, to set the expansion tool 200 in the released or deployed position, a mechanical shifting tool (known in the art) is conveyed into the string 120 and engaged with the release sleeve 240. Pushing the shifting tool downward (to the right) causes the collet 250 to collapse, thereby causing the profile 256a, 256b of the release sleeve to disengage from the profile 213 of the lower housing 212, which allows the release sleeve 240 to move downhole (to the right), as shown in FIGS. 4A and 4B. The profiles 258a, 258b, etc. of the collet 250 pass over the profile 219 on the lower housing 212, which prevents the release sleeve 240 from moving uphole (to the left). In the released position, as shown in FIGS. 4A and 4B the expansion tool 200 attains the deployed or expanded position.
Referring now to FIGS. 1, 4A and 4B, the string 120 containing one or more expansion tools, such as expansion tools 195a-195n, is deployed into the wellbore 101. The expansion tools 190a-190n are then placed in their respective released positions, as described above in reference to FIGS. 3A, 3B, 4A and 4B. The wellbore 101 at this stage is at the formation temperature, which causes the expansion tools 195a-195n to achieve their expanded positions. The packers 124a-124n are then set either one at a time or all at the same time, causing the outer string 120 to anchor into the casing 104. During a treatment operation, such as fracing, the fluid supplied is at a temperature lower than the temperature of the wellbore, which may cause the string 120 to contract. As the string 120 contracts, the expansion tools 195a-195n contract correspondingly. In the particular embodiment of the expansion joint 200, contraction of the string 120 will cause the top sub 201 and the bottom sub 206 to contract, which will cause the housings 219 to move to the left over the release collet 220 and the release sleeve 260, thereby absorbing the shrinkage of the string 120. In one aspect, an expansion joint may be placed below (downhole) each packer at a suitable location, such as above the screens S1-Sn, as shown in FIG. 1. In such a configuration each zone Z1-Zn will include an expansion tool to operate when its corresponding zone is being treated.
In another aspect, the expansion tool 200 may further include a disconnect or a disconnect tool that enables disconnecting the string 120 from the expansion tool 200, which expansion tools may be placed at suitable locations below the packers. Referring to FIGS. 2A, 2B, and 2C, the expansion tool 200 is shown to include a non-limiting embodiment of a disconnect tool or disconnect device 280. In one non-limiting embodiment, the disconnect tool 280 includes a collet 282 that has a solid ring 281 on one end and collet fingers 282a, 282b, on the other end. A solid ring 289 with a shear pin 292 prevents the collet 282 from moving to the right. A seal 287 is provided between the solid ring 289 and another solid ring 288. The collet fingers 282a, 282b respectively include profiles 284a, 284b that abut against an inner profile 285 on the upper housing 210 that prevents the movement of the collet 280 to the left. To disconnect the string 120 from the expansion tool, a set down tool is conveyed into the string 120 and engaged with the top sub 201. When the set down tool is pulled uphole with a force above a selected load, the collet fingers 282a, 282bb disengage from the profile 285 of the upper housing 210, which breaks the shear pin 292, causing the release sleeve 220 to disengage from the profile 215 of the upper housing, thereby disconnecting the top sub 201 the release collet 220, collet 282, solid ring 288, seal 287 and solid ring 289, as shown in FIGS. 5A and 5B. The remaining components of the disconnect remain attached to the lower sub 206.
In aspects, the non-limiting embodiment of the expansion tool 200 described herein includes tubing to annulus seals that create a pressure barrier between the exterior and interior of the expansion tool 200. The expansion tool 200 geometry allows torque communication across the tool from the top sub 201 to the bottom sub 206. The expansion tool 200 also communicates axial tension and compression prior to activating the expansion tool 200 to the release or deployed position shown in FIGS. 4A and 4B. A suitable tool, such as shifting tool (known in the art), may be utilized to release the expansion tool 200, which allows it to stroke while maintaining seal integrity and absorbing axial changes in the expansion tool length due to thermal effects on its various components. A locking mechanism or device or member, such as the lock sleeve 260, prevents premature shift of the release sleeve 240. Once the expansion tool 200 has been located properly in the wellbore, the locking mechanism is activated, allowing the release sleeve 240 to be shifted mechanically when desired. As is well known in the art, many factors including internal/external fluid circulation, formation composition, depth, and geological conditions create a temperature cycle affecting the physical length of tools in the outer sting 120, an effect that is cumulative and increases over distances. Increased tensile/compressive forces acting upon rigid components can cause stress failures lacking a device to absorb these forces. The expansion joint 200 shares system burst and collapse pressure, allows torque as well as tensile “pull” and compression “push” communication through the expansion tool 200 from one end connection (top sub 201) to the other end connection (bottom sub 206) until unlocked then released in separate operations, which operation disengages collet fingers that can deflect out of a collet finger groove allowing stroke along a seal diameter. During run-in, the expansion tool 200 is locked and the collet fingers transfer tension while compression is applied from the top sub to the outer housing. . Once the gravel pack assembly is downhole and located properly, the lock feature can be activated allowing the release sleeve to be shifted when ready. Packers are set and a gravel pack is performed, locking the expansion tool somewhat in place by packing the annular area around the expansion tool with a filter media. Temperature changes at this point would apply stresses to the string 120 and the expansion tool 200 axially. After the gravel packing, the release sleeve is shifted to release the collet fingers to allow axial forces to stroke the expansion tool to remove the accumulated effect over the length of the completion. The lock feature prevents accidental shifting of the release sleeve 240 during run-in and other operations. The lock feature can be actuated at surface without the need to run a shifting tool. Should assembly removal after expansion tool release be necessary, an optional snap ring in the assembly can allow the removal of lower components upon reaching the expansion joints maximum stroke, or the absence of the snap ring would allow a complete separation of the upper and lower expansion joint allowing future tools to snap into and seal within the remaining geometry. Additionally, the individual actuation of both the lock sleeve and the release sleeve may be initiated hydraulically, pneumatically, mechanically, via stored energy such as pressure chamber or energized spring, expanding/contracting material, motorized, or by any energy source. The locking mechanism which holds tension during run-in and possibly provides a “push” shoulder could be collet fingers, colleted threads, locking dogs, or other geometry that provides a shoulder to apply tension against and/or push or compression.
Referring to FIG. 6 a lock device 360 is shown. In the illustrated embodiment, the lock device 360 includes a degradable portion 362. The lock device 360 can be used with the expansion tool 200 described herein to replace or in addition to the lock devices described herein.
In the illustrated embodiment, the degradable portion 362 is formed from a degradable material, including, but not limited to a controlled electrolytic metallic. In the illustrated embodiment the degradable portion 362 can degrade and/or dissolve in response to exposure to a downhole environment, including exposure to wellbore fluids. The degradation time of the degradable portion 362 can be selected to be any suitable time for a desired application. Therefore, during run in of the expansion tool 200, the degradable portion 362 of the lock device 360 can prevent motion of a release device to prevent the release device from inadvertently releasing during run in. Further, in the illustrated embodiment, after the degradable portion 362 is sufficiently degraded from wellbore environment exposure, the degraded lock device 360 can allow movement of the release device to allow the release device of the expansion tool 200 to be actuated.
Referring to FIG. 7 a lock device 460 is shown. In the illustrated embodiment, the lock device 460 is a mechanical locking device that is actuated by a mechanical shifting tool. In the illustrated embodiment, the lock device 460 may operate similarly to the mechanical release device 240 described herein. The lock device 460 can be used with the expansion tool described herein to replace or in addition to the lock devices described herein. In the illustrated embodiment, the lock device 460 can utilize a different profile of a mechanical shifting tool to allow a single or multiple shifting tools to actuate a lock device 460 and a release device 440.
In the illustrated embodiment, in an initial position the lock device 460 can be engaged to a profile 213 to keep the lock device 460 in an initial position. During run in of the expansion tool 200, the lock device 460 can prevent motion of the release device 440 to prevent the release device 440 from inadvertently releasing during run in. When the lock device 460 is desired to be unlocked, a mechanical shifting tool (known in the art) is conveyed into the string 120 and engaged with the lock device 460. Pushing the shifting tool downward (to the right) causes the lock device 460 to disengage from the profile 213 of the lower housing 212, which allows the lock device 460 to move downhole (to the right). After the lock device 460 is moved, the lock device can allow movement of the release device 440 to allow the release device 440 of the expansion tool 200 to be actuated.
Referring to FIG. 8 a release device 540 is shown. In the illustrated embodiment, the release device 540 is a hydraulic release device that is actuated by applied fluid pressure. In the illustrated embodiment, the release device 540 may operate similarly to the lock device 260 described herein. The release device 540 can be used with the expansion tool described herein to replace or in addition to the release devices described herein.
In the illustrated embodiment, the release device 540 has an upper seal section 270 formed by a seal, such as o-ring 270a, between the member 262 and the lower housing 212 and a lower seal section 272 formed by a seal, such as o-ring 272a, between the member 262 and the lower housing 212. In one aspect, the area Al of the seal section 270a is greater than the area A2 of the seal section 272a. In one aspect, the area A1 may be defined by the diameter d1 of the seal 270a and the area A2 may be defined by the diameter d2 of the seal 272a. In one aspect, the difference between the areas A1 and A2 is such that when a fluid pressure above a selected amount or threshold is applied to inside the release device 540, the member 262 and thus release device 540 will move downhole (to the right).
In the illustrated embodiment, during run in a lock device 560 can prevent movement of the release device 540. After the lock device 560 is moved to an unlocked position, the release device 540 can be actuated to release the release device 540 to allow the expansion tool 200 to be actuated. In the illustrated embodiment, the release device 540 can be actuated by application of fluid pressure. In the illustrated embodiment, the pressure inside the string 120 is raised to a level sufficient to create a selected or desired pressure differential between the areas A1 and A2 to cause the release device 540 to move to the right to allow the expansion tool 200 to be actuated.
In certain embodiments, various combinations of lock devices and release devices can be utilized together to control the deployment of the expansion tool. In the illustrated embodiment, an expansion tool can utilize a lock device that is hydraulically actuated and a release device that is mechanically actuated, a lock device that is degradable and a release device that is mechanically actuated, a lock device that is mechanically actuated and a release device that is mechanically actuated, a lock device that is degradable and a release device that is hydraulically actuated, and a lock device that is mechanically actuated and a release device that is hydraulically actuated. In other embodiments, any other suitable combination of lock devices and release devices can be utilized.
The foregoing disclosure is directed to the certain exemplary embodiments and methods according to one or more non-limiting embodiments of the apparatus and methods described herein. Various modifications to such apparatus and methods will be apparent to those skilled in the art. It is intended that all such modifications within the scope of the appended claims be embraced by the foregoing disclosure. The words “comprising” and “comprises” as used in the claims are to be interpreted to mean “including, but not limited to”. Also, the abstract is not to be used to limit the scope of the claims.
Patent Application
20170183919
