US20180320478A1

US20180320478A1 - Method and apparatus for wellbore fluid treatment

Info

Publication number: US20180320478A1
Application number: US16/029,506
Authority: US
Inventors: Daniel Jon Themig; Jim Fehr
Original assignee: Packers Plus Energy Services Inc
Current assignee: Packers Plus Energy Services Inc
Priority date: 2002-08-21
Filing date: 2018-07-06
Publication date: 2018-11-08

Abstract

An apparatus for treatment of a wellbore is described. The apparatus includes a tubing string having a wall that defines an inner bore and a plurality of ports spaced apart along the wall. The apparatus includes a plurality of port-closure sleeves each covering a corresponding port. The apparatus also includes a movable sleeve initially positioned uphole from the port-closure sleeves. There is an interference fit between the movable sleeve and the port-closure sleeve, enabling the movable sleeve to engage a port-closure sleeve, displace the port-closure-sleeve to open the corresponding port, and then pass past the port-closure sleeve to engage and displace the next downhole port-closure sleeve.

Description

RELATED PATENT APPLICATIONS

This application is a continuation-in-part application of U.S. application Ser. No. 14/738,506 filed Jun. 12, 2015, pending; which is a continuation application of Ser. No. 14/150,514, filed Jun. 12, 2015, now U.S. Pat. No. 9,074,451 issued on Jul. 7, 2015; which is a continuation application of Ser. No. 13/455,291 filed Apr. 25, 2012, now U.S. Pat. No. 8,657,009, issued 25 Feb. 2014; which is a continuation application of U.S. application Ser. No. 14/830,410, filed Jul. 5, 2010, abandoned, and of application Ser. No. 12/830,412 filed Jul. 5, 2010, now U.S. Pat. No. 8,167,047, issued 1 May 2012; which is a continuation-in-part application of U.S. application Ser. No. 12/208,463, filed Sep. 11, 2008, issued as U.S. Pat. No. 7,748,460 on Jul. 6, 2010, which is a continuation of U.S. application Ser. No. 11/403,957 filed Apr. 14, 2006, now U.S. Pat. No. 7,431,091, issued Oct. 7, 2008; which is a divisional application of U.S. application Ser. No. 10/604,807 filed Aug. 19, 2003, now U.S. Pat. No. 7,108,067, issued Sep. 19, 2006.
This application also claims priority through the above-noted applications to U.S. provisional application Ser. No. 60/404,783 filed Aug. 21, 2002.
application Ser. No. 12/830,412, mentioned above, is also a continuation-in-part of PCT application no. PCT/CA2009/000599, filed Apr. 29, 2009, which is a continuation-in-part of U.S. application Ser. No. 12/405,185, filed Mar. 16, 2009, now abandoned. This application also claims priority through the above-noted applications to U.S. provisional application Ser. Nos. 61/048,797 and 61/287,150, filed Apr. 29, 2008 and Dec. 16, 2009, respectively.

TECHNICAL FIELD

The invention relates to a method and apparatus for wellbore fluid treatment and, in particular, to a method and apparatus for selective flow control to a wellbore for fluid treatment.

BACKGROUND OF THE INVENTION

An oil or gas well relies on inflow of petroleum products. When drilling an oil or gas well, an operator may decide to leave productive intervals uncased (open hole) to expose porosity and permit unrestricted wellbore inflow of petroleum products. Alternately, the hole may be cased with a liner, which is then perforated to permit inflow through the openings created by perforating.
When natural inflow from the well is not economical, the well may require wellbore treatment termed stimulation. This is accomplished by pumping stimulation fluids such as fracturing fluids, acid, cleaning chemicals and/or proppant laden fluids to improve wellbore inflow.
In one method, the well is isolated in segments and each segment is individually treated so that concentrated and controlled fluid treatment can be provided along the wellbore. Often, in this method a tubing string is used with inflatable element packers thereabout which provide for segment isolation. The packers, which are inflated with pressure using a bladder, are used to isolate segments of the well and the tubing is used to convey treatment fluids to the isolated segment. Such inflatable packers may be limited with respect to pressure capabilities as well as durability under high pressure conditions. Generally, the packers are run for a wellbore treatment, but must be moved after each treatment if it is desired to isolate other segments of the well for treatment. This process can be expensive and time consuming. Furthermore, it may require stimulation pumping equipment to be at the well site for long periods of time or for multiple visits. This method can be very time consuming and costly.
Other procedures for stimulation treatments use tubing strings without packers such that tubing is used to convey treatment fluids to the wellbore, the fluid being circulated up hole through the annulus between the tubing and the wellbore wall or casing.
The tubing string, which conveys the treatment fluid, can include ports or openings for the fluid to pass therethrough into the borehole. Where more concentrated fluid treatment is desired in one position along the wellbore, a small number of larger ports are used. In another method, where it is desired to distribute treatment fluids over a greater area, a perforated tubing string is used having a plurality of spaced apart perforations through its wall. The perforations can be distributed along the length of the tube or only at selected segments. The open area of each perforation can be pre-selected to control the volume of fluid passing from the tube during use. When fluids are pumped into the liner, a pressure drop is created across the sized ports. The pressure drop causes approximate equal volumes of fluid to exit each port in order to distribute stimulation fluids to desired segments of the well.
In many previous systems, it is necessary to run the tubing string into the bore hole with the ports or perforations already opened. This is especially true where a distributed application of treatment fluid is desired such that a plurality of ports or perforations must be open at the same time for passage therethrough of fluid. This need to run in a tube already including open perforations can hinder the running operation and limit usefulness of the tubing string.
Some sleeve systems have been proposed for flow control through tubing ports. However, the ports are generally closely positioned such that they can all be covered by the sleeve.
Other processes for performing fracking operations are explained in U.S. Pat. Nos. 6,907,936 and 7,108,067 assigned to Packers Plus Energy Services Inc., the assignee of the present application. According to these processes, a wellbore treatment apparatus has been developed that includes a wellbore tubing string for staged well treatment. The wellbore tubing string is useful to create a plurality of isolated stages within a well and includes an openable port system that allows selected access to each such isolated stage. The tubing string includes a tubular string carrying a plurality of packers that can be set in the hole to create isolated stages therebetween about the annulus of the tubing string. Openable ports are provided through the tubing string between the packers. The ports are selectively openable by displacement of a port-closure (e.g. sleeve) using a sealable seat in the liner, when that seat is impacted by a ball dropped or pumped into the liner from the wellhead. The ball is dropped or launched from the wellhead, stops on the seat, and seals the tubing string at a stage of the wellbore. Then, pressure can be increased uphole from the ball to drive the sleeve to drive the port-closure away from the port, acting to open the port in the respective stage. Most of the seats in these ball-drop hydraulic fracking prior art systems are formed to accept a ball of a selected diameter but to allow balls of smaller diameters to pass.
In some of these ball-drop hydraulic fracking prior art systems, such as explained in U.S. Pat. No. 9,765,995 assigned to Packers Plus Energy Services Inc., a single ball can be used to impact several seats in the liner, and this open several ports in the liner. Each seat has a substantially fixed inner diameter (ID) restriction. The ball is a deformable sealing device that can sit on the seat to create a seal in the liner, and then with an increase in pressure applied from the wellhead, pass through the inner diameter restriction of the seat, which is also deformable. The hall is selected to have an outer diameter greater than the inner diameter through the seat (Le, the ball is selected to have an interference fit with the inner diameter of the seat), but can be forced by fluid pressure to pass through the restriction and in so doing creates a reliable force on a tool attached to a seat, such as a sliding sleeve that is covering a port. In particular, the passage of the ball through the restriction of the seat creates a force that is reliable, for example, of a known minimum value, such that the mechanism can be set to be actuated by that force.
In such ball-drop hydraulic fracking prior art systems, during the fracking operation, each time fluid flows past the ball seat, the ball seat acts as a choke and causes a pressure drop because the restriction created by the narrower ball seats reduces the pressure of the fluid downhole of the restriction. Further, as the fluid flows past subsequent ball seats, the reduction of fluid pressure increases further at each ball seat thereby causing a large aggregate pressure drop at the stages that are further downhole. Considering an example of a single stage, having a tubing string with a three inch inner diameter, and seven ball seats in the stage that each are associated with a port, there is a pressure drop as the ball passes through each seat of the stage, that is about 276.4 PSI. The total pressure drop across all seven ball seats of the stage is therefore approximately 7×276.4=1934.80 PSI. In some cases, the loss of fluid pressure can be up to 3000-4000 PSI per stage. Such pressure drops affect the fracking operation because the fluid pressure required to stimulate the formation is lost due to such large pressure drops. In order to compensate for this loss, the fluid needs to be pumped at a pressure higher than required pressure, which requires larger pumps thereby adding to the operational cost of the wellbore fracking operation.

SUMMARY OF THE INVENTION

A method and apparatus has been invented which provides for selective communication to a wellbore for fluid treatment. In one aspect, the method and apparatus provide for the running in of a fluid tubing string, the fluid tubing string having ports substantially closed against the passage of fluid therethrough, but which are openable when desired to permit fluid flow into the wellbore. The apparatus and methods of the present invention can be used in various borehole conditions including open holes, lined or cased holes, vertical, inclined or horizontal holes, and straight or deviated holes.
In one embodiment, there is provided an apparatus for fluid treatment of a borehole, the apparatus comprising a tubing string having a long axis, a plurality of closures accessible from the inner diameter of the tubing string, each closure closing a port opened through the wall of the tubing string and preventing fluid flow through its port, but being openable to permit fluid flow through its port and each closure openable independently from each other closure and a port-closure sleeve positioned in the tubing string and driveable through the tubing string to actuate the plurality of closures to open the ports.
The sleeve can be driven in any way to move through the tubing string to actuate the plurality of closures. In one embodiment, the sleeve is driveable remotely, without the need to trip a work string such as a tubing string, coiled tubing or a wire line.
In one embodiment, the sleeve has formed thereon a seat and the apparatus includes a sealing device selected to seal against the seat, such that fluid pressure can be applied to drive the sleeve and the sealing device can seal against fluid passage past the sleeve. The sealing device can be, for example, a plug or a ball, which can be deployed without connection to surface. This embodiment avoids the need for tripping in a work string for manipulation.
In one embodiment, the closures each include a cap mounted over its port and extending into the tubing string inner bore, the cap being openable by the sleeve engaging against. The cap, when opened, permits fluid flow through the port. The cap can be opened, for example, by action of the sleeve breaking open the cap or shearing the cap from its position over the port.
In another embodiment, the closures each include a port-closure sleeve each mounted over at least one port, and openable by a movable sleeve engaging and moving the port-closure sleeve to uncover its respective port. The port-closure sleeve can include, for example, a profile on its surface open to the tubing string and the movable sleeve includes a locking dog biased outwardly therefrom and selected to engage the profile on the port-closure sleeve such that the port-closure sleeve is moved by the movable sleeve. The profile is formed such that the locking dog can disengage therefrom, permitting the movable sleeve to move along the tubing string to a next port-closure sleeve.
In another embodiment, the apparatus includes a tubing string having a wall that defines an inner bore and a plurality of ports spaced apart along the wall. The apparatus includes a plurality of port-closure sleeves each covering a corresponding port. The apparatus also includes a movable sleeve initially positioned uphole from the port-closure sleeves. There is an interference fit between the movable sleeve and the port-closure sleeves, enabling the movable sleeve to engage a port-closure sleeve, displace the port-closure-sleeve to open the corresponding port, and then pass past the port-closure sleeve to engage and displace the next downhole port-closure sleeve.
In one embodiment, the apparatus can include a packer about the tubing string. The packers can be of any desired type to seal between the wellbore and the tubing string. For example, the packer can be a solid body packer including multiple packing elements.
In view of the foregoing there is provided a method for fluid treatment of a borehole, the method comprising: providing an apparatus for wellbore treatment according to one of the various embodiments of the invention; running the tubing string into a wellbore to a position for treating the wellbore; moving the sleeve to open the closures of the ports and increasing fluid pressure to force wellbore treatment fluid out through the ports.
In one method according to the present invention, the fluid treatment is a borehole stimulation using stimulation fluids such as one or more of acid, gelled acid, gelled water, gelled oil, CO2, nitrogen and any of these fluids containing proppants, such as for example, sand or bauxite. The method can be conducted in an open hole or in a cased hole. In a cased hole, the casing may have to be perforated prior to running the tubing string into the wellbore, in order to provide access to the formation.
The method can include setting a packer about the tubing string to isolate the fluid treatment to a selected section of the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

A further, detailed, description of the invention, briefly described above, will follow by reference to the following drawings of specific embodiments of the invention. These drawings depict only typical embodiments of the invention and are therefore not to be considered limiting of its scope. In the drawings:

FIG. 1 is a sectional view through a wellbore having positioned therein a fluid treatment assembly according to the present invention;

FIG. 2 is a sectional view through a wellbore having positioned therein a fluid treatment assembly according to the present invention;

FIG. 3 is a sectional view along the long axis of a packer useful in the present invention;

FIG. 4a is a section through another wellbore having positioned therein another fluid treatment assembly according to the present invention, the fluid treatment assembly being in a first stage of wellbore treatment;

FIG. 4b is a section through the wellbore of FIG. 4a with the fluid treatment assembly in a second stage of wellbore treatment;

FIG. 4c is a section through the wellbore of FIG. 4a with the fluid treatment assembly in a third stage of wellbore treatment;

FIG. 5 is a sectional view along the long axis of a tubing string according to the present invention containing a sleeve and axially spaced fluid treatment ports;

FIG. 6a is a sectional view along the long axis of a tubing string according to the present invention containing axially spaced fluid treatment ports, each covered by a port-closure sleeve, and each port-closure sleeve engageable with a moving sleeve;

FIG. 6b is another implementation of the embodiment illustrated in FIG. 6A, with an interference fit between the movable sleeve and the port-closure sleeve.

FIG. 7a is a section through a wellbore having positioned therein another fluid treatment assembly according to the present invention, the fluid treatment assembly being in a first stage of wellbore treatment;

FIG. 7b is a section through the wellbore of FIG. 7a with the fluid treatment assembly in a second stage of wellbore treatment;

FIG. 7c is a section through the wellbore of FIG. 7a with the fluid treatment assembly in a third stage of wellbore treatment; and

FIG. 7d is a section through the wellbore of FIG. 7a with the fluid treatment assembly in a fourth stage of wellbore treatment,

DETAILED DESCRIPTION

Referring to FIG. 1, a wellbore fluid treatment assembly is shown, which can be used to effect fluid treatment of a formation 10 through a wellbore 12. The wellbore assembly includes a tubing string 14 having a lower end 14 a and an upper end extending to surface (not shown). Tubing string 14 includes a plurality of spaced apart ports 17 opened through the tubing string wall to permit access between the tubing string inner bore 18 and the wellbore. Each port 17 includes thereover a closure that can be closed to substantially prevent, and selectively opened to permit, fluid flow through the ports.
A port-closure sleeve 22 is disposed in the tubing string to control the opening of the port-closures. In this embodiment, sleeve 22 is mounted such that it can move, arrow A, from a port closed position, wherein the sleeve is shown in phantom lines, axially through the tubing string inner bore past the ports to a open port position, shown in solid lines, to open the associated closures of the ports allowing fluid flow therethrough. The sliding sleeve is disposed to control the opening of the ports through the tubing string and is moveable from a closed port position to a position wherein the ports have been opened by passing of the sleeve and fluid flow of, for example, stimulation fluid is permitted down through the tubing string, arrows F, through the ports of the ported interval. If fluid flow is continued, the fluid can return to surface through the annulus.
The tubing string is deployed into the borehole in the closed port position and can be positioned down hole with the ports at a desired location to effect fluid treatment of the borehole.
Referring to FIG. 2, a wellbore fluid treatment assembly is shown, which can be used to effect fluid treatment of a formation 10 through a wellbore 12. The wellbore assembly includes a tubing string 14 having a lower end 14 a and an upper end extending to surface (not shown). Tubing string 14 includes a plurality of spaced apart ported intervals 16 c to 16 e each including a plurality of ports 17 opened through the tubing string wall to permit access between the tubing string inner bore 18 and the wellbore. The ports are normally closed by pressure holding caps 23.
Packers 20 d to 20 e are mounted between each pair of adjacent ported intervals. In the illustrated embodiment, a packer 20 f is also mounted below the lower most ported interval 16 e and lower end 14 a of the tubing string. Although not shown herein, a packer can be positioned above the upper most ported interval. The packers are disposed about the tubing string and selected to seal the annulus between the tubing string and the wellbore wall, when the assembly is disposed in the wellbore. The packers divide the wellbore into isolated segments wherein fluid can be applied to one segment of the well, but is prevented from passing through the annulus into adjacent segments. As will be appreciated the packers can be spaced in any way relative to the ported intervals to achieve a desired interval length or number of ported intervals per segment. In addition, packer 20 f need not be present in some applications.
The packers can be, as shown, of the solid body-type with at least one extrudable packing element, for example, formed of rubber. Solid body packers including multiple, spaced apart packing elements 21 a, 21 b on a single packer are particularly useful especially for example in open hole (unlined wellbore) operations. In another embodiment, a plurality of packers are positioned in side by side relation on the tubing string, rather than using only one packer between each ported interval,
Sliding sleeves 22 c to 22 e are disposed in the tubing string to control the opening of the ports by opening the caps. In this embodiment, a sliding sleeve is mounted for each ported interval and can be moved axially through the tubing string inner bore to open the caps of its interval. In particular, the sliding sleeves are disposed to control the opening of their ported intervals through the tubing string and are each moveable from a closed port position away from the ports of the ported interval (as shown by sleeves 22 c and 22 d) to a position wherein it has moved past the ports to break open the caps and wherein fluid flow of, for example, stimulation fluid is permitted through the ports of the ported interval (as shown by sleeve 22 e).
The assembly is run in and positioned downhole with the sliding sleeves each in their closed port position. When the tubing string is ready for use in fluid treatment of the wellbore, the sleeves are moved to their port open positions. The sleeves for each isolated interval between adjacent packers can be opened individually to permit fluid flow to one wellbore segment at a time, in a staged treatment process.
Preferably, the sliding sleeves are each moveable remotely, for example without having to run in a line or string for manipulation thereof, from their closed port position to their position permitting through-port fluid flow. In one embodiment, the sliding sleeves are actuated by devices, such as balls 24 d, 24 e (as shown) or plugs, which can be conveyed by gravity or fluid flow through the tubing string. The device engages against the sleeve and causes it to move4 through the tubing string. In this case, ball 24 e is sized so that it cannot pass through sleeve 22 e and is engaged in it when pressure is applied through the tubing string inner bore 18 from surface, ball 24 e seats against and plugs fluid flow past the sleeve. Thus, when fluid pressure is applied after the ball has seated in the sleeve, a pressure differential is created above and below the sleeve which drives the sleeve toward the lower pressure side.
In the illustrated embodiment, the inner surface of each sleeve, which is the side open to the inner bore of the tubing string, defines a seat 26 e onto which an associated ball 24 e, when launched from surface, can land and seal thereagainst. When the ball seals against the sleeve seat and pressure is applied or increased from surface, a pressure differential is set up which causes the sliding sleeve on which the ball has landed to slide through the tubing string to a port-open position until it is stopped by, for example, a no go. When the ports of the ported interval 16 e are opened, fluid can flow therethrough to the annulus between the tubing string and the wellbore and thereafter into contact with formation 10.
Each of the plurality of sliding sleeves has a different diameter seat and, therefore, each accept a different sized ball. In particular, the lower-most sliding sleeve 22 e has the smallest diameter D1 seat and accepts the smallest sized ball 24 e and each sleeve that is progressively closer to surface has a larger seat. For example, as shown in FIG. 2, the sleeve 22 c includes a seat 26 c having a diameter D3, sleeve 22 d includes a seat 26 d having a diameter D2, which is less than D3 and sleeve 22 e includes a seat 26 e having a diameter D1, which is less than D2. This provides that the lowest sleeve can be actuated to open it ports first by first launching the smallest ball 24 e, which can pass through all of the seats of the sleeves closer to surface but which will land in and seal against seat 26 e of sleeve 22 e. Likewise, penultimate sleeve 22 d can be actuated to move through ported interval 16 d by launching a ball 24 d which is sized to pass through all of the seats closer to surface, including seat 26 c, but which will land in and seal against seat 26 d.
Lower end 14 a of the tubing string can be open, closed or fitted in various ways, depending on the operational characteristics of the tubing string which are desired. In the illustrated embodiment, the tubing string includes a pump out plug assembly 28. Pump out plug assembly 28 acts to close off end 14 a during run in of the tubing string, to maintain the inner bore of the tubing string relatively clear. However, by application of fluid pressure, for example at a pressure of about 3000 psi, the plug can be blown out to permit actuation of the lower most sleeve 22 e by generation of a pressure differential. As will be appreciated, an opening adjacent end 14 a is only needed where pressure, as opposed to gravity, is needed to convey the first ball to land in the lower-most sleeve. Alternately, the lower most sleeve can be hydraulically actuated, including a fluid actuated piston secured by shear pins, so that the sleeve can be driven along the tubing string remotely without the need to land a ball or plug therein.
In other embodiments, not shown, end 14 a can be left open or can be closed, for example, by installation of a welded or threaded plug.
While the illustrated tubing string includes three ported intervals, it is to be understood that any number of ported intervals could be used. In a fluid treatment assembly desired to be used for staged fluid treatment, at least two openable ports from the tubing string inner bore to the wellbore must be provided such as at least two ported intervals or an openable end and one ported interval. It is also to be understood that any number of ports can be used in each interval.
Centralizer 29 and other tubing string attachments can be used, as desired.
The wellbore fluid treatment apparatus, as described with respect to FIG. 2, can be used in the fluid treatment of a wellbore. For selectively treating formation 10 through wellbore 12, the above-described assembly is run into the borehole and the packers are set to seal the annulus at each location creating a plurality of isolated annulus stages. Fluids can then pumped down the tubing string and into a selected stage of the annulus, such as by increasing the pressure to pump out plug assembly 28. Alternately, a plurality of open ports or an open end can be provided or lower most sleeve can include a piston face for hydraulic actuation thereof. Once that selected stage is treated, as desired, ball 24 e or another sealing plug is launched from surface and conveyed by gravity or fluid pressure to seal against seat 26 e of the lower most sliding sleeve 22 e, this seals off the tubing string below sleeve 22 e and drives the sleeve to open the ports of ported interval 16 e to allow the next annulus stage, the stage between packer 20 e and 20 f, to be treated with fluid. The treating fluids will be diverted through the ports of interval 16 e whose caps have been removed by moving the sliding sleeve. The fluid can then be directed to a specific area of the formation. Ball 24 e is sized to pass though all of the seats closer to surface, including seats 26 c, 26 d, without sealing thereagainst. When the fluid treatment through ports of interval 16 e is complete, a ball 24 d is launched, which is sized to pass through all of the seats, including seat 26 c closer to surface, and to seat in and move sleeve 22 d. This opens the ports of ported interval 16 d and permits fluid treatment of the annulus between packers 20 d and 20 e. This process of launching progressively larger balls or plugs is repeated until all of the stages are treated. The balls can be launched without stopping the flow of treating fluids. After treatment, fluids can be shut in or flowed back immediately. Once fluid pressure is reduced from surface, any balls seated in sleeve seats can be unseated by pressure from below to permit fluid flow upwardly therethrough.
The apparatus is particularly useful for stimulation of a formation, using stimulation fluids, such as for example, acid, gelled acid, gelled water, gelled oil, CO2, nitrogen and/or proppant laden fluids.
Referring to FIG. 3, a packer 20 is shown which is useful in the present invention. The packer can be set using pressure or mechanical forces. Packer 20 includes extrudable packing elements 21 a, 21 b, a hydraulically actuated setting mechanism and a mechanical body lock system 31 including a locking ratchet arrangement. These parts are mounted on an inner mandrel 32. Multiple packing elements 21 a, 21 b are formed of elastomer, such as for example, rubber and include an enlarged cross section to provide excellent expansion ratios to set in oversized holes. The multiple packing elements 21 a, 21 b can be separated by at least 0.3M and preferably 0.8M or more. This arrangement of packing elements aid in providing high pressure sealing in an open borehole, as the elements load into each other to provide additional pack-off.
Packing element 21 a is mounted between fixed stop ring 34 a and compressing ring 34 b and packing element 21 b is mounted between fixed stop ring 34 c and compressing ring 34 d. The hydraulically actuated setting mechanism includes a port 35 through inner mandrel 32, which provides fluid access to a hydraulic chamber defined by first piston 36 a and second piston 36 b. First piston 36 a acts against compressing ring 34 b to drive compression and, therefore, expansion of packing element 21 a, while second piston 36 b acts against compressing ring 34 d to drive compression and, therefore, expansion of packing element 21 b. First piston 36 a includes a skirt 37, which encloses the hydraulic chamber between the pistons and is telescopically disposed to ride over piston 36 b. Seals provides sealing against the leakage of fluid between the parts. Mechanical body lock system 31, including for example a ratchet system, acts between skirt 37 and piston 36 b permitting movement therebetween driving pistons 36 a, 36 b away from each other but locking against reverse movement of the pistons toward each other, thereby locking the packing elements into a compressed, expanded configuration.
Thus, the packer is set by pressuring up the tubing string such that fluid enters the hydraulic chamber and acts against pistons 36 a, 36 b to drive them apart, thereby compressing the packing elements and extruding them outwardly. This movement is permitted by body lock system 31. However, body lock system 31 locks the packers against retraction to lock the packing elements in their extruded conditions.
Ring 34 a includes shears 39 which mount the ring to mandrel 32. Thus, for release of the packing elements from sealing position the tubing string into which mandrel 32 is connected, can be pulled up to release shears 38 and, thereby, release the compressing force on the packing elements.
FIGS. 4a to 4c show an assembly and method for fluid treatment, termed sprinkling, wherein fluid supplied to an isolated interval is introduced in a distributed, low pressure fashion along an extended length of that interval. The assembly includes a tubing string 212 and ported intervals 216 a, 216 b, 216 c each including a plurality of ports 217 spaced along the long axis of the tubing string. Packers 220 a, 220 b are provided between each interval to form an isolated segment in the tubing string 212.
While the ports of interval 216 c are open during run in of the tubing string, the ports of intervals 216 b and 216 a, are closed during run in and sleeves 222 a and 222 b are mounted within the tubing string and actuatable to selectively open the ports of intervals 216 a and 216 b, respectively. In particular, in FIG. 4a , the position of sleeve 222 b is shown when the ports of interval 216 b are closed. The ports in any of the intervals can be size restricted to create a selected pressure drop therethrough, permitting distribution of fluid along the entire ported interval.
Once the tubing string is run into the well, stage 1 is initiated wherein stimulation fluids are pumped into the end section of the well to ported interval 216 c to begin the stimulation treatment (FIG. 4a ). Fluids will be forced to the lower section of the well below packer 220 b. In this illustrated embodiment, the ports of interval 216 c are normally open size restricted ports, which do not require opening for stimulation fluids to be jetted therethrough. However, it is to be understood that the ports can be installed in closed configuration, but opened once the tubing is in place.
When desired to stimulate another section of the well (FIG. 4b ), a ball or plug (not shown) is pumped by fluid pressure, arrow P, down the well and will seat in a selected sleeve 222 b sized to accept the ball or plug. The pressure of the fluid behind the ball will push the cutter sleeve against any force or member, such as a shear pin, holding the sleeve in position and down the tubing string, arrow S. As it moves down, it will open the ports of interval 216 b as it passes by them. Sleeve 222 b eventually stops against a stop means. Since fluid pressure will hold the ball in the sleeve, this effectively shuts off the lower segment of the well including previously treated interval 216 c. Treating fluids will then be forced through the newly opened ports. Using limited entry or a flow regulator, a tubing to annulus pressure drop insures distribution. The fluid will be isolated to treat the formation between packers 220 a and 220 b.
After the desired volume of stimulation fluids is pumped, a slightly larger second ball or plug is injected into the tubing and pumped down the well, and will seat in sleeve 222 a which is selected to retain the larger ball or plug. The force of the moving fluid will push sleeve 222 a down the tubing string and as it moves down, it will open the ports in interval 216 a. Once the sleeve reaches a desired depth as shown in FIG. 4c , it will be stopped, effectively shutting off the lower segment of the well including previously treated intervals 216 b and 216 c. This process can be repeated a number of times until most or all of the wellbore is treated in stages, using a sprinkler approach over each individual section.
The above noted method can also be used for wellbore circulation to circulate existing wellbore fluids (drilling mud for example) out of a wellbore and to replace that fluid with another fluid. In such a method, a staged approach need not be used, but the sleeve can be used to open ports along the length of the tubing string. In addition, packers need not be used when the apparatus is intended for wellbore circulation as it is often desirable to circulate the fluids to surface through the wellbore annulus.
The sleeves 22 a and 222 b can be formed in various ways to cooperate with ports 217 to open those ports as they pass through the tubing string.
With reference to FIG. 5, a tubing string 212 according to the present invention is shown including a movable sleeve 222 and a plurality of normally closed ports 217 spaced along the long axis x of the string. Ports 217 each include a pressure holding, internal cap 223. Cap 223 extends into the bore 218 of the tubing string and is formed of shearable material at least at its base, so that it can be sheared off to open the port. Cap 223 can be, for example, a cobe sub or other modified subs. As will be appreciated, due to the use of ball actuated sleeves, the caps are selected to be resistant to shearing by movement of a ball therepast.
Sleeve 222 is mounted in the tubing string and includes a cylindrical outer surface having a diameter to substantially conform to the inner diameter of, but capable of sliding through, the section of the tubing string in which the sleeve is selected to act. Sleeve 222 is mounted in tubing string by use of a shear pin 250 and has a seat 226 formed on its inner facing surface with a seat diameter to be plugged by a selected size ball 224 having a diameter greater than the seat diameter. When the ball is seated in the seat, and fluid pressure is applied therebehind, arrow P, shear pin 250 will shear and the sleeve will be driven, with the ball seated therein along the length of the tubing string until stopped by shoulder 246.
Sleeve 222 includes a profiled leading end 247 which is formed to shear or cut off the protective caps 223 from the ports as it passes, thereby opening the ports. Sleeve 222 and caps 223 are selected with consideration as to the fluid pressures to be used to substantially ensure that the sleeve can shear the caps from and move past the ports as it is driven through the tubing string.
While shoulder 246 is illustrated as an annular step on the inner diameter of the tubing string, it is to be understood that any configuration that stops movement of the sleeve though the wellbore can be used. Shoulder 246 is preferably spaced from the ports 217 with consideration as to the length of sleeve 222 such that when the sleeve is stopped against the shoulder, the sleeve does not cover any ports. Although not shown, the sleeve can be disposed in a circumferential groove in the tubing string, the groove having a diameter greater than the id of the tubing string. In such an embodiment, the sleeve could be disposed in the groove to eliminate or limit its extension into the tubing string inner diameter.
Sleeve 222 can include seals 252 to seal between the interface of the sleeve and the tubing string, where it is desired to seal off fluid flow therebetween.
The caps can also be used to close off ports disposed in a plane orthogonal to the long axis of the tubing string, if desired.
Referring to FIG. 6a , there is shown another tubing string 314 according to the present invention. The tubing string includes an axially movable sleeve 322 and a plurality of normally closed ports 317 a, 317 a′, 317 b, 317 b′. Ports 317 a, 317 a′ that are spaced from each other on the tubing circumference. Ports 317 b, 317 b′ are also spaced circumferentially in a plane orthogonal to the long axis of the tubing string. Ports 317 a, 317 a′ are spaced from ports 317 b, 317 b′ along the long axis x of the string
Movable sleeve 322 is normally mounted by shear pin 350 in the tubing string. However, fluid pressure created by seating of a seal, e.g. a ball or plug 324 in the sleeve, can cause the shear to be sheared and the sleeve to be driven along the tubing string until it butts against a shoulder 346.
Port 317 a is positioned thereover a port-closing sleeve 325 a and port 317 b is positioned thereover a port-closure sleeve 325 b. The sleeves act as valves to seal against fluid flow though their associated ports when they are positioned thereover. However, sleeves 325 a, 325 b can be moved axially along the tubing string to expose their associated ports, permitting fluid flow therethrough. In particular, with reference to port 317 a, each set of ports includes an associated port-closure sliding sleeve 325 disposed in a cylindrical groove 341, defined by shoulders 327 a, 327 b about the port. The groove is formed in the inner wall of the tubing string and sleeve 325 a is selected to have an inner diameter that is generally equal to the tubing string inner diameter and an outer diameter that substantially conforms to, but is slidable along, the groove between shoulders 327 a, 327 b. Seals 329-2 are provided in the groove between port-closure sleeve 325 a and liner 314, such that fluid leakage therebetween is substantially avoided.
The port-closure sleeves, for example 325 a, are normally positioned over their associated port, for example 317 a, adjacent shoulder 327 a, but can be slid along the groove until stopped by shoulder 327 b. In each ease, the shoulder 327 b is spaced from its ports with consideration as to the length of the associated sleeve so that when the sleeve is butted against shoulder 327 b, the port is open to allow at least some fluid flow therethrough.
The port-closing sleeves 325 a, 325 b are each formed to be engaged and moved by movable sleeve 322 as it passes through the tubing string from its pinned position to its position against shoulder 346. In the illustrated embodiments, sleeves 325 a, 325 b are moved by engagement of outwardly biased dogs 351 on the movable sleeve 322. In particular, each sleeve 325 a, 325 b includes a profile 353 a, 353 b into which dogs 351 of movable sleeve 322 can releasably engage. The spring force of dogs and the co-acting configurations of profiles and the dogs are together selected to be greater than the resistance of sleeve 325 moving within the groove, but less than the fluid pressure selected to be applied against plug 324, such that when movable sleeve 322 is driven through the tubing string, it will engage against each sleeve 325 a to move it away from its port 317 a and against its associated shoulder 327 b. However, continued application of fluid pressure will drive the dogs 351 of the movable sleeve 322 to collapse, overcoming their spring force, to remove the sleeve from engagement with a first port-closing sleeve 325 a, along the tubing string 314 and into engagement with the profile 353 b of the next port-closure sleeve 325 b to move that sleeve and open port 317 b, and so on, until movable sleeve 322 stopped against shoulder 346. In this way, one plug 324 acting under the force of uphole-sourced fluid pressure, can seal up against a movable sleeve 3222, and the plug 324 in tandem with the sleeve 322 can be used to open several port- closure sleeves 325 a, 325 b. Unlike prior art system such as U.S. Pat. No. 9,765,995, in which a single plug serially engages several seats that each control the opening of a port-closure sleeve, in order to open several ports, in the embodiment of FIG. 6A, a single combination of a plug 324 in engagement with a seat serially engages several port-closure sleeves to open several ports.
FIG. 6b illustrates another implementation of a portion of the tubing string 314, wherein the movable sleeve 322 does not use dogs to engage the port-closure sleeves 325. Rather, this embodiment uses an interference fit between the seat 322-1 and the plug 324, and another interference fit between the outer surface of movable sleeve 322 and the inner surface of the port- closure sleeves 325 a, 325 b, which ensures adequate transfer of force from the movable sleeve 322 to the port- closure sleeves 325 a, 325 b. As a result of their interference fit, the seat 322-1 and plug 324 both experience elastic and plastic deformation when the plug 324 is exposed to high fluid pressure sourced from the surface, while both the seat 322-1 and plug 324 remain substantially intact enough to be reused to open several port-closure sleeves such as port-closure sleeve 325 a and port-closure sleeve 325 b. In one embodiment, the inner diameter of the seat 322-1 is 10/1000 of an inch smaller than the outer diameter of the plug 324, where for example the inner diameter of the seat is 3 inches. Also as a result of their interference fit, the outer surface of movable sleeve 322 and the inner surface of the port-closure sleeves 325 a also experience elastic and plastic deformation, while remaining substantially intact enough to allow the movable seat 322 to be reused to open several other port-closure sleeves, such as port-closure sleeve 325 b. The extent to which the inner diameter of a port-closure sleeve 325 a is smaller than the outer diameter of the movable sleeve 322, is a function of the diameter of the plug 324 and seat 322-1, and can be 6/1000 of an inch for example.
Using an interference fit, as opposed to the dogs used in the embodiment of FIG. 6a , for the engagement of the movable sleeve 322 with the port-closure sleeves 325, makes for a more reliable engagement that is far less prone to malfunctioning in the very extreme temperature and high pressure environments of a well bore, due to the reduction in the number and significance of moving mechanical parts. The use of an interference fit instead of dogs, is especially advantageous, where finer sands are used for fracking that are especially problematic for the proper functioning of mechanical parts such as dogs. In essence, in the embodiment of FIG. 6B, by correctly modeling the deformation of plugs and seats as they engage through interference fits with one another, one can eliminate the use of more failure-prone moving mechanical parts such as dogs and latches.
The plug 324 can be made of any of a number of materials including metallics such as aluminum, steel, or a dissolving metallic, or super-hard ceramics, as known to those in the art. In an embodiment, the material of the plug must permit the plug to be milled out. The plug 324 also needs to be strong enough to be pressure rated at different levels depending on a number of factors including the well depth at which the plug will be used. The minimum pressure rating for most jobs needs to be 4000 psi, and can be as high as 10000 psi for some jobs, assuming a 6/1000 inch interference fit between the plug 324 and seat 322-1. The diameter of a plug 324 is standard as known to those skilled in the art, for example 3⅞ inches for 4½ inch liner. The plug 324 can be a ball or a cylinder, with consideration as to the shape being the degree to which the plug will be deformed when shaped as a ball, a cylinder or some other shape, as a result of the interference fit with the seat 322-1. The plug can be made of dissolvable materials provided it is designed not to dissolve, from the time it is installed in a well until the time it is finished participating in the completion of a stage, or stages of interest, as described below. If the plug 324 is millable, it might also comprise splines or other features designed to prevent the plug 324 from rotating as it is being milled out.
FIGS. 6 and 6 b depicts the movable sleeve 322 and only two port-closure sleeves 325 placed in the tubing string 314. It is to be understood that the number of port-closure sleeves in a stage may not be limited to the number shown in FIG. 6a or FIG. 6 b.
In the embodiment of FIG. 6b , the movable sleeve 322 is attached to the tubing string 314 by shear pin 350. Seals 329-1 are provided between an outer surface of the movable sleeve 322 and an inner wall of the tubing string 314 such that fluid leakage therebetween is substantially avoided. The movable sleeve 322 also includes a ball seat 322-1 on an uphole side of the movable sleeve 322 sized to receive a sealing device, such as the ball or plug 324, launched from the surface. The seat 322-1 is long enough to accommodate the interference fit of the pug 324 for a long enough time, to allow for the engagement of the movable seat 322 with all the port- closure sleeves 325 a and 325 b of the stage, as the plug 324 and movable sleeve 322 move in tandem inside a stage. The ball seat 322-1 enables displacement of the movable sleeve within the tubing string when hydraulic pressure is applied on the sealing device that is situated in the ball seat 322-1. The outer diameter of the movable sleeve 322 is selected to enable the movable sleeve 322 to slide along the internal surface of the tubing string 314. In one embodiment, the thickness of the movable sleeve 322 at the point where it has its narrowest inner diameter, is ¼ inches.
As in the embodiment of FIG. 6A, the port-closure sleeve 325 a is enabled to be displaced between a port closed position, where the respective port 317 a is closed, to a port opened position, where port 317 a is open. In one embodiment, movable sleeve 322 may be provided with plug engaging profile 331, having a thickness of ⅙ inches. In one embodiment, the thickness of port-closure sleeve 325 is ¼ inches, excluding thickness of profile 333. As in FIG. 6a , the displacement of port-closure sleeve 325 is confined in a cylindrical groove 341 defined in the tubing string 314 between shoulders 327 a and 327 b. The port closed position is a position in which fluid flow through the port is not allowed and a port open position is a position in which such fluid flow is allowed. The cylindrical groove 341 has a depth selected to enable an inner diameter of port-closure sleeve 325 to be substantially equal to the inner diameter of the part of tubing string 314 at which there is no groove for a port- closure sleeve 325 a or 325 b. FIG. 6b shows the port- closure sleeves 325 a and 325 b in the port closed position, adjacent to the shoulder 327 a. The port-closure sleeve 325 is also mounted on the tubing string 314 using shear pins 352 and is also insulated against leakage by seals 329-1.
As in the embodiment of FIG. 6a , the movable sleeve 322 is installed uphole from the port-closure sleeves 325, so that when movable sleeve 322 is actuated by the plug 324 to move downhole, it engages the movable sleeve 322 and forces it to move downhole, to shift a series of port- closure sleeves 325 a,325 b in the stage, and thus open their respective ports 317 a, 317 b.
Specifically, a material pressure drop is created between the uphole side and the downhole side of the movable sleeve 322 upon receipt of the plug 324. When the plug 324 lands on the ball seat 322-1, it seals the internal bore of tubing 314, creating the material pressure drop which in turn forces the movable sleeve 322 to move in the downhole direction under hydraulic pressure applied from the surface. The pressure applied to the plug 324 is sufficient to shear the shear pin 350 and free the movable sleeve 322 to move downhole until stopped engagement of its engaging profile 331, with the engagement profile 333 of port-closure sleeve 325 a. As the external diameter of movable sleeve 322 is substantially equal to the internal diameter of the port-closure sleeve 325 a, and to the part of the tubing 314 without a port- closure sleeve 325 a, 325 b, as a result, the movable sleeve 322 slides inside the tubing string 314 and then inside the sleeve 325 a.
In one embodiment, sleeves 322 and 325 a may be provided with respective engaging profiles 331, 333, respectively. Engaging profiles 331 and 333 have an interference fit therebetween to enable movable sleeve 322 to engage sleeve 325 a. Namely, engaging profile 331 may be a small engaging feature extending from the outer surface of movable sleeve 322, and the port-closure sleeve profile 333 may be an engaging feature, extending from the inner surface of the port-closure sleeve 325 a. The thicknesses of profile 333 and 331 are correlated with the size of the inner diameter of the plug that will engage with movable sleeve 322. In one embodiment, profile 333 protrudes 6/1000 of an inch from the inner surface of the port-closure sleeve 325 a. In another embodiment where the plug has a larger inner diameter, profile 333 protrudes 12/1000 of an inch from the inner surface of the port-closure sleeve 325 a. As a result, under hydraulic pressure applied to plug 324, the movable sleeve 322 engages port-closure sleeve 325 a and forces sleeve 325 a to move downhole, resulting in opening of the port 317 a.
In more general terms, the outer diameter (OD) of movable sleeve 322 and an inner diameter (ID) of the port-closure sleeve 325 s, 325 b, are selected such that there is an engagement between the sleeves, and they can then move together during engagement so as to result in the opening of the port- closure sleeves 325 a, 325 b, and the opening of the port 317 a. Such engagement ensures adequate transfer of force from the movable sleeve 322 to the port- closure sleeve 325 a, 325 b, while at the same time reducing the possible damage to the movable sleeve 322 or the port- closure sleeve 325 a, 325 b, due to engagement and their downhole motion.
After port 317 a is opened, the two sleeves 322, 325 a, still in engagement continue to move downhole together, until the front side of the sleeve 325 a engages the shoulder 327 b which stops movement of the port-closure sleeve 325 a. While the engagement between the inner surface of the port-closure sleeve 325 a and the outer surface of movable sleeve 322 enables movement of these two sleeves together, when the sleeve 325 a is stopped by shoulder 327 b, movable sleeve 322 overcoming the engagement force between profile 331 and profile 333, and therefore disengages from sleeve 325 a, due to the hydraulic pressure applied to the movable sleeve 322 and plug 324. In this way, the movable sleeve 322 is displaced under the hydraulic pressure applied to the sealing device 324 to successively engage a plurality of port- closure sleeves 325 a, 325 b, in each stage, and displace each such port- closure sleeve 325 a, 325 b, from a port closed position to a port open position, thereby enabling opening of a plurality of ports using a single plug 324 in engagement with a single movable sleeve 322. The treatment fluid is then circulated from surface through the tubing string and out one or more of the ports 317 a, 317 b, to treat the formation adjacent to the stage occupied by the illustrated portion of the liner 314.
Once the port-closure sleeve 325 a is retained in the groove 341 against the shoulder 327 b, the fluid pressure applied to the plug 324 causes the movable sleeve 322 to squeeze through the port-closure sleeve 325 a and travel towards the next port-closure sleeve to perform the same operation. Importantly, the combination of the plug 324 and movable sleeve 322 moves towards a next port-closure sleeve 325 b, engages with that next port-closure sleeve 325 b using an interference fit that results in the opening of the next port-closure sleeve 325 b, and then squeezes past the next port-closure sleeve 325 b and, optionally, towards a yet another port-closure sleeve in the same stage. This continues until the combination of the plug 324 and movable sleeve 322 have engaged with and opened all the port-closure sleeves of a stage. At that point, the plug 324 is squeezed through the moving sleeve 322 and released in the downhole direction, by increasing the pressure applied from the surface if necessary. In some embodiments, after being released from the moving sleeve 322, the plug 324 can move downhole to another stage where it can be reused to engage with another moving sleeve in that other stage to open more port-closure sleeves in that other stage. In this other downhole stage, the inner diameter formed by the seat of the moving sleeves can be smaller than the inner diameter of moving sleeve 322 to accommodate any narrowing deformation that might have been experienced by the plug 324 in the previous stage.
Due to the small size of the profile 333, as mentioned above, the inner diameter of the port-closure sleeve 325 a is substantially similar to the inner diameter of the tubing string 314. As a result, the pressure drop that results when movable sleeve 322 engages with and then moves past a port-closure sleeve 325 a for example, is negligible. The only material pressure drop that occurs as the ports are opened in the stage illustrated in FIG. 6A or FIG. 6B, occurs when the plug 324 moves past the movable sleeve 322. As a result, pressure drops across the stage do not occur at each port-closure sleeve in a stage, as in prior art systems where a stage that has seven port-closure sleeves results in seven pressure drops occurring at that stage. In the system of FIG. 6A and FIG. 6B, the pressure drop occurs just as the plug 324 moves past the moveable sleeve 322, one time per stage. In contrast to the example set out in the Background of the Invention, where a stage having seven ball seats each associated with a port-closure sleeve experienced a pressure drop of 1934.80 PSI for that stage, the pressure drop across a stage is far lower in the embodiments illustrated in FIG. 6A and FIG. 6B, that would have the same number of ports (i.e., seven, in this example) at each stage. Specifically, in the embodiments of FIG. 6B for example, the plug 324 passes past the movable sleeve 322 once per stage, and the pressure drop as the plug 324 passes past the movable sleeve 322 is about 276.4 PSI. As a result, if the embodiment of FIG. 6B had seven ports per stage, instrad of the two ports per stage that are illustrated, the total pressure drop across all seven port-closure sleeves of the stage is 276.4 PSI because the only restriction in the tubing string is the restriction presented by the ball seat 322-1 of the movable sleeve 322. With only one restriction per stage, the total pressure drop across each stages is far less than the pressure drop across each stage in a conventional completion system.
This total pressure drop across all the sleeves in a stage for the embodiments illustrated in FIG. 6A and FIG. 6B, is to be contrasted with the far higher pressure drop across all the sleeves of a similarly sized stage of prior art systems for performing fracking operations, such as those explained in U.S. Pat. Nos. 6,907,936 and 7,108,067 as described in the Background.
Referring to FIGS. 7a to 7d , the wellbore fluid treatment assemblies described above can also be combined with a series of ball activated focused approach sliding sleeves and packers as described in applicant's corresponding US Application 2003/0127227 to allow some segments of the well to be stimulated using a sprinkler approach and other segments of the well to be stimulated using a focused fracturing approach.
In this embodiment, a tubing or casing string 414 is made up with two ported intervals 316 b, 316 d formed of subs having a series of size restricted ports 317 therethrough and in which the ports are each covered, for example, with protective pressure holding internal caps and in which each interval includes a movable cutter movable sleeve 322 b, 322 d with profiles that can act as a cutter to cut off the protective caps to open the ports. Other ported intervals 16 a, 16 c include a plurality of ports 417 disposed about a circumference of the tubing string and are closed by a ball or plug activated sliding sleeves 22 a, 22 c. Packers 420 a, 420 b, 420 c, 420 d are disposed between each interval to create isolated segments along the wellbore 412.
Once the system is run into the well (FIG. 7a ), the tubing string can be pressured to set some or all of the open hole packers. When the packers are set, stimulation fluids are pumped into the end section of the tubing to begin the stimulation treatment, identified as stage 1 sprinkler treatment in the illustrated embodiment. Initially, fluids will be forced to the lower section of the well below packer 420 d. In stage 2, shown in FIG. 7b , a focused frac is conducted between packers 420 c and 420 d; in stage 3, shown in FIG. 7c , a sprinkler approach is used between packers 420 b and 420 c; and in stage 4, shown in FIG. 7d , a focused frac is conducted between packers 420 a and 420 b.
Sections of the well that use a “sprinkler approach”, intervals 316 b, 316 d, will be treated as follows: When desired, a ball or plug is pumped down the well, and will seat in one of the movable cutter movable sleeve 322 b, 322 d. The force of the moving fluid will push the cutter sleeve down the tubing string and as it moves down, it will remove the pressure holding caps from the segment of the well through which it passes. Once the cutter reaches a desired depth, it will be stopped by a no-go shoulder and the ball will remain in the sleeve effectively shutting off the lower segment of the well. Stimulation fluids are then pumped as required.
Segments of the well that use a “focused stimulation approach”, intervals 16 a, 16 c, will be treated as follows: Another ball or plug is launched and will seat in and shift open a pressure shifted sliding plug activated sliding sleeves 22 a, 22 c, and block off the lower segment(s) of the well. Stimulation fluids are directed out the ports 417 exposed for fluid flow by moving the sliding sleeve.
Fluid passing through each interval is contained by the packers 420 a to 420 d on either side of that interval to allow for treating only that section of the well.
The stimulation process can be continued using “sprinkler” and/or “focused” placement of fluids, depending on the segment which is opened along the tubing string.
It will be apparent that changes may be made to the illustrative embodiments, while falling within the scope of the invention and it is intended that all such changes be covered by the claims appended hereto.

Claims

What is claimed is:

1. An apparatus for treatment of a wellbore comprising:

a tubing string having a longitudinal axis, a wall defining an inner bore, a first port extending through the wall, and a second port extending through the wall and positioned downhole along the axis from the first port;

a first port-closure sleeve proximate to the first port, and adapted to slide within the tubing string from a closed position covering the first port, to an open position uncovering the first port;

a second port-closure sleeve proximate to the second port, and adapted to slide within the tubing string from a closed position covering the second port, to an open position uncovering the second port; and

a movable sleeve located uphole from the first port-closure sleeve and the second port-closure sleeve, the movable sleeve having a seat adapted to receive a sealing device, and the movable sleeve being adapted to slide downhole to engage and displace the first port-closure sleeve from the closed position to the open position, upon receipt of the sealing device at the seat and upon a first application of pressure to the uphole side of said sealing device.

2. The apparatus of claim 1 wherein the movable sleeve is further adapted to:

disengage from the first port-closure sleeve after displacing the first port-closure sleeve from the closed position to the open position; and,

slide downhole past the first port-closure sleeve to engage and displace the second port-closure sleeve from the closed position to the open position, upon a second application of pressure to the uphole side of said sealing device.

3. The apparatus of claim 1, wherein the sealing device is one of a plug and a ball.

4. The apparatus of claim 2, wherein an outer surface of the movable sleeve and an inner surface of the first port-closure sleeve, are adapted to engage in an interference fit with each other.

5. The apparatus of claim 4, wherein the outer surface of the first movable sleeve comprises a movable-sleeve engaging profile, the inner surface of the first port-closure sleeve comprises a first engaging profile, and the movable-sleeve engaging profile is adapted to engage with the first engaging profile.

6. The apparatus of claim 2 further comprising a first port-closure sleeve pin for maintaining the first port-closure sleeve in the closed position, said first port-closure sleeve pin adapted to be sheared after the movable sleeve engages with the first port-closure sleeve and before the movable sleeve displaces the first port-closure sleeve from the closed position to the open position.

7. The apparatus of claim 2, wherein the first port-closure sleeve is installed in a cylindrical groove provided within the tubing string, which restricts movement of the first port-closure sleeve between the closed position and the open position.

8. The apparatus of claim 8, wherein the cylindrical groove has a downhole end that stops displacement of the first port-closure sleeve in the downhole direction.

9. A method for fluid treatment of a wellbore using a tubing string having a longitudinal axis, a wall defining an inner bore, a first port extending through the wall covered by a first port-closure sleeve, and a second port extending through the wall covered by a first port closure sleeve and positioned downhole along the axis from the first port, the method comprising:

displacing a movable sleeve in the tubing string under a first application of hydraulic pressure;

engaging the first port-closure sleeve with the movable sleeve to displace the first port-closure sleeve from a first port closed position to a first port open position;

disengaging the first port-closure sleeve from the movable sleeve and further displacing the movable sleeve downhole past the first port-closure sleeve; and

engaging the second port-closure sleeve with the movable sleeve to displace the second port-closure sleeve from a second port closed position to a second port open position.

10. The method of claim 9, further comprising displacing the movable sleeve under a second application of hydraulic pressure to successively engage a third port-closure sleeve that is positioned in the tubing string downhole from the second port-closure sleeve.

11. The method of claim 10, further comprising displace the third port-closure sleeve from a third port closed position to a third port open position.

12. The method of claim 9, further comprising circulating treatment fluid from surface through the tubing string and through the first and second ports to treat a formation.

13. The method of claim 9 wherein displacing a movable sleeve in the tubing string under a first application of hydraulic pressure comprises launching a plug from surface to land on a seat that is part of the movable sleeve.

14. The method of claim 13, wherein the plug forms a pressure seal with the seat.

15. The method of claim 14, further comprising pressure-isolating a stage of the tubing string with packers positioned outside the tubing string adjacent the first port-closure sleeve.

16. An apparatus adapted to be installed in a tubing string for treatment of a multi-port stage of a wellbore comprising:

a port closure for each port in the stage; and

a movable sleeve adapted to receive a plug, slide downhole along with the plug under hydraulic pressure applied from surface, and displace each port closure to enable circulation of treatment fluid through each port of the stage.

17. The apparatus of claim 15, wherein each port-closure is a cap extending into the tubing string.

18. The apparatus of claim 16, wherein the movable sleeve has a cutting downhole end, adapted to displace the caps from their respective ports as the movable sleeve slides past the caps.

19. The apparatus of claim 15, wherein the movable sleeve is provided with a seat at an uphole side of the movable sleeve, adapted to receive a plug for pressure-sealing the tubing string.

20. The apparatus of claim 15, wherein an outer surface of the movable sleeve and an inner surface of each port-closure sleeve are adapted to engage with each other in an interference fit.