Abstract
A squeeze packer (1) assembly incorporates a built-in setting tool which removes the need for a separate setting tool. The packer comprises a body comprising a mandrel (9), a shuttle sleeve (7), and a stinger (2) assembly which is lowered into the wellbore on the end of tubing (102). The shuttle sleeve is housed within the body and incorporates a latch device in the form of a collet comprising a plurality of resilient fingers (14) to releasably connect to the stinger. A ball seat (15) allows hydraulic setting of slips (3). Additional slips (4) can be set by applying tension on the tubing (FIG. 4). Once released, the stinger can open and close the shuttle sleeve by reciprocating in and out of the packer as many times as required during cementing operations.
Claims
1. A squeeze packer assembly for deployment in a wellbore of an oil, gas or water well on an elongate member, the squeeze packer assembly comprising a body having a bore, at least one anchoring member actuable between active and inactive configurations in response to changes in fluid pressure, and wherein in the active configuration, the anchoring member is adapted to anchor the body in the wellbore to resist axial movement of the body in the wellbore, and a sealing member adapted to seal an annulus between the body and an inner surface of the wellbore; a stinger adapted for connection to the elongate member for injection of a fluid through the bore of the body; a latch adapted to releasably latch the stinger onto the body; and a valve selectively actuable to open and close the bore to allow and prevent fluid passage through the body, wherein the valve controls passage of pressurised fluid to the anchoring member to actuate the anchoring member between inactive and active configurations, and wherein the valve is controlled by axial movement of the stinger and the elongate member relative to the body to actuate the valve between different actuation configurations, and wherein the stinger is released from the body by rotation of the elongate member in a direction opposite to a direction of rotation used to disconnect threaded couplings making up the elongate member; wherein the anchoring member comprises first and second sets of slips and wherein the first set of slips is set by hydraulic pressure before the second set is set mechanically by exerting an axial force on the elongate member.
2. The squeeze packer assembly as claimed in claim 1, wherein the valve comprises a sleeve slidable axially within the bore of the body to shift the valve between different actuation states.
3. The squeeze packer assembly as claimed in claim 1, wherein the latch comprises a collet having plurality of resilient fingers disposed on the end of a sleeve slidable axially within the bore of the body, wherein the sleeve comprises one or more ports to permit fluid flow, and wherein the resilient fingers are resiliently biased radially inwards with respect to an axis of the collet and wherein the resilient fingers on the collet releasably engage with a recess on the stinger.
4. The squeeze packer assembly as claimed in claim 3, wherein the collet comprises a cylindrical sleeve with an inwardly projecting cylindrical shoulder mounted on at least two of the fingers which combine to form a seat to receive and to seat a valve closure device.
5. The squeeze packer assembly as claimed in claim 1, wherein the valve has a seat disposed in the bore of the body and wherein seating a valve closure member on the seat diverts fluid through the bore of the body to set a first set of slips forming an anchoring member.
6. The squeeze packer assembly as claimed in claim 5, wherein the seat is resiliently biased radially inwards, and upon removal of the bias is adapted to resiliently expand to release a seated valve closure member.
7. The squeeze packer assembly as claimed in claim 1, wherein the valve comprises a cylindrical sleeve slidable axially in a valve housing having a clearance gap between the valve housing and the cylindrical sleeve.
8. The squeeze packer assembly as claimed in claim 1, wherein the valve is adapted to slide axially in the bore of the body after hydraulic setting of the anchoring member.
9. The squeeze packer assembly as claimed in claim 1, wherein the force on the elongate member to set the second set of slips activates the sealing member.
10. The squeeze packer assembly as claimed in claim 1 wherein the stinger has a smooth outer surface.
11. The squeeze packer assembly as claimed in claim 1, wherein the valve is adapted to be repeatedly cycled within the body between different configurations to open and close the bore through the packer before injecting fluid through the bore of the packer.
12. The squeeze packer assembly as claimed in claim 1, wherein the latch is adapted to cycle between disconnected and connected configurations to disconnect and reconnect the stinger and the packer.
13. The squeeze packer assembly as claimed in claim 1, incorporating a seat adapted to be closed by a valve closure member, wherein the seat remains static within the bore in open and closed configurations of the valve, and wherein the valve comprises a sleeve adapted to move axially within the bore relative to the static seat, between the open and closed configurations.
14. The squeeze packer assembly as claimed in claim 13, wherein the sleeve has a first section with a first diameter and a second section with a second diameter different from the first diameter, and wherein in an open configuration, the seat is disposed within the first section and in the closed configuration, the seat is disposed in the second section.
15. The squeeze packer assembly as claimed in claim 14, wherein the sleeve has a waist between the first and second sections, and wherein the waist incorporates a step in the inner and outer diameters of the sleeve.
16. The squeeze packer assembly as claimed in claim 15, having an annular fluid flowpath between the first section of the sleeve and the bore, wherein the outer diameter of the sleeve steps radially outward at the interface between the first section and the waist, and wherein the inner diameter of the sleeve steps radially outward at the interface between the second section and the waist, and wherein the sleeve has an annular fluid flowpath between the second section of the sleeve and the seat.
17. A method of injecting a fluid into a wellbore of an oil, gas or water well through an elongate member, the method comprising: deploying a squeeze packer into the wellbore, the squeeze packer comprising: a body with a bore, at least one anchoring member actuable between active and inactive configurations in response to changes in fluid pressure, and wherein in the active configuration, the anchoring member is adapted to anchor the body in the wellbore to resist axial movement of the body in the wellbore, and a sealing member adapted to seal an annulus between the body and an inner surface of the wellbore; a stinger adapted for connection to the elongate member for injection of a fluid through the packer, the stinger being releasably latched onto the body; and a valve selectively actuable to open and close the bore to allow and prevent fluid passage through the body, wherein the valve controls passage of pressurised fluid to the anchoring member to actuate the anchoring member between inactive and active configurations; the method including: anchoring the squeeze packer in the wellbore and sealing the annulus between the body and the inner surface of the wellbore; releasing the stinger from the packer by rotation of the elongate member in a direction opposite to the direction of rotation used to disconnect the threaded couplings making up the elongate member, and moving the stinger axially within the body to actuate the valve between different actuation configurations; wherein the anchoring member comprises first and second sets of slips and wherein the first set of slips is set by hydraulic pressure before the second set is set mechanically by exerting an axial force on the elongate member.
18. The method as claimed in claim 17, including actuating the valve to control passage of pressurised fluid to the anchoring member to actuate the anchoring member between inactive and active configurations.
19. The method as claimed in claim 17, wherein the valve includes a sleeve, including sliding the sleeve axially within the bore between different actuation configurations of the packer, and including sliding the sleeve relative to a seat adapted to close the bore by seating of a valve closure member on the seat.
20. The method as claimed in claim 19, wherein the sleeve has a first section with a first inner diameter and a second section with a second inner diameter, and wherein the method include sliding the sleeve over the seated valve closure member on the seat between a first valve configuration and a second valve configuration, wherein in the first valve configuration the valve closure member is in the first section and fluid cannot pass through the sleeve, and wherein in the second valve configuration, the valve closure member is in the second section of the sleeve, and wherein fluid can pass through the sleeve.
21. The method as claimed in claim 17, wherein the stinger is adapted to be connected to the body by a threaded connection, wherein the thread is connected by anti-clockwise rotation of the stinger with respect to the body and is disconnected by clockwise rotation of the stinger with respect to the body, and wherein the stinger is disconnected from the body by clockwise rotation relative to the body.
22. The method as claimed in claim 17, wherein the valve has a seat disposed in the bore and wherein the method includes seating a valve closure member on the seat and setting the anchoring member by hydraulic pressure diverted through the bore of the body by the valve closure member on the seat.
23. The method as claimed in claim 17, wherein the stinger is adapted to be latched to the valve, and wherein the method includes latching the stinger to the valve and sliding the valve between different actuation configurations by axial movement of the stinger relative to the body, releasing the stinger from the body and unlatching the stinger from the valve, circulating fluid through the stinger to pressure test the seal between the sealing member and the inner surface of the wellbore, reconnecting the stinger to the body and re-latching the stinger to the valve and sliding the valve between different actuation configurations by axial movement of the stinger relative to the body.
24. A squeeze packer assembly for deployment in a wellbore of an oil, gas or water well on an elongate member, the squeeze packer assembly comprising a body having a bore, at least one anchoring member actuable between active and inactive configurations in response to changes in fluid pressure, wherein the anchoring member comprises first and second sets of slips and wherein the first set of slips is set by hydraulic pressure before the second set is set mechanically by exerting an axial force on the elongate member, and wherein in the active configuration, the anchoring member is adapted to anchor the body in the wellbore to resist axial movement of the body in the wellbore, and a sealing member adapted to seal an annulus between the body and an inner surface of the wellbore; a stinger adapted for connection to the elongate member for injection of a fluid through the body; a latch adapted to releasably latch the stinger onto the body; and a valve selectively actuable to open and close the bore to allow and prevent fluid passage through the body, wherein the valve controls passage of pressurised fluid to the anchoring member to actuate the anchoring member between inactive and active configurations, and wherein the valve is controlled by axial movement of the stinger and the elongate member relative to the body to actuate the valve between different actuation configurations; wherein the stinger is connected to the body by a threaded connection, wherein the thread is connected by anti-clockwise rotation of the stinger with respect to the body and is disconnected by clockwise rotation of the stinger with respect to the body, and wherein the stinger is adapted to be disconnected from the body by clockwise rotation relative to the body; wherein the valve has a seat disposed in the bore and wherein seating a valve closure member on the seat sets the anchoring member by hydraulic pressure diverted through the bore of the body by the valve closure member on the seat; and wherein the sealing member is expanded in the annulus between the body and an inner surface of the wellbore to seal the annulus by pulling up on the elongate member.
Description
BRIEF DESCRIPTION OF THE DRAWINGS
(1) In the accompanying drawings:
(2) FIG. 1 shows a schematic sectional front view of a packer in the running in position as it is lowered into the wellbore;
(3) FIG. 2 shows a close up schematic sectional front view of the FIG. 1 packer showing a valve in the running in position with the circulation ports aligned, a ball on a ball seat, and a stinger latched onto the valve;
(4) FIG. 3 shows a schematic sectional front view of the FIG. 1 packer with upper slips set by applied hydraulic pressure acting on the ball on the seat;
(5) FIG. 4 shows a schematic sectional front view of the FIG. 1 packer with lower slips set by pulling the drill string/tubing upwards which also compresses the elastomeric/rubber element;
(6) FIG. 5 shows a schematic sectional front view of the FIG. 11 packer once the stinger has disconnected from the valve which has opened up and allowed the ball to fall into a pocket;
(7) FIG. 6 shows a close up schematic sectional front view of FIG. 5 showing the valve in the closed position as the stinger has axially moved upwards and the ball falls into the pocket due to the ball seat springing back to its original relaxed state and creating a larger internal diameter than the outer diameter of the ball;
(8) FIG. 7 shows a schematic sectional front view of the FIG. 1 packer with the stinger lowered back into the packer and cement displaced through the tubing, out the circulation ports into the wellbore and into the perforations;
(9) FIG. 8 shows a close up schematic sectional front view of the FIG. 7 position with the valve in the open position after the stinger has lowered and latched onto the valve, allowing fluid flow through the aligned circulation ports;
(10) FIG. 9 shows a schematic sectional front view of the FIG. 1 packer after remedial cementing has taken place with the stinger released from the squeeze packer and thus closing the valve, retaining the cement;
(11) FIG. 10 shows a schematic sectional front view of an alternative release method where the stinger is released from the packer by over pull on the drill string/tubing and shearing a set of shear pins at a predetermined value;
(12) FIG. 11 shows a schematic sectional front view of an alternative example where a disposable cleaning element, in this case a brush, is attached to the bottom of the packer and used to clean the setting area and the micro annulus to allow an optimised sealing engagement between the wellbore and the packer;
(13) FIG. 12 shows an optional modification of a squeeze packer assembly where perforation guns are connected to the end of the packer. This allows the complete remedial cementing operations to be conducted on a single run;
(14) FIG. 13 shows an optional modification of the squeeze packer assembly in which the valve comprises a sleeve which slides axially downwards relative to a static ball seat in the housing which allows hydraulic pressure to build up and set the upper slips;
(15) FIG. 14 shows the FIG. 13 arrangement with the sleeve sliding upwards into a closed configuration; and
(16) FIG. 15 shows the FIG. 13 arrangement with the sleeve sliding downwards into a circulating position.
DETAILED DESCRIPTION
(17) FIG. 1 shows a cross-section view of a first example of a squeeze packer assembly comprising a packer 1 and a stinger 2; in this example, the packer 1 is a cement squeeze packer. In FIG. 1 the packer 1 is connected to tubing 102 (which could be drill pipe) via the stinger 2 and a crossover 101. The tubing 102 has a bore 103. The packer assembly is deployed in a wellbore 100 drilled in a formation 107 and cased by metal casing or similar. In this wellbore, the cement job has deteriorated forming an annulus 108 between the casing and the wellbore 100, which is to be repaired using the packer assembly. The packer 1 is lowered into the wellbore 100 via tubing 102 to the required setting depth, in this example, just above lower perforations 106 formed through the casing, optionally in an earlier trip. The stinger 2 is coupled to the crossover 101 via a standard oilfield connection (e.g. a box and pin arrangement having a conventional right hand thread).
(18) The packer 1 has a body comprising a central mandrel 9 having a central bore 9b. The mandrel 9 has a socket at its upper end which receives a lower stem of an upper setting sleeve 12, also having a bore which is co-axial with the bore 9b of the mandrel 9. The upper setting sleeve 12 is connected to the mandrel 9 via shear pins 29 passing radially through the socket and into the stem. Above the stem, the upper section of the upper setting sleeve 12 has a guide in the form of a funnel which tapers radially inward from a wide diameter opening at the top of the funnel to a narrow throat at the junction between the upper section and the stem of the upper setting sleeve 12. The throat is co-axial with the bore of the upper setting sleeve 12 and with the bore of the mandrel 9, and the opening to the throat has a female thread 33 on its inner surface which has an opposite hand to the normal thread used to make up the standard oilfield connections (best seen in FIG. 9). In this example, the thread is a right hand thread, being connected by anti-clockwise rotation of a male threaded member in the bore, and being disconnected by clockwise rotation. The stem of the upper setting sleeve 12 is generally cylindrical and is surrounded by an outer setting sleeve 27, which receives the upper setting sleeve 12 in a cylindrical socket permitting sliding movement between the sleeves 12, 27. The socket is chamfered at its lower end, forming a stop to limit axial sliding of the upper sleeve 12 within the outer sleeve 27 just as the lower surface of the funnel shoulders out on the upper surface of the outer setting sleeve 27. The upper sleeve has radial ports 26 connecting the bore of the upper setting sleeve 12 with its outer surface.
(19) The mandrel 9 is generally cylindrical, and on its outer surface, it carries anchoring and sealing members, optionally in the form of sleeves in this example, which anchor the packer in place, and seal the annulus between the packer 1 and the inner surface of the wellbore 100. Below the outer setting sleeve 27, and surrounding the interface between the upper setting sleeve 12 and the socket in the mandrel 10, is a skirt, having a radially extending flat lower surface forming a shoulder that engages an upper surface of an anchoring member in the form of an upper set of slips 3 having an inner profile with a wedge shape that cooperates with a cone 10, and an outer profile that grips the inner surface of the wellbore. The interface between the skirt and the upper slips 3 is optionally smooth, allowing the slips 3 to slide radially outwards against the skirt. The slips 3 in this example are formed as separate parts, circumferentially spaced around the outer circumference of the mandrel 9. The upper slips 3 and cone 10 are slidable axially relative to the mandrel 9, and are arranged so that axial sliding movement of the cone 10 toward the slips 3 causes the slips 3 to move radially outwards, to grip the inner wall of the wellbore 100. Below the cone 10, a sealing member in the form of an elastomeric sealing element 5 is supported between oppositely oriented seal shoes, and is optionally split into several axially separate parts. Below the elastomeric ceiling element 5, a set of lower slips 4 and corresponding cone 11 is provided having a similar configuration to the upper slips 3 and clone 10, but oriented in the opposite direction. Below the lower slips 4, an end collar 32 is mounted on the outer surface of the mandrel 9, and in this example is fixed to the mandrel 9 and cannot slide along its outer surface as the cones and slips can. At the lower end of the mandrel 9 a screw thread connection attaches an end cap 40.
(20) The central bore 9b extending through the body of the mandrel 9 is counter-bored at its lower end, to a larger diameter in order to receive a valve within the bore. The upper portion of the end cap 40 connected to the mandrel 9 also has a similar diameter of bore, and together the large diameter bores of the end cap 40 and mandrel 9 allow the valve to shuttle axially by sliding within the enlarged bore in order to open and close ports 8 in the end cap 40.
(21) The stinger 2 is received within the bore of the mandrel 9 and extends axially through the mandrel 9 into the larger bore chamber containing the valve. In this example, the body of the valve comprises a shuttle sleeve 7 having valve ports 16 in the form of slots which extend axially along the shuttle sleeve 7. Optionally four valve ports 16 are spaced circumferentially at equal spacing around the shuttle sleeve 7, at the same axial position.
(22) The shuttle sleeve 7 is generally cylindrical and can be formed from spring steel or some other resilient material. At its lower end, the valve ports 16 are disposed above a solid section bounded by resilient circumferential seals 17 on the outer surface of the cylinder. As the shuttle sleeve 7 slides axially within the enlarged bore of the body, the seals 17 move over the circulation ports 8 extending radially through the end cap and move the valve ports 16 in and out of fluid communication with the circulation ports 8 to open and close the fluid conduit formed by the bore of the packer.
(23) At its upper end, the shuttle sleeve 7 has a latch device in the form of a collet comprising a plurality of resilient fingers 14 connected to the end of the sleeve in a cantilever manner and extending axially from a ball seat 15. The upper end of the shuttle sleeve 7 is relatively resilient, allowing the collet fingers 14 and the ball seat 15 to move radially into different configurations as will be described below.
(24) When run in hole, in the FIG. 1 configuration, the stinger 2 is engaged with the upper end of the shuttle sleeve 7 via the latching device provided by the collet fingers 14. The arrangement of slotted valve ports 16 on the shuttle sleeve 7 align with the circulation ports 8 on the end cap 40 thereby opening the bore through the packer and preventing surging of the well while running in. The assembly is run into the hole until it reaches the setting depth, where the perforations 106 in the wellbore 100 lead to the annulus 108 between the wellbore 100 and formation 107.
(25) The upper and lower slips 3, 4 are set to anchor the packer in position. The upper cone 10 is mounted on a body lock ring 6 where the surface of the internal diameter of the body lock ring 6 has teeth which cooperate with teeth on the mandrel 9 to permit movement of the body lock ring relative to the mandrel 9 in one direction only. In this example it allows the mandrel 9 to move upwards with respect to the cone 10 and resists movement of the upper cone 10 relative to the mandrel 9 when the packer 1 is set.
(26) The shuttle sleeve 7 is shown in more detail in FIG. 2, which shows the position after running into the hole and after an activation ball 25 has been dropped from surface and is seated on the ball seat 15 on the shuttle sleeve 7. The collet fingers 14 are flexible enough to radially expand and spring back to a resting state. Three fingers 14 are provided in this example, but optionally more fingers may be used in other examples. The collet fingers 14 have two main functions: to latch onto the stinger 2 and to provide a pressure retaining ball seat 15, which optionally releasably retains the ball 25. The stinger 2 has a recessed groove 19 on its outer surface with a profile which matches the profile on the internal surface of the tips 13 on the fingers 14. The tips 13 spread radially outwards when engaged by the chamfered end of the stinger 2 during initial assembly, and slide along the outer surface of the stinger until they reach the groove 19 above the stinger ports 18, just as the chamfered end of the stinger shoulders out on the upper face of the ball seat 15, which optionally has a complementary profile to the chamfer on the end face of the stinger 2. Once they reach the groove 19, the tips 13 close radially into the position shown in FIG. 2 and thereby latch the stinger 2 onto the upper end of the shuttle sleeve 7. The connection allows the valve to be opened and closed by axial reciprocation of the stinger. The connection between the shuttle sleeve 7 and the stinger is releasable as will be described below.
(27) Mounted on the same collet fingers 14, a ball seat 15 is provided. The ball seat 15 is radially expandable between the seating configuration shown in FIG. 2, in which the ball 25 is retained on the seat 15, and a release position shown in FIG. 6, where the ball 25 is released and can pass through the seat 15. In the FIG. 2 arrangement, the ball seat 15 is in the compressed seating configuration with a reduced internal diameter. When the ball 25 is seated on the seat 15 in this configuration, it can occlude the bore through the packer, and seating the ball 25 on the seat 15 optionally provides a pressure retaining seal in the bore. This can be used to divert fluid in the bore 9b via the stinger ports 18 to activate and set the upper slips as will be described below. An annular seal 35, made from an elastomeric compound or similar optionally provides the pressure retaining seal while the ball seat 15 is in the compressed state and an activation ball 25 is seated on the seat 15. Optionally the inter-engaging faces between the segments of the ball seat 15 have a close tolerance and when compressed together in the compressed seating configuration, they resist the passage of fluid between the segments. Optionally the segments can be coated with a resilient material to enhance their sealing ability when compressed into the seating configuration.
(28) A cylindrical valve housing sleeve 21 fixed in the bore of the mandrel 9 has a central bore that is co-axial with the bore 9b of the mandrel 9. The valve housing sleeve 21 houses the shuttle sleeve 7 and permits it to move axially within the bore of the valve housing sleeve 21 between different states of actuation. The valve housing sleeve 21 has a series of counter-bores forming a stepped internal profile which increases in diameter towards the upper end of the valve housing sleeve 21. Two steps are provided in the bore of the housing sleeve; namely a first step between a relatively narrow central section of the bore housing the seal 35 and an intermediate section 22 of the bore immediately above the central section, and a second step between the intermediate section 22 and an end section 23. The central section has a narrower internal diameter than the intermediate section 22, which has a narrower internal diameter than the end section 23. The internal diameter of the intermediate section 22 is sufficiently narrow to maintain the tips 13 of the collet fingers 14 compressed in the groove 19, to keep the stinger 2 latched to the shuttle sleeve 7 for as long as the tips 13 of the collet fingers 14 are in the intermediate section of the bore of the valve housing sleeve 21. However, the intermediate section 22 is sufficiently wide to permit expansion of the ball seat 15 from its FIG. 2 position. Therefore, as the shuttle sleeve 7 slides upwards and the ball seat 15 enters the intermediate section 22 of the bore, the ball seat 15 can radially spring outwards back to its original relaxed state. The internal diameter of the ball seat 15 is therefore increased and the activation ball 25 is able to fall through the relaxed ball seat 25. However, the stinger 2 remains latched onto the shuttle sleeve 7 as long as the tips 13 remain in the intermediate section 22 of the bore.
(29) Further upwards movement of the shuttle sleeve 7 eventually moves the tips 13 of the fingers 14 into the end section 23 of the bore, which has a larger diameter than the intermediate section. The larger diameter of the end section 23 provides sufficient annular space outside the tips 13 for the tips 13 to expand radially outward, which releases the stinger 2 from the shuttle sleeve 7. Once the shuttle sleeve 7 has been pulled up to the position where the tips 13 of the collet fingers 14 expand into the end section 23, the slotted valve ports 16 are sealed off from the circulation ports 8 and fluid flow is prevented through the bore.
(30) Now referring to FIG. 3, the activation ball 25 is dropped from surface through the internal bore 103 tubing 102, falls through the bore of the stinger 2, and eventually lands on the ball seat 15 in the shuttle sleeve 7, which is at this time in the closed position shown in FIG. 2. Pressure from surface is applied through the bore of the stinger 2 and stinger ports 18, and builds up above the seated ball 25. This pressure differential is communicated via the annulus 28 between the stinger 2 and the mandrel 9 leading to ports 26 on the upper setting sleeve 12, which communicate the pressure to the annular space between the outer surface of the upper setting sleeve 12 and the inner surface of the outer setting sleeve 27, which, as mentioned above, is axially slideable over the upper setting sleeve 12. Since the upper setting sleeve is pinned to the mandrel 9 by shear pins 29, this pressure differential applied from surface acts upon the upper face of the outer setting sleeve 27 and hydraulically forces it downwards over the upper setting sleeve 12 and mandrel 9. The skirt on the lower face of the outer setting sleeve 27 therefore urges the upper slips 3 axially downwards along the outer surface of the mandrel 9 onto the thin end of a ramped profile on the upper cone 10. As the upper slips 3 move axially along the ramped profile, they are forced to move radially outwards against the casing 100 to the position shown in FIG. 3. An anchor is then created as the slips 3 have a grooved profile cut into an outer surface which allows movement of the slips in a downwards direction (to force the slips radially outwards tighter against the wall) but prevents movement to release the slips.
(31) FIG. 4 shows the next stage of the setting sequence after the upper slips 3 have been set and anchored against the wellbore 100. A mechanical over pull on the tubing 102 causes the end collar 32 to pull the lower slips 4 upwards over a ramped profile on the lower cone 11 and move them radially outwards against the wellbore 100. Similar to the upper slips 3, the lower slips 4 have a grooved profile cut into an outer surface which acts as a ratchet to allow upward movement of the lower slips 4 to tighten them against the wall of the wellbore but resists movement tending to release the slips. The over pull also causes the elastomeric element 5 to compress axially and expand radially to meet the wellbore 100 and seal off the annulus between the wellbore 100 and the packer 1. The over pull is applied from the surface by pulling up on the tubing 102, which is secured to the stinger 2 by the cross over 101. The force is applied to the mandrel 9 by the threads 33, 34 connecting the stinger 2 and the upper setting sleeve 12 at the throat, and by the radial shear pins 29 connecting the upper setting sleeve 12 to the mandrel 9 in the socket of the mandrel 9.
(32) Referring now to FIG. 5, once the upper slips 3 have been set by hydraulic pressure applied from surface through the elongate member and the stinger, and an over pull (also applied from surface via the elongate member and the stinger 2) has been applied to set the lower slips 4 and expand the elastomeric element 5, the stinger 2 can be released from the squeeze packer 1 by rotating the tubing 102 to the right (clockwise as seen from the surface) to disconnect the left-hand male thread 34 on the stinger 2 from the left-hand female thread 33 on the throat of the upper setting sleeve 12. Keeping the tubing 102 in tension while rotating helps the stinger 2 to release from the packer 1. As the stinger 2 moves up the bore 9b the activation ball 25 is released from the ball seat 15 as the seat 15 expands and drops into the end cap 40 as explained below.
(33) The closed position of one example of shuttle sleeve 7 is shown in FIG. 6, which is a close up view of the FIG. 5 position. As shown, the stinger 2 has moved up the bore and disengaged from the thread 33 in the throat of the upper setting sleeve 12. Since the tips 13 on the collet fingers 14 are still engaged in the groove 19 the shuttle sleeve 7 is still connected to the stinger 2 at this point, and has axially moved upwards from its original position. In the FIG. 5/6 position, the slotted valve ports 16 on the shuttle sleeve 7 are out of alignment with the circulation ports 8 which are sealed off from the bore of the packer by a circumferential seals 17 compressed between the outer surface of the shuttle sleeve 7 and the inner surface of the end cap 40, therefore preventing communication through the ports 8 and closing the bore 9b. Above the shuttle sleeve 7, the bore is sealed by a bonded seal 20 on the stinger 2, which prevents fluid flow from the squeeze packer to the wellbore. Thus there is no fluid communication between the bore of the stinger 2 and the wellbore in this configuration. The seals 17 and bonded seal 20 can optionally comprise a polymeric material resilient enough to retain hydraulic pressure as well as durable enough to withstand axial reciprocation.
(34) Just before the shuttle valve 7 has axially moved upwards into the FIG. 5/6 position, the ball seat 15 traverses from the central section of the valve housing sleeve 21 into the intermediate section 22, and is no longer radially compressed by the narrower bore of the central section and so radially springs back to its original relaxed state as shown in FIG. 6 as soon as it passes the transition between the central and intermediate sections 22 on the valve housing sleeve 21. The ball seat 15 expands in the intermediate section to a larger internal diameter than the ball 25, which drops through the expanded ball seat 15 and lands in a pocket 24 in the end cap 40.
(35) Continued upward axial movement of the stinger 2 drags the tips 13 of the fingers 14 up into the end section 23 of the valve housing sleeve 21, which has a larger internal diameter permitting the tips 13 to expand radially and escape from the groove 19 on the stinger 2. This releases the stinger 2 from the shuttle sleeve 7. Once the tips 13 are in the end section 23, the sliding valve latch 7 is free from the stinger 2 and can be pulled freely from the packer 1, leaving the tips 13 latched in the upward configuration in the end section 23. Once the stinger 2 is removed from the cement squeeze packer, additional operations such as pressure testing to confirm well integrity can be conducted. If additional adjustment of the packer is needed, the stinger 2 can be re-engaged with the packer and adjustments made as many time as are needed, without pulling the string from the hole. Optionally, cementing operations take place only after the stinger has disconnected from the packer and re-engaged as described. Optionally, the stinger is disconnected from the packer after setting before being able to open and close the valve.
(36) In the configuration shown in FIG. 7, the stinger 2 has been lowered back into the wellbore 100 via tubing 102 back into the cement squeeze packer 1 after completion of pressure testing. In the present example, upper perforations 104 have been made in the wellbore 100 after the squeeze packer 1 has been set and before lowering the stinger 2 back in the wellbore 100; in some examples, the perforations have been pre-formed. The present example shows the stinger 2 fully engaged back into the cement squeeze packer 1 after the FIG. 5 configuration. To achieve this, the stinger 2 is lowered through the funnel at the top of the upper setting sleeve 12 into the bore of the body, and the threads 33, 34 are made up by anticlockwise rotation applied to the tubing 102 from the surface. Optionally, a physical no-go is provided by the male thread 34 on the stinger and female thread 33 on the upper setting sleeve 12, resisting further axial travel of the shuttle sleeve 7 further into the bore of the mandrel 9. As the stinger 2 is lowered through the bore of the body, the lower end of the stinger 2 eventually shoulders out on the ball seat 15 as shown in FIG. 6, which pushes the shuttle sleeve downwards in the bore, causing the tips 13 to compress radially inwards as they leave the end section and re-engage in the groove 19 on the outer surface of the stinger 2 thereby reconnecting the stinger 2 and the shuttle sleeve 7 via the latch provided by the collet fingers 14. The end of the stinger 2 is chamfered to match the profile of the ball seat 15, which cannot expand (because it is still in the relatively narrow intermediate section 22) and so the ball seat 15 is pushed axially by the advancing stinger 2 down the intermediate portion 22 of the housing sleeve.
(37) Once the stinger 2 and shuttle valve 7 have fully engaged and the shuttle sleeve has moved down to the FIG. 7/8 position, the valve ports 16 at the lower end of the shuttle sleeve 7 line up with the circulation ports 8 providing fluid communication between the tubing 102 and the wellbore 100 through the stinger 2 and shuttle sleeve 7. Cementing operations can then begin through the lower perforations 106. Cement 105 is pumped through the bores of the tubing 102, crossover 101, stinger 2, packer 1 and out of the circulation ports 8. Once the cement 105 enters the lower wellbore 100 below the packer 1, it fills the lower wellbore and flows through the lower perforations 106 into the annulus 108 between the wellbore 100 and formation 107. The cement 105 enters and fills up any fractures and voids which may be present before reaching the upper perforations 104 and flowing through the upper perforations into the upper section of the wellbore 100 above the packer 1.
(38) FIG. 8 shows the position of the shuttle valve 7 after the stinger 2 has been lowered back in the wellbore and is engaged back into the packer 1. The stinger 2 enters the shuttle sleeve 7, expands the tips 13 and shoulders up against the ball seat 15. The protruding finger profiles 13 locate into the recessed profile 19 on the stinger 2. Further axial downwards movement from the stinger 2 compresses the tips 14 radially inwards until firmly engaged in the end section 19 thereby re-latching the shuttle sleeve 7 back onto the stinger 2, and allowing the shuttle sleeve 7 to move further into the cylindrical sleeve 21. The tips 13 are tapered to match the internal profile of the end section 23 so do not cause interference. When the stinger 2 is fully engaged, in the FIG. 7 position, the valve ports 16 are aligned with the circulation ports 8 and the sliding valve 7 is in the open position allowing fluid movement.
(39) FIG. 9 shows the stinger 2 axially withdrawn from the cement squeeze packer 1, after cementing operations have been completed. Once the cementing operation is completed, the stinger 2 is withdrawn from the wellbore 100. The shuttle sleeve 7 is axially moved upwards and prevents fluid movement by misaligning the circulation and valve ports 8, 16, sealing off the ports 8 by the lower sealed portion of the shuttle sleeve 7 and retaining the cement 105 in place. The stinger 2 is then fully retracted back to surface after displacing the cement 105. Optionally the outer surface of the stinger 2 is relatively smooth and causes minimal disruption to the setting cement 105.
(40) In FIG. 10, an optional secondary release mechanism of the packer is shown, used in the event of sticking of the threads 33, 34. In the optional secondary release mechanism, shear pins 29 connecting the mandrel 9 with the upper setting sleeve 12 are sheared by mechanical over pull of the tubing 102 applied from surface. A predetermined shear valve is set before the squeeze packer is run in hole. Optionally the shear pins 29 are brass or can be formed from other materials such as steel if higher thresholds of shearing are needed. If right-hand rotation of the tubing 102 to release the stinger 2 from the packer 1 is not possible, mechanical over pull of the tubing 102 from surface can be performed. The shear pins 29 have a predetermined shear value. Once released, the upper setting sleeve 12 is kept engaged with the stinger 2 while still allowing an open ended profile of the stinger 2 for cementing through.
(41) FIG. 11 shows an optional modification to the above-described example, where a cleaning tool, in this case a disposable brush 36 is connected to the end of the packer 1 via the end cap 40. This allows the setting area around the perforations 106 to be cleaned of debris and to remove any accumulated micro annulus formed between layers of mud etc. in the wellbore which may cause setting problems with the cement. The disposable brush 36 or similar is optionally manufactured from drillable material such as aluminium alloy. In one example, the brush body 38 houses durable and resilient bristles 39 which may be made from spring steel or a plastic compound. The abrasive action of the bristles 39 coupled with axial reciprocation of the tubing 102 optionally aids in creating a clean setting area for the packer 1 to be set.
(42) FIG. 12 shows further optional modified example where perforating guns 41 are connected to the end of the packer 1 (which is shown in schematic view in FIG. 12, but could be the same as that described above). In a single run, the perforation guns 41 can create perforations in the casing 100 prior to setting the packer 1. The perforation guns 41, can optionally be activated by pressure or by other mechanisms. Optionally, upper perforating guns 42 can be used to create upper perforations and lower perforating guns 43 is used to create lower perforations on the same trip. The upper perforations are optionally created first before creating the lower perforations. The packer 1 is then positioned between the upper and lower perforations before being set and beginning remedial cementing operations, as described above.
(43) FIGS. 13-15 show a variation of a squeeze packer assembly 201 similar to that described above, having similar components (for which the same numbering will be used herein but increased by 200) with a mandrel 209, stinger 202, and gripping and sealing members and being deployed on tubing 101 as previously described. The structure and function of these components of the squeeze packer assembly 201 is similar to those described for the previous example, and will not be described herein in detail. The squeeze packer assembly 201 differs from the previous example in the configuration of the shuttle sleeve 207 and the ball seat 215.
(44) In the present example of FIGS. 13-15, the shuttle sleeve 207 comprises a sliding sleeve as previously described sliding inside the bore of the mandrel 209 with a bore 209b with a latch provided by a collet having resilient fingers at an upper end which engage in a groove on the outer surface of the stinger 202 when the stinger 202 stabs into the bore of the mandrel 209 and can be released by pulling up on the stinger 202 until the tips of the fingers of the latch are axially aligned with a larger diameter section of the bore of the mandrel 209 just as described in the previous example. Essentially the upper end of the shuttle sleeve 207 is very similar to the upper end of the shuttle sleeve 7 in the previous example, with a narrow outer diameter creating an annular space between the outer surface of the shuttle sleeve 207 and the inner surface of the bore of the mandrel 209.
(45) However, in this example, the sliding shuttle sleeve 207 is without a ball seat, and the chamfered lower end of the stinger 202 engages on a complementarily chamfered shoulder 207s in the bore of the shuttle sleeve 207. The inner diameter of the end of the stinger 207 is the same as the inner diameter of the shoulder 207s, so the ball 225 passes through the stinger 202 and into the shuttle sleeve 207 without seating in the shuttle sleeve 207, unlike in the previous example. In the assembly 201, the lower section of the shuttle sleeve 207 has an expanded inner diameter larger than the diameter of the ball 225, so there is a clearance between the inner surface of the lower part of the shuttle sleeve 207 and the ball 225 as best seen in FIG. 13. The lower section has the same slotted valve ports 216 in the side walls, and is sealed to the inner surface of the mandrel 209 by seals 247 and 217 (in the present example 201 there is no housing sleeve between the bore of the mandrel 209 and the shuttle sleeve 207, and the shuttle sleeve 207 bears directly on the inner surface of the bore of the mandrel 209.
(46) The ball 225 seats on a chamfered ball seat 215 set on the top of a tubular central pillar 244 fixed in position in the base of the end cap in line with the central axis of the bore of the mandrel 209 and protruding axially into the opening at the lower end of the bore of the mandrel 209. The pillar 244 has annular seals 246 on its outer surface, underneath the ball seat 215. The pillar 244 has a hollow bore 245 and side ports 244p, and the end opposite the ball seat 215 has a blind end where the pillar 244 is fixed to the end cap 240.
(47) The shuttle sleeve has an external circumferential seal 247 on a waist between its upper and lower ends. The outer diameter of the shuttle sleeve 207 steps radially outward just above the waist ending the annular space outside the shuttle sleeve 207 above the waist, and just below the waist the inner diameter also steps radially outward, leaving the waist with a larger radial thickness, disposed at the boundary where the inner and outer diameters step radially outwards. Below the waist, the outer surface of the shuttle sleeve 207 is pressed against the inner surface of the bore of the mandrel 209, but the inner surface of the shuttle sleeve 207 defines an annular gap between the shuttle sleeve 207 and the pillar 244, through which fluid can flow.
(48) In the running in position with the stinger 202 fully inserted into the mandrel 209 as shown in FIG. 13, and with the stinger 202 latched onto the top of the shuttle sleeve 207, but before the ball 225 is seated on the seat 215, fluid can flow between the bore in the stinger 202, the bore 245 in the pillar 244, the side ports 244p, the valve ports 216 and the circulation ports 208 on the end cap 240, and hence the assembly 201 can be run in without surging or other undesirable hydraulic effects as described for the first example.
(49) Once the ball 225 is dropped and lands on the chamfered profile of the ball seat 215, the fluid pathway through the bore 245 of the pillar 244 is blocked. The seals 246 on the outer surface of the pillar 244 compress between the outer surface of the pillar 244 and the inner surface of the waist of the shuttle sleeve 207, while seals 247 on the outer surface of the waist of the sliding shuttle sleeve 207 seal the annular area between the bore of the mandrel 209 and the outer surface of the shuttle sleeve 207, hence blocking fluid flow between upper and lower ends of the shuttle sleeve 207. Hydraulic pressure injected from the stinger 202 is communicated through setting ports 207p above the waist of the shuttle sleeve 207 and builds up in the annulus 228 between the stinger 202 and the mandrel 209 which is enough to set the upper slips as previously described for the above example.
(50) FIG. 14 shows the assembly 201 after the packer has set. The stinger 202 has been pulled upwards and moved the shuttle sleeve 207 into the upper closed position until the radial step outwards on between the upper end and the waist shoulders out on an internal counter-bored shoulder on the mandrel 209. The ball 25 remains seated on the profile on the pillar 244, but as the shuttle sleeve 207 rises in the bore of the mandrel 209 relative to the pillar 244, the radially thick waist clears the seals 246 on the outer surface of the pillar 244 which unload, allowing fluid communication between the upper and lower ends of the shuttle sleeve. Hence, fluid can now flow around the ball 215 from the bore of the stinger 202, through the bore 207b of the shuttle sleeve 207, and into the annular area at the lower end of the shuttle sleeve 207 between the shuttle sleeve 207 and the outer diameter of the pillar 244. The circumferential seals 217 have also moved upwards in the bore of the mandrel 209 and are compressed between the shuttle sleeve 207 and the mandrel 209 above and below the circulation ports 208, thereby preventing escape of fluid from the ports 208 in the FIG. 14 configuration. The stinger 202 can at this stage be withdrawn completely, automatically unlatching from the resilient fingers at the upper end of the shuttle sleeve 207 as in the first example, and can re-engage in the latch upon insertion into the bore of the packer as previously described, or it can remain in place in this configuration.
(51) FIG. 15 shows the next progression of the assembly 201. After the packer has fully set and the stinger 202 is retracted from the packer, closing off circulation, the packer can be opened again to allow circulation through the tool. The stinger 202 is stabbed into the bore of the mandrel 209 to re-engage with the latch on the upper end of the shuttle sleeve 207 and reconnect the stinger 202 onto the shuttle valve 207 when the stinger 202 moves down the bore 209b from the FIG. 14 configuration. At this point, the stinger 202 pushes the shuttle sleeve 207 down the bore 209b at the same time, causing the slots 216 on the shuttle sleeve 207 to line up axially with the circulation ports 208. This allows fluid communication between the bore of the stinger 202 and the annulus below the packer, via the annular space between the pillar 244 and the shuttle sleeve 207 and the circulation ports 208. The stinger 202 does not necessarily need to push the shuttle sleeve 207 all the way down the bore 209b back into the same position as FIG. 13, but merely moves it until the two seals 217 are below the circulation ports 208; the stinger 202 and the shuttle sleeve 207 are optionally prevented from further axial movement by the no-go created by the abutting of the threads 33 and 34. The top of the pillar 244 does not necessarily enter the narrower bore of the upper end of the shuttle sleeve 207, so there is provided an annular flow path around the ball 225 which allows fluid to pass around the ball 225 into the annular area below the set packer via the circulation ports 8.
