Patent Application
20150369010
The invention relates to a method and apparatus for wellbore fluid treatment and, in particular, to a multi-leg wellbore fluid treatment apparatus and a method for fluid treatment of a wellbore using and managing actuator plugs.
Actuator plugs are used for downhole tool actuation. Generally, actuator plugs are conveyed downhole to land on the tool and actuate it. Actuator plugs can take various forms such as balls, darts, etc. Actuator plugs can be conveyed by gravity and/or fluid flow. In this application, the terms “plug” and “ball” are used interchangeably.
Recently, as described in U.S. Pat. Nos. 6,907,936 and 7,108,067 to Packers Plus Energy Services Inc., the assignee of the present application, wellbore treatment apparatus have been developed that include a wellbore treatment string including one or more openable port mechanisms that allow selected access to one or more zones in a well. The port mechanism employed includes a port through the string wall and a sleeve thereover with a sealable seat formed in the inner diameter of the sleeve. The sleeve may be moved to open or close the port by launching a plug, which can land in and seal against the seat and thereby create a pressure differential to drive the sleeve through the tubing string, such driving acts to open or close the port over which the sleeve is positioned. If more than one openable port mechanism is employed, a plurality of plugs can be used and/or one plug can actuate more than one sleeve. In one multi-sleeve system, the seat in each sleeve can be formed to accept a plug of a selected diameter but to allow plugs of lesser diameters to pass.
Once the pressure differential is dissipated, the plug may tend to lift off the seat and in fact may, by flow of fluids upwardly in the well, begin to move toward surface. If the wellbore treatment apparatus is used in a multi-leg well, the movement of plugs out of the apparatus and/or out of the wellbore leg in which they were employed may interfere with wellbore operations in other parts of the well.
In one embodiment, there is provided a method for fluid treatment of a borehole including a main wellbore, a first wellbore leg extending from the main wellbore and a second wellbore leg extending from the main wellbore, the method including: running a wellbore tubing string apparatus into the first wellbore leg; conveying a plug into the wellbore tubing string apparatus to actuate a plug-actuated sleeve in the wellbore tubing string apparatus to open a port through the wall of the wellbore tubing string apparatus covered by the sleeve; employing a plug retainer to retain the plug in the tubing string against passing outwardly from the tubing string apparatus; allowing fluids to flow toward surface outwardly from the tubing string apparatus; and performing operations in the second wellbore leg.
In another embodiment, there is also provided a wellbore installation for the a well including a main wellbore, a first wellbore leg extending from the main wellbore and a second wellbore leg extending from the main wellbore, the wellbore installation comprising: a tubing string in the first wellbore leg, the tubing string including: an upper end; and a inner bore accessible through the upper end; a sleeve in the inner bore, the sleeve having an inner diameter and a valve seat on the inner diameter such that the sleeve is moveable along the inner bore from a first position to a second position by introducing a plug through the upper end, landing the plug on the valve seat and creating a pressure differential across the plug and valve seat; and a plug retainer to prevent movement of the plug outwardly from the tubing string upper end without sealing fluid flow upwardly out of the upper end, the plug retainer positioned between the valve seat and the upper end; and an apparatus in the second wellbore leg, the apparatus including: a plug-actuated tool.
It is to be understood that other aspects of the present invention will become readily apparent to those skilled in the art from the following detailed description, wherein various embodiments of the invention are shown and described by way of illustration. As will be realized, the invention is capable for other and different embodiments and its several details are capable of modification in various other respects, all without departing from the spirit and scope of the present invention. Accordingly the drawings and detailed description are to be regarded as illustrative in nature and not as restrictive.
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:
a and 2b are sectional view through a wellbore and a fluid treatment assembly positioned therein;
a, 3b and 3c are sequential sectional views through a fluid treatment assembly according to one aspect of the present invention;
a, 5b and 5c are side elevation, side sectional pump in and side sectional landed views, respectively, of a plug useful in the present invention;
a and 7b sequential sectional views through a fluid treatment assembly according to another aspect of the present invention;
a and 8b are sequential sectional views through a plug retainer according to another aspect of the present invention;
a and 12b are sequential sectional views through another plug retainer according to another aspect of the present invention; and
a to 13e are sequential schematic views of operations in a multi-leg well.
The description that follows, and the embodiments described therein, are provided by way of illustration of an example, or examples, of particular embodiments of the principles of various aspects of the present invention. These examples are provided for the purposes of explanation, and not of limitation, of those principles and of the invention in its various aspects. In the description, similar parts are marked throughout the specification and the drawings with the same respective reference numerals. The drawings are not necessarily to scale and in some instances proportions may have been exaggerated in order more clearly to depict certain features.
The apparatus and methods of the present invention can be used in various borehole conditions including an open hole, a lined hole, a vertical hole, a non-vertical hole, a main wellbore, a wellbore leg, a straight hole, a deviated hole or various combinations thereof.
With reference to
A wellbore tubing string apparatus according to an aspect of the invention may provide for retention of a sleeve actuating plug in the tubing string to act against movement of the plug out of the tubing string into which they were introduced. In another aspect a wellbore treatment process is provided that has positional control over the position of the one or more sleeve actuating plugs employed therein, to prevent them from passing upwardly out of the tubing string until it is acceptable to do so.
Referring to
A sliding sleeve 22a is disposed in the tubing string to control the open/closed state of ports 17a in each interval. In this embodiment, sliding sleeve 22a is mounted over ports 17a to close them against fluid flow therethrough, but sleeve 22a can be moved away from a port closed position covering the ports to a port open position, in which position fluid can flow through the ports 17a. In particular, the sliding sleeve is disposed to control the opening of the ports of the ported interval through the tubing string and are each moveable from a closed port position, wherein the sleeve covers its associated ported interval (
Often the assembly is run in and positioned downhole with the sliding sleeve in its closed port position and the sleeve is moved to its open port position when the tubing string is ready for use in fluid treatment of the wellbore.
Sliding sleeve 22a may be moveable remotely between its closed port position and its open port position (a position permitting through-port fluid flow), without having to run in a line or string for manipulation thereof. In one embodiment, the sliding sleeve may be actuated by a plug, such as a ball 24a (as shown), a dart or other plugging device, which can be conveyed in a state free from connection to surface equipment, as by gravity or fluid flow, into the tubing string. The plug is selected to land and seal against the sleeve to move the sleeve. For example, in this case ball 24a engages against sleeve 22a, and, when pressure is applied through the tubing string inner bore 18 through upper end 14a, ball 24a seats against and creates a pressure differential across the sleeve and the ball seated therein (above and below) the sleeve which drives the sleeve toward the lower pressure (bottomhole) side.
In the illustrated embodiment, the inner surface of sleeve 22a which is open to the inner bore of the tubing string has defined thereon a seat 26a onto which an associated plug such as ball 24a, when launched from surface, can land and seal thereagainst. When the ball seals against sleeve seat 26a 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 to a port-open position. When the ports of the ported interval are opened, fluid can flow therethrough to the annulus between the tubing string and the wellbore wall 13 and thereafter into the formation 6.
While only one sleeve is shown in
While plugs and fluid can be conveyed in various ways through the wellbore to upper end 14a, a communication string 27 can be employed to latch onto upper end 14a and provide communication from a bore of string 27 to inner bore 18. A communication string 27 may facilitate fluid communication to string 14 and can be connected to string via a connector 29.
One or more packers, such as packer 20, may be mounted about the string to, when set, seal an annulus 31 between the tubing string and the wellbore wall, when the assembly is disposed in the wellbore. The packers may be positioned to seal fluid passage through the annulus and/or may be positioned to create isolated zones along the annulus such that fluids emitted through each ported interval may be contained and focused in one zone of the well. For example, packer 20 may be positioned between ports 17a and upper end 14a to prevent fluid introduced through ports 17a from flowing through annulus 31 into the remainder of the well above end 14a. If desired, there may be a further packer between ports 17a and ports 17b. Further packers may be mounted between each pair of adjacent ported intervals or at other positions along the tubing string. The packers may 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, a packer below the lowest ported interval may or may not be needed in some applications.
The packers may take various forms. Those shown are of the solid body-type with at least one extrudable packing element, for example, formed of rubber. Solid body packers including multiple, spaced apart expandable packing elements 20a, 20b on a single packer mandrel 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 one packer between each ported interval. The packers can be set by various means, such as plug actuation, hydraulics (including piston drive or swelling), mechanical, direct actuation, etc.
The lower end of the tubing string can be open, closed or fitted in various ways, depending on the operational characteristics of the tubing string that are desired. For example, in one embodiment, the end includes a pump-out plug assembly. A pump-out plug assembly acts to close off the lower end 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 fluid flow through the string and, thereby, the generation of a pressure differential. As will be appreciated, an opening adjacent lower end 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 opened remotely without the need to land a ball or plug therein.
In other embodiments, not shown, the end can be left open or can be closed for example by installation of a welded or threaded plug.
Centralizers and/or other standard tubing string attachments can be used, as desired.
In use, the wellbore fluid treatment apparatus, as described with respect to
Once a selected zone is treated, as desired, ball 24b or another type of sealing plug is launched from surface and conveyed by gravity or fluid pressure to seal against the seat of its target sliding sleeve. Ball 24b seals off the tubing string below its sleeve and opens the ported interval of its sleeve to allow fluid communication between inner bore 18 and annulus 31 and permit fluid treatment of the formation therethrough. Ball 24b is sized to pass though all other seats between upper end 14a and seat 26b, but will be stopped by and seal against seat 26b. After ball 24b lands, a pressure differential can be established across the ball/sleeve which will eventually drive the sleeve to the low pressure side and, thereby open the ports covered by the sleeve.
After fluid treatment is complete through the ports associated with ball 24b, ball 24a is launched, which is sized to be caught in seat 26a. Ball 24a is conveyed by fluid or gravity to move through the tubing string, arrow A (as shown in
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. The apparatus may also be useful to open the tubing string to production fluids.
While the illustrated embodiment, shows only two balls, it is to be understood that the numbers of ported intervals in these assemblies can be varied. In a fluid treatment assembly useful for staged fluid treatment, for example, at least two openable ports from the tubing string inner bore to the wellbore are generally provided such as at least two ported intervals or an openable end and one ported interval.
After treatment, once fluid pressure is reduced from surface, the pressure holding the uppermost ball in its sleeve seats will be dissipated. As shown in
The plug retainer may take various forms. For example, it may entirely be installed in the string before it is run in or it may in whole or in part be conveyed down to become installed in the tubing string when it is deemed an appropriate time to do so, for example after all balls 24a, 24b of interest have been conveyed into the string. As another example, the plug retainer may be selected only to move into a retaining position after the ball actuation process is complete or the plug retainer may be selected to continuously be in a position blocking reverse plug movement out of the upper end of the tubing string. As a further example of options, the plug retainer may seal all movement of plugs and fluid upwardly out of the tubing string or may prevent plug movement while allowing fluid passage upwardly (toward surface) therepast. As another possible option, the plug retainer, once in place in a retaining position, may be permanent or may be removable. As a further possible option, the plug retainer may inhibit downward access of fluid and/or equipment therepast or may allow passage of fluid and at least some equipment (for example: lines). Of course, various combinations of these options are also possible.
As will be appreciated from the foregoing options, the plug retainer may take various forms. As an example, the plug retainer may include a gate, such as a spring, collet finger or a flapper, that protrudes into the inner bore. As another example, the plug retainer may include a separately installable-type ball retainer, which includes a separate body that is conveyed from surface to become secured in the tubing string.
One possible embodiment of a plug retainer is shown in
If desired, the plug retainer body may be removable from profile, when it is no longer needed, such as by acid dissolution or by drilling out, as shown in
In another embodiment, the body may be removed by a spear that engages the body and pulls it out of its locked position. For example, the spear may engage a fishing-type profile on the body or may dig into the material of the body. The spear may be moved to engage and release the body by applying a pull force thereto. The pull force may be generated, for example, by hydraulics or by connection to surface through a line or string. In one embodiment, for example, the spear may be installed on an end of the communication line and may be placed into engagement with the separately installable plug retainer body by adjacent positioning or possibly connection of the communication line. The spear may be installed on an end of the communication line by pumping into that position through the line or by preinstallation, as desired.
Once the body is removed, as shown in
a, 5b, and 5c show another separately installable-type ball retainer formed as body 142 useful in one aspect of the present invention. The body may include fins 143 that facilitate and stabilize the movement of the body through the well by fluid flow to the tubing string. Spring biased expansion rings 148 on the body's leading, nose end act to lock the body into an annular recess 149 in the tubing string. The bore may include a bore 156 through its body from the leading end to the trailing end to permit, when open, fluid flow therethrough. A seal, such as a burst disc 158, may be installed in bore 156 to permit pumping conveyance of the body to and into the tubing string. However, once the body 142 is landed in its position in the tubing string the seal may be overcome to open bore 156. In an embodiment employing burst disc 158 as a seal, the bore may be opened by achieving burst pressures above the disc. The body may also include a screen 160, if desired, to prevent the balls from moving through bore 156, even after the burst disc is open. Balls may accumulate against the screen, but fluid can flow therepast through the bore.
The inner diameter of the tubing string adjacent profile 249 at least on the ball-stopping (downhole) side can be slightly larger than the largest ball, such that when the largest ball is stopped against the screen in the plug retainer, a clearance (at C) remains between the outer diameter of the ball and the inner diameter of the tubing string such that fluid can flow therepast.
In this illustrated embodiment, the plug retainer may be drillable. For example, at least body 242a may be formed of drillable materials and ratchets 248 and profile 249 can have a thread form that limits rotation of the body relative to the tubing string. The anti-rotation feature of ratchets 248 and profile 249 holds the plug retainer steady against drilling rotation of the drill bit. Alternately or in addition, the plug retainer may include a fishing neck 257 to permit latching thereto such as to apply a pulling force to separate the body from ratchets 248.
Another possible embodiment of a plug retainer is shown in
If desired, the fingers may be removable such as by acid dissolution or by drilling out, as shown in
Once the fingers are removed, the tubing string 214 becomes opened for full bore access at least to sleeve 222, as well as for flow back of balls 224a, 224b. As such, the fingers may be left in place until it is considered that the flow back of the balls will not complicate other wellbore operations. For example, fingers 60 might only be removed in one embodiment, after wellbore operations in other wellbore legs of interest are substantially completed.
a and 8b show another gate-type plug retainer including a spring biased gate finger 70 that is held out of the inner bore until released to protrude therein. Gate finger 70 may be in the form of one or more spring loaded structures such as rods or leaves that protrude into the flow path of the tubing string inner bore 318 to prevent balls, such as ball 77, from flowing back and out the upper end 314a of the tubing string 314. During tubing string run in and wellbore treatments, gate finger 70 is held in an inactive position out of the inner bore and out of the fluid flow path and out of the way of tools and actuation balls. In the illustrated embodiment of
As noted above, finger 70 can be sized to prevent bypass of balls but does not block the entire inner diameter of the tubing string such that fluid flow can continue therepast. The recess 72 adjacent gate permits fluid bypass even around a ball 77 stopped against the gate finger.
During tubing string run in and wellbore treatments requiring movement therepast of tools, actuation balls, etc., springs 90 are held out of the inner bore 518 in recess 92 of a retainer housing 95 behind activation sleeve 94, as is shown in
As noted above with respect to other gate-type plug retainers, the springs can be sized and/or grouped to prevent bypass of balls but can continue to permit fluid flow. Ball 96, of course, also may be sized to be captured below the springs. If ball 96, when captured, tends to restrict fluid flow back, along a direction shown by arrows D, through the sleeve, a fluid bypass may be provided. A fluid bypass may include, for example, sleeve ports 99a and channels 99b to permit fluid flow around the sleeve and any ball captured below the springs. In particular, ports 99a and channels 99b are positioned to be aligned when sleeve 94 is moved to expose springs 90. When the ports and channels substantially align, fluids can bypass around ball 96 which is trapped in sleeve below springs 90. In particular, a fluid path is set up from inner bore 518 below sleeve 94, through ports 99a, channels 99b and recess 92 and back into inner bore 518 above upper end 94a of the sleeve, arrows F. There may be a plurality of ports 99a spaced apart, as by multi-drilling, such that lower actuation balls may not readily block these flow ports. Alternately or in addition, a sufficient distance may be provided between trapped ball 96 and the uppermost sleeve of the tubing string such that the lower balls may pile up below trapped ball 96 and not block the fluid bypass. Alternately or in addition, seat 98 may be formed deformable such that it can catch ball 96 and retain it long enough to move the sleeve but will deform to release the ball to continue down the tubing string.
Another gate-type ball retainer is shown in
Fingers 462 are sized and/or grouped relative to the inner bore such that, when they are compressed to protrude inwardly, actuation balls used in the string cannot move therepast. However, open gaps remain between the fingers and the tubing string inner wall, to permit fluid flow to continue therepast even when the fingers are in an active position.
The ball retainer can be operated in various ways to move the fingers into the active, ball retaining position. For example, a tool can be actuated that drives ends 462b toward ends 462a. In the illustrated embodiment, the ball retainer is operated by movement of a sleeve 622. Opposite ends 462b are moved by sleeve 622, when the sleeve is moved axially through the tubing string. In the illustrated embodiment, sleeve 622 includes a seat 626 that can catch and seal with an actuation ball 496. When ball 496 lands and seals against the seat, the seal permits the generation of a pressure differential across the seat and ball that causes sleeve to shift down towards the low pressure side. Sleeve 622 can be pinned by releasable locks such as shear pins 464 to be secured against inadvertent movement, but will be overcome to release when the pressure differential is sufficiently established.
While various orientations are possible, the illustrated sleeve has seat 626 positioned downhole of the fingers and an upper section 622a uphole of the fingers that is connected to move with seat 626. When upper sleeve section 622a is moved with the seat, it bears against ends 462b while ends 462a are stopped against shoulders 467. As a result, the fingers collapse between section 622a and shoulders 467 and fold inwardly.
As noted above, the ball retainer is positioned somewhere between the upper end of the tubing string and the uppermost site of the ball actuation. In the illustrated embodiment, for example, the ball retainer is incorporated into a port opening sleeve. In particular, when sleeve 622 is moved, ports 407 are opened such that fluid can be pumped, arrow F, out from the inner bore. As such, sleeve 622 can serve a dual purpose.
If it is later of interest, seat 626 and fingers 462 can be drilled out. Sleeve 622 may be positioned in an annular recess in the inner wall of the tubing string such that it offers full bore access therethrough after drill out.
If there is concern that the ball retainer will restrict back flow of fluids, the tubing string can be configured such that ports 407 also allow production from the lower stages to be produced by passing out from a lower port 407a, through the annulus to bypass along the outer surface of the tubing string and back in through ports 407. As such, flow may avoid any flow constrictions such as balls that are trapped by the ball retainer.
A method for treating a multi-leg well is described above. In summary, with reference to
One or more of the legs can be treated as by lining, stimulation, fracing, etc. For example, the method may include running an apparatus 704 into at least one of the legs (
In the illustrated embodiment, for example, apparatus 704 includes a tubing string through which wellbore fluid treatment is effected and tools 722 are formed as sliding sleeves actuated by plugs 724. Plugs 724 can be conveyed into the apparatus to land in seats 726 on the sleeves and create pressure differentials to move the sleeves from a closed position to an open condition, to expose ports 707. Wellbore treatments, such as fluid injection, as for fracturing the well, may be carried out through the opened ports 707 (
After the wellbore treatments, the plugs remain in the tubing string, and may unseat and may begin to move toward surface, along direction B. The plugs may be moved by fluid pressure including back flow of fluids such as treatment fluids or produced fluids. As such, a ball retainer 740 can be employed to retain the balls in the apparatus. The ball retainer prevents the first leg balls from flowing out of the apparatus, while allowing fluid flow, arrow P, upwardly past the ball retainer and out of the apparatus.
The ball retainer may have one or more features as described above with reference to any of
The ball retainer is generally set into a ball blocking position before the balls are able to move upwardly past the location of the ball retainer or passing out of the tubing string. In one embodiment, the ball retainer is set before any back flow is encountered in the well and possibly before any surface connection string, such as fracing string 727 is disconnected from the upper end of the apparatus.
As such plugs 724 become trapped in the apparatus 704 behind, downhole of, ball retainer 740 and cannot exit the apparatus. Fluid, however, can continue to flow from the apparatus. Fluid may flow through the trapped balls and ball retainer 740 or fluid may be bypassed about the ball retainer and/or the balls.
Operations may then be carried out in other parts of the well, including in main wellbore 708 or in other legs 711b. In one embodiment (
If desired, when it is appropriate to release the trapped balls and open up the apparatus, ball retainer 740 can be removed, as by drilling out the ball retainer (
The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments without departing from the spirit or scope of the invention. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article “a” or “an” is not intended to mean “one and only one” unless specifically so stated, but rather “one or more”. All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are know or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims. No claim element is to be construed under the provisions of 35 USC 112, sixth paragraph, unless the element is expressly recited using the phrase “means for” or “step for”.
This application claims priority to U.S. provisional application Ser. No. 61/256,944, filed Oct. 30, 2009, U.S. provisional application Ser. No. 61/288,714, filed Dec. 21, 2009 and U.S. provisional application Ser. No. 61/326,776, filed Apr. 22, 2010.
| Number | Date | Country | |
|---|---|---|---|
| 61256944 | Oct 2009 | US | |
| 61288714 | Dec 2009 | US | |
| 61326776 | Apr 2010 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 13499774 | Apr 2012 | US |
| Child | 14838817 | US |
