Patent Application
20180320478
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.
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.
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.
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:
Referring to
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
Packers 20d to 20e are mounted between each pair of adjacent ported intervals. In the illustrated embodiment, a packer 20f is also mounted below the lower most ported interval 16e and lower end 14a 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 20f 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 21a, 21b 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 22c to 22e 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 22c and 22d) 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 22e).
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 24d, 24e (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 24e is sized so that it cannot pass through sleeve 22e and is engaged in it when pressure is applied through the tubing string inner bore 18 from surface, ball 24e 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 26e onto which an associated ball 24e, 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 16e 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 22e has the smallest diameter D1 seat and accepts the smallest sized ball 24e and each sleeve that is progressively closer to surface has a larger seat. For example, as shown in
Lower end 14a 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 14a 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 22e by generation of a pressure differential. As will be appreciated, an opening adjacent end 14a 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 14a 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
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
Packing element 21a is mounted between fixed stop ring 34a and compressing ring 34b and packing element 21b is mounted between fixed stop ring 34c and compressing ring 34d. 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 36a and second piston 36b. First piston 36a acts against compressing ring 34b to drive compression and, therefore, expansion of packing element 21a, while second piston 36b acts against compressing ring 34d to drive compression and, therefore, expansion of packing element 21b. First piston 36a includes a skirt 37, which encloses the hydraulic chamber between the pistons and is telescopically disposed to ride over piston 36b. 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 36b permitting movement therebetween driving pistons 36a, 36b 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 36a, 36b 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 34a 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.
While the ports of interval 216c are open during run in of the tubing string, the ports of intervals 216b and 216a, are closed during run in and sleeves 222a and 222b are mounted within the tubing string and actuatable to selectively open the ports of intervals 216a and 216b, respectively. In particular, in
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 216c to begin the stimulation treatment (
When desired to stimulate another section of the well (
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 222a which is selected to retain the larger ball or plug. The force of the moving fluid will push sleeve 222a down the tubing string and as it moves down, it will open the ports in interval 216a. Once the sleeve reaches a desired depth as shown in
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 22a and 222b 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
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
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 317a is positioned thereover a port-closing sleeve 325a and port 317b is positioned thereover a port-closure sleeve 325b. The sleeves act as valves to seal against fluid flow though their associated ports when they are positioned thereover. However, sleeves 325a, 325b can be moved axially along the tubing string to expose their associated ports, permitting fluid flow therethrough. In particular, with reference to port 317a, each set of ports includes an associated port-closure sliding sleeve 325 disposed in a cylindrical groove 341, defined by shoulders 327a, 327b about the port. The groove is formed in the inner wall of the tubing string and sleeve 325a 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 327a, 327b. Seals 329-2 are provided in the groove between port-closure sleeve 325a and liner 314, such that fluid leakage therebetween is substantially avoided.
The port-closure sleeves, for example 325a, are normally positioned over their associated port, for example 317a, adjacent shoulder 327a, but can be slid along the groove until stopped by shoulder 327b. In each ease, the shoulder 327b is spaced from its ports with consideration as to the length of the associated sleeve so that when the sleeve is butted against shoulder 327b, the port is open to allow at least some fluid flow therethrough.
The port-closing sleeves 325a, 325b 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 325a, 325b are moved by engagement of outwardly biased dogs 351 on the movable sleeve 322. In particular, each sleeve 325a, 325b includes a profile 353a, 353b 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 325a to move it away from its port 317a and against its associated shoulder 327b. 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 325a, along the tubing string 314 and into engagement with the profile 353b of the next port-closure sleeve 325b to move that sleeve and open port 317b, 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 325a, 325b. 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
Using an interference fit, as opposed to the dogs used in the embodiment of
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.
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
In the embodiment of
As in the embodiment of
As in the embodiment of
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 325a. As the external diameter of movable sleeve 322 is substantially equal to the internal diameter of the port-closure sleeve 325a, and to the part of the tubing 314 without a port-closure sleeve 325a, 325b, as a result, the movable sleeve 322 slides inside the tubing string 314 and then inside the sleeve 325a.
In one embodiment, sleeves 322 and 325a 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 325a. 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 325a. 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 325a. 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 325a. As a result, under hydraulic pressure applied to plug 324, the movable sleeve 322 engages port-closure sleeve 325a and forces sleeve 325a to move downhole, resulting in opening of the port 317a.
In more general terms, the outer diameter (OD) of movable sleeve 322 and an inner diameter (ID) of the port-closure sleeve 325s, 325b, 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 325a, 325b, and the opening of the port 317a. Such engagement ensures adequate transfer of force from the movable sleeve 322 to the port-closure sleeve 325a, 325b, while at the same time reducing the possible damage to the movable sleeve 322 or the port-closure sleeve 325a, 325b, due to engagement and their downhole motion.
After port 317a is opened, the two sleeves 322, 325a, still in engagement continue to move downhole together, until the front side of the sleeve 325a engages the shoulder 327b which stops movement of the port-closure sleeve 325a. While the engagement between the inner surface of the port-closure sleeve 325a and the outer surface of movable sleeve 322 enables movement of these two sleeves together, when the sleeve 325a is stopped by shoulder 327b, movable sleeve 322 overcoming the engagement force between profile 331 and profile 333, and therefore disengages from sleeve 325a, 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 325a, 325b, in each stage, and displace each such port-closure sleeve 325a, 325b, 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 317a, 317b, to treat the formation adjacent to the stage occupied by the illustrated portion of the liner 314.
Once the port-closure sleeve 325a is retained in the groove 341 against the shoulder 327b, the fluid pressure applied to the plug 324 causes the movable sleeve 322 to squeeze through the port-closure sleeve 325a 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 325b, engages with that next port-closure sleeve 325b using an interference fit that results in the opening of the next port-closure sleeve 325b, and then squeezes past the next port-closure sleeve 325b 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 325a 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 325a for example, is negligible. The only material pressure drop that occurs as the ports are opened in the stage illustrated in
This total pressure drop across all the sleeves in a stage for the embodiments illustrated in
Referring to
In this embodiment, a tubing or casing string 414 is made up with two ported intervals 316b, 316d 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 322b, 322d with profiles that can act as a cutter to cut off the protective caps to open the ports. Other ported intervals 16a, 16c 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 22a, 22c. Packers 420a, 420b, 420c, 420d are disposed between each interval to create isolated segments along the wellbore 412.
Once the system is run into the well (
Sections of the well that use a “sprinkler approach”, intervals 316b, 316d, 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 322b, 322d. 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 16a, 16c, 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 22a, 22c, 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 420a to 420d 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.
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.
| Number | Date | Country | |
|---|---|---|---|
| 60404783 | Aug 2002 | US | |
| 61048797 | Apr 2008 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 10604807 | Aug 2003 | US |
| Child | 11403957 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 14150514 | Jan 2014 | US |
| Child | 14738506 | US | |
| Parent | 13455291 | Apr 2012 | US |
| Child | 14150514 | US | |
| Parent | 12830412 | Jul 2010 | US |
| Child | 13455291 | US | |
| Parent | 11403957 | Apr 2006 | US |
| Child | 12208463 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 14738506 | Jun 2015 | US |
| Child | 16029506 | US | |
| Parent | 12208463 | Sep 2008 | US |
| Child | 12830412 | US | |
| Parent | PCT/CA2009/000599 | Apr 2009 | US |
| Child | 12830412 | US | |
| Parent | 12405185 | Mar 2009 | US |
| Child | PCT/CA2009/000599 | US |
