Wellbore treatment tool and method

A wellbore treatment tool for setting against a constraining wall in which the wellbore treatment tool is positionable, the wellbore treatment tool including: a tool body including a first end formed for connection to a tubular string and an opposite end; a no-go key assembly including a tubular housing and a no-go key, the tubular housing defining an inner bore extending along the length of the tubular housing and an outer facing surface carrying the no-go key, the no-go key configured for locking the no-go key and tubular housing in a fixed position relative to the constraining wall, the tubular housing sleeved over the tool body with the tool body installed in the inner bore of the tubular housing; and a sealing element encircling the tool body and positioned between a first compression ring on the tool body and a second compression ring on the tubular housing, the sealing element being expandable to form an annular seal about the tool body by compression between the first compression ring and the second compression ring.

FIELD

The invention relates to a method and apparatus for wellbore treatment.

BACKGROUND

Wellbore completion operations require tools for fluid control and injections. For example, packers are employed to control fluid flows and to isolate and direct fluid pressures. In addition or alternately, fluid delivery tools may be employed to direct injected fluid into particular areas of the formation.

Wellbore fluid treatments may be for wellbore stimulation such as cleaning, acidizing or fracturing (also called fracing).

SUMMARY

In accordance with a broad aspect of the present invention, there is provided a wellbore treatment tool for setting against a constraining wall in which the wellbore treatment tool is positionable, the wellbore treatment tool comprising: a tool body including a first end formed for connection to a tubular string and an opposite end; a no-go key assembly including a tubular housing and a no-go key, the tubular housing defining an inner bore extending along the length of the tubular housing and an outer facing surface carrying the no-go key, the no-go key configured for locking the no-go key and tubular housing in a fixed position relative to the constraining wall, the tubular housing sleeved over the tool body with the tool body installed in the inner bore of the tubular housing; and a sealing element encircling the tool body and positioned between a first compression ring on the tool body and a second compression ring on the tubular housing, the sealing element being expandable to form an annular seal about the tool body by compression between the first compression ring and the second compression ring

In accordance with another broad aspect of the present invention, there is provided a wellbore treatment assembly comprising: a liner installable in a wellbore, the liner including an inner bore defined within an inner wall, an outer surface, a first port extending from the inner wall to the outer surface, a first stop wall on the inner wall spaced axially from the first port, a second port extending from the inner wall to the outer surface spaced axially from the first port and a second stop wall on the inner wall spaced axially from the second port; a tubular string extendible through the liner and manipulatable from surface; and a wellbore treatment tool for setting against the inner wall of the liner including: a tool body including a first end formed for connection to the tubular string and an opposite end; a no-go key assembly including a tubular housing and a no-go key carried on the tubular housing, the tubular housing defining an inner bore extending from a first end to a second end of the tubular housing and an outer facing surface carrying the no-go key and the tubular housing sleeved over the tool body with the tool body installed in the inner bore of tubular housing; and the no-go key biased out to engage against the stop wall and to prevent the no-go key and tubular housing from moving downwardly past the stop wall; and a sealing element encircling the tool body and positioned between a first compression ring on the tool body and a second compression ring on the tubular housing, the sealing element being expandable to form an annular seal about the tool body by setting the no-go key against the stop wall and pushing the tool body down to compress the sealing element between the first compression ring and the second compression ring.

Also provided is a method for treating a formation accessed through a liner port in a wellbore, the method comprising: running into the wellbore with a wellbore treatment tool connected to a tubing string, the wellbore treatment tool including a tool body including a first end formed for connection to a tubular string and an opposite end; a no-go key assembly including a tubular housing and a no-go key, the tubular housing defining an inner bore extending along the length of the tubular housing and an outer facing surface carrying the no-go key, the no-go key configured for locking the no-go key and tubular housing in a fixed position relative to the constraining wall, the tubular housing sleeved over the tool body with the tool body installed in the inner bore of the tubular housing; and a sealing element encircling the tool body and positioned between a first compression ring on the tool body and a second compression ring on the tubular housing, the sealing element being expandable to form an annular seal about the tool body by compression between the first compression ring and the second compression ring; positioning the wellbore treatment tool with the sealing element positioned downhole of the liner port; compressing the wellbore treatment tool to expand the sealing element to set the annular seal downhole of the liner port; and pumping a wellbore treatment fluid into the wellbore uphole of the annular seal and through the liner port into the formation

DETAILED DESCRIPTION OF VARIOUS EMBODIMENTS

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. The drawings are not necessarily to scale and in some instances proportions may have been exaggerated in order more clearly to depict certain features. Throughout the drawings, from time to time, the same number is used to reference similar, but not necessarily identical, parts.

A wellbore fluid treatment tool, assemblies and methods for wellbore operations have been invented. Pluralities of embodiments are disclosed herein but they have common features that may facilitate and increase reliability of a wellbore fluid treatment operation.

With reference toFIGS. 1 to 5, one embodiment of a wellbore fluid treatment assembly is shown. These figures show the assembly including a wellbore treatment tool18and a wellbore tubular liner2, in which the wellbore fluid treatment tool may be positioned for operation. As notedFIG. 1, shows a schematic view of a tool18in position in a liner2within a wellbore4.FIG. 2shows fluid treatment tool18in an inactive condition, apart from the liner. This is the condition the tool is in during run in.FIGS. 3 to 5show the wellbore assembly including the wellbore fluid treatment tool18operating in liner2.

Wellbore tubular liner2and wellbore fluid treatment tool18have features that permit operation to selectively fluid treat a wellbore4in which the liner is positioned, permit reliable placement of wellbore fluid treatment tool18within liner2and permit setting of a seal element26on the tool by simple manipulation of the tool relative to liner2. These features offer many benefits over the prior art.

Liner2may be installed in wellbore4and the liner then provides a conduit through which the wellbore may be selectively treated. The liner may be installed in a cased wellbore or in an open hole wellbore, wherein the formation is exposed and forms wellbore wall4a, as shown.

Liner2may include a plurality of fluid treatment ports6through its wall. The ports extend from the inner bore2adefined within inner wall2bof the liner to its outer surface2cfacing wellbore wall4a.

Liner2may be installed in the wellbore in various ways. Liner2may, for example, be cemented in the wellbore or it may be deployed with packers8and set in the wellbore by expansion of the packers. Packers8may be carried on the liner and, when set, may fill the annular area to separate the annular area between outer surface2cand wellbore wall4ainto fluid-isolated segments. One or more of fluid treatment ports6may open into each isolated segment.

Tool18is formed to fit within inner wall2bwhich forms a constraining wall about the tool and tool18can move through liner2. Tool18may be carried, via its upper end18a, on a manipulation string16, through which the tool18can be axially moved and manipulated from surface. String16may have a solid or a tubular form. String16, for example, may include rods, coil tubing, interconnected tubulars, etc. If fluid is to be conveyed from surface through string16to tool18, the string will, of course, require a tubular form.

To facilitate positioning of the tool18in the liner, a marker profile10may be provided on inner wall2b. As best shown inFIG. 3, marker profile10may be an annular indentation in the liner wall with a particular shape to accept therein a matching, outwardly biased marker key24on tool18. Marker profile10may be positioned downhole of all ports6of interest in the liner and, if desired, the location of marker profile10within the well may be known (as by counting the liner joints installed above the joint accommodating marker profile10, as the liner is installed: called “pipe tally”). Tool18may be run in until key24locates in marker profile10providing a reference indication of the tool's position in the well. When the key is located in its profile10, a correlation can be made between tool depth and liner depth.

Key24is selected to match and engage with marker profile10. Marker profile10may have a shape dissimilar to other liner profiles, such as collar gaps9(aka J-spaces), port location profiles12(to be described hereinafter), etc. Thus, key24catches properly only in marker profile10. For example, marker profile10can have a shape, for example, a length, dissimilar to other liner profiles. In the illustrated embodiment, for example, marker profile10is an axial indentation in wall2band the axial indentation has an axial length L longer than any other profile in the liner. In the illustrated embodiment, marker profile10also has a unique axial shape with a raised portion10abisecting the axial length L.

Marker profile10has a diameter larger than the normal inner diameter ID of the wellbore wall. Marker key24, to land in the marker profile, may have an axial length shorter than the profile's axial length L and conforms to other shape parameters of profile10, such that the key can expand into the profile, when the key is aligned with the profile.

While the above description refers to a single key24, the key, as shown, may actually contain a plurality of keys at the same axial location along tool body18band marker profile10may be formed as an annular indentation (i.e. a cylindrical indentation in wall2b). This arrangement permits the overall key in profile engagement to be circumferential around the tool such that the engagement in the annular profile is not dependent on the rotational orientation of the tool.

Marker key24is biased outwardly from the tool body18bby spring25, but can collapse against the bias of spring25, if sufficient force is applied. Profile10may be a depth such that extra force is required to push key24out of the profile than what is required to move the key along the liner wall2b. Key24and profile10have chamfered ends so that the key can ride out of the locator profile, but extra force is required to do so.

To treat the well, fluids may be pumped through ports6and, thereby into contact with the formation at wall4a. Tool18serves to direct fluid to a selected port. To do so, tool18is moved through liner2to a position adjacent the selected port6and the tool is then manipulated to direct fluid to that selected port. Tool18may then be manipulated to set a seal in the liner, as by use of an annular sealing element26to divert fluid to ports6.

If a marker profile10is employed, ports6in the liner may each be a known distance from the marker profile. Thus, once tool18is positioned in marker profile10, movement of the tool through the known distances positively positions the tool adjacent the ports6.

A locator profile12may be provided in the liner inner wall2badjacent each port6or group of ports in the liner. Locator profile12may be formed as an indentation in wall2band profile12may have a particular shape to accept therein a matching, outwardly biased no-go key34on tool18. Again, profile12may be annular and key34may be plural to provide a circumferential effect and eliminate the need for rotational alignment between tool18and liner2. Each port6adjacent which the tool18is to act, may have a locator profile12close by and possibly each port6is a known position and distance from its profile12.

Locator profiles12may each have a similar shape, but a shape dissimilar to other liner profiles, such as collar gaps9, marker profile10, etc. Thus, key34catches properly only in the locator profiles12. For example, locator profile12can have a shape, for example, a length or pattern dissimilar to other liner profiles. In the illustrated embodiment, for example, locator profiles12each are an annular indentation in wall2band each have an axial length longer than standard profiles but shorter than any marker profile10in the liner. Also, locator profiles12each further have a raised portion that forms a unique pattern along the length. Key34is formed to fit into profile12.

In addition to use as a positioning reference, locator profile12may also have a form that securely engages no-go key34such that the tool can be securely engaged in the liner at the position of profile12. In particular, locator profile12may be formed with a no-go wall12a, which presents an abrupt return wall that an abruptly angled shoulder34aof key34cannot readily pass. Thus, when key34is moved out to engage in profile12, the key cannot pass out of the profile in a direction where shoulder34amust move past wall12a. Through the “no-go” engagement of key34in profile12, a force can be generated in tool18. For example, when key34is engaged in profile12and shoulder34ais set against stop wall12a, force can be applied through tool18to liner2and continued force in the same direction can be generated, for example, to drive operation of tool18.

In the illustrated embodiment, wall12aand shoulder34aare formed to stop key34from moving downwardly through profile12. In particular, wall12afaces uphole toward surface and shoulder34afaces down toward the lower end of the tool. Thus, engagement of key34in profile permits the generation of compressive force in the tool, as by pushing down on the tool relative to the profile, which may include applying a pushing force through string16or simply by slacking off the string supports to place the weight of the tool18and manipulation string16onto key34, as it is engaged against wall12a.

While wall12aand shoulder34aare formed to stop key34from moving downwardly through profile12, the other ends of the key/profile are formed to permit key34to be pulled up out of engagement with profile12. For example, keys can have an upwardly facing chamfered end to facilitate movement of the key upwardly out of profile12. As will be appreciated then, when key34is activated, the illustrated tool18can move in one direction (i.e. upwardly) through profiles12, but not in the other direction (i.e. downwardly) through the profiles.

The outer face of key34may be substantially smooth such that the key can ride readily along the inner wall. Key34may be devoid of surface roughening and is devoid, for example, of teeth. Thus, key34does not act as a slip or drag block. However, key34, when activated, readily expands out into a locator profile and cannot move downwardly past the stop wall of the locator profile so that compressive force can be established in the tool.

The engagement of key34in a profile12serves both for precise locating of the tool relative to a port and compressive operation of the tool.

Since liner2may contain more than one locator profile12and all profiles12are formed to accept engagement therein of no-go key34on tool18, key34may have (i) an inactive condition where it is retained from engagement with profiles12and (ii) an active condition where key34can engage in locator profiles12. The above-noted provision of an inactive condition for key34permits free movement of the illustrated tool12in both directions past the profiles, when desired.

The activation of key34from the inactive condition to the active condition can be by various means. In the illustrated embodiment, this activation of key34from inactive to active is achieved by a mechanical system or hydraulics. A mechanically activated system for the no-gos, could involve a continuous j-slot and jay pin. After locating in the marker joint, the tubing could be reciprocated navigating the jay pin through the j-slot.

This action may trigger the no-go key from the dormant, inactive position to the active position. As shown in the illustrated embodiment, hydraulics are employed, as permitted by a controller. For example, key34is retained in the inactive condition by one or more restraining pistons36. Restraining pistons36overlie the key34and hold it recessed in a cavity on a key housing41, but key34is biased against pistons36by a spring37. Restraining pistons36are moveable to a retracted position away from key34, by hydraulic pressure communicated to a hydraulic chamber38open to pistons36. Tool18includes an inner bore18cextending from upper end18athrough which hydraulic fluid may be communicated from string16. Hydraulic delivery channels39extend from bore18cto chamber38. Seals35hold hydraulic pressure in chamber38and direct the pressure against pistons36. Locks33carried on pistons36may secure the pistons in their retracted positions.

A controller ensures that only certain pressures are sufficient to drive activation of the keys. The controller includes a releasable holding mechanism, such as shear pins40, on pistons36and a valve42in the bore18cto control diversion of pressures to chamber38. Valve42, in this embodiment, includes a ball seat42asized to seal with a ball42bin bore18c. Seat42aand ball42bcreate a one way check valve permitting flow upwardly through tool but resisting fluid flow down past seat42a. The valve, however, can be inactivated when desired. For example, seat42ais releasable, for example, via release of shears43and collapse of detents44, to move past an opening46between bore18cand the outer surface of the tool body. Note the active position of ball seat42ainFIG. 2compared to the inactive position of the ball seat inFIG. 4. Once ball seat42ais positioned below openings46, fluid can flow out of bore18cinto liner2without control by valve42.

As noted above, tool18further includes sealing element26for operation to divert fluid to ports6to treat the wellbore. In this tool, sealing element26is settable/releasable such that it can be set to create a seal and then released to allow the tool to be moved. The sealing element26can be set and released a plurality of times and in different locations, without being tripped to surface.

Sealing element26is set by compressive force, which moves compression rings28a,28btoward each other and compresses therebetween the sealing element to extrude it outwardly. Compressive force can be generated in the tool, by engaging key34in profile12, as described above.

Compressive force can be directed to sealing element26by releasing key housing41to be slidably moveable over tool body18b, which acts as a mandrel for key housing41. Key housing41carries key34and these parts move together axially. Tool body18bis formed to extend through an inner diameter41aof key housing41and tool body18bis slidably moveable in the inner diameter of housing41, when the housing and the tool body are released.

When the key housing41and tool body18bare released for slideable movement and compressive force is introduced to the tool, tool body18bcan be driven down through key housing41, as it remains secured via key34in profile12. Compression ring28ais secured and moveable with body18band compression ring28b, on the other side of element26, is secured and moveable with key housing41. Thus, movement of tool body18bdown through key housing41drives compression, and therefore extrusion and setting, of element26.

To avoid inadvertent setting of sealing element26, key housing41and tool body18bcan only move relative to each other when released to do so. While there are various means for releasably locking the parts together, housing41and tool body18bare locked together via a collet connection with collet dogs47on one part (in this case housing41) that lock into a recess48on the other part (in this case tool body18b). Collet dogs47are locked into engagement with recess48by a lock ring50, but lock ring50is removable from over dogs47to allow them to pull out of the recess when the parts41and18bare moved relative to each other.

Further in this illustrated embodiment, the release of the releasable lock is linked to deactivation of valve42. In particular, lock ring50is connected to ball seat42ato move therewith when ball seat42ais moved. In this embodiment, lock ring50and ball seat42aare connected through a pin52and a sleeve54in which seat42ais installed.

When ball seat42ais moved by a ball landing therein and applying a force capable of shearing shears43, that movement is transferred to pin52, which pulls lock ring50off dogs47. Thus, deactivation of valve42and activation of seal26can occur through the same operation. Once lock ring50is moved away from dogs47, tool body18bcan slide within housing41and the sealing element26can be set and unset by that movement. Note the relative positions of housing41, body18band lock ring50and the condition of sealing element26inFIG. 2compared to the positions of those parts and the expanded condition of seal26inFIG. 4.

InFIGS. 1 to 5, tool18is configured to convey a wellbore treatment through string16and bore18c. As such, tool18includes fluid delivery ports60through the wall of tool body18band a valve62to control flow through bore18cbetween ports60and opening46.

Ports60provide a fluid flow path from bore18cto the outer surface of the tool such that fluid, for example wellbore treatment fluid, can be delivered from surface through string16into bore18cand then to liner2above sealing element26. Since tool18requires pressure actuations, for example of key34, ports60are normally closed but selectively openable. In this illustrated embodiment, a sleeve valve64is movably mounted on the tool to close and open the ports. Sleeve valve64, as illustrated, is held closed by shears66but can be opened by pressure differentials where the pressure external to the tool is greater than the pressure in bore18c. A spring67is provided to drive sleeve64open as soon as the pressure differential is capable of overcoming shears66. Note the relative position of sleeve valve64inFIG. 4compared to that inFIG. 5.

Valve62controls flow through bore between ports60and opening46. Since tool18requires pressure actuations below ports60, but is also operable to deliver treatment fluid through ports60, a valve62is provided that is operable to permit or stop flow through bore18cbelow ports60. Because flow may not be of interest after activation of the tool, valve62could be first open and then permanently closed. However, the ability to move valve62repeatedly between open and closed positions may be of interest for pressure equalization, flushing, to facilitate movement, etc. In the illustrated embodiment, valve62is actuated between open and closed positions by compression and release of compression in the tool. In particular, valve62may be incorporated in a telescoping portion of tool body18b. Valve62may include a telescoping sleeve including ports70that are open when body18bis in tension, but close when body is compressed. Compression of the tool shifts sleeve69into a section of bore18c. Valve62may initially be held against telescopic movement by a releasable lock such as detents, shear pins71, etc., but these are overcome when the body is pushed into compression. Note that valve62is open inFIG. 2, which is the run in condition of the tool and inFIG. 4, valve62is closed.

The tool can include other features such as a disconnect74. The illustrated disconnect is a mechanical hydraulic disconnect, but other configurations are possible.

Tool18, by setting sealing element26, may be used to isolate an upper portion of the liner from a lower portion thereof. With the ports60, the tool may be used to both isolate and pressure effect an area along the wellbore. For example, tool18may be employed to isolate and fluid treat a wellbore by being set adjacent a port6, setting the sealing element26below port6to create a seal in the liner and then directing fluid out through ports60, into the liner and then through ports6into contact with the formation. The annular area15between tool18and liner2may be pressured up to prevent fluid from circulating up through the annulus rather then passing through the ports6. The tool can be run in to the position adjacent port6in an inactive condition, but activated downhole to set the seal, etc.

As noted above, the sealing element of the present tool is set by compression. Tool18works with locator profiles12to permit compressive force to be generated in the tool.

Locator profiles12may be used to ensure proper positioning of the tool in the well by positioning a profile adjacent a position in the well in which it is desired to set the sealing element. For example, the tool may be intended to treat the formation through a port6and a locator profile12may be axially spaced from the port with consideration as to the compressed distance between element26and no-go key34such that when key34is located in the locator profile and the tool is compressed, element26is set below (i.e. downhole of) port6.

To more fully appreciate operational options of the presently described embodiment, note that a liner is run into the well with a marker profile10and locator profiles12on inner wall2b. As noted above, liner2may be cemented into the well or installed in open hole. Each locator profile12is a known distance uphole from marker profile10and each profile12is a known distance downhole from an associated port6. The tool configuration and liner configuration can be correspondingly selected such that when the no-go key is located in a locator profile, the annular seal is positioned downhole of the associated port6and opposite a section of liner wall to accept the expansion of seal thereagainst. The liner and tool can each be relatively compact.

For use, tool18is first connected to string16, which is formed of tubing. Tool18is run into liner2in an inactive condition, as shown inFIG. 1. In the inactive condition, neither no-go keys34nor sealing element26are expanded and, therefore, they do not drag along inner wall2b. The tool can therefore be run in quickly, with little risk of adverse tool wear or stuck conditions. During run in, fluids can be reverse circulated through the tool.

During deployment marker keys24, which are biased outwardly by springs25, contact the liner's inner wall. However, keys24are shaped (i.e. sized and/or machined) such that they do not catch in other profiles in the liner. For example, keys24pass over locator profiles12, j-spaces, etc. without catching therein. Eventually, the tool is moved by string16to a depth where marker keys24land in marker profile10(FIG. 3). At this point, keys24expand out and engage the matching profile10. This engagement point is used as a reference to correlate tool depth to liner depth. Because the marker keys can only catch in one profile in the liner, the operator is assured of the position of the tool, when marker keys24catch in a profile.

After correlation of depths, pressure is applied to string16. As valve62is open in the inactive, run in condition, fluid pressure is communicated down through bore18c. This drives ball42bto seal against seat42aand tubing pressure can be increased. Eventually pressure, communicated through channel39, increases in chamber38and shears pins40permitting restraining pistons36to move away from selective no-go keys34. Springs37located below keys34exert a force on the keys to push them radially out from housing41.

A further increase in pressure shears pins43and collapses detents44to pump seat42aand ball42bdown past openings46. This opens the bore to flow therethrough. The action of seat42abeing driven down also unlocks the collet connection, freeing the no-go key housing41from its fixed position on body18band triggering the sealing element into a compressible condition.

The tool is then fully activated. This can be done at any time before the tool is required to catch in the first profile of interest. Generally, activation occurs while the marker key remains in the marker profile or while the tool is at some point between the marker profile and the first locator profile of interest. Once the tool is activated, it remains active.

The tool can then be moved to engage keys34in a first locator profile12of interest (FIG. 4). Because the distances between marker profile10and profiles12are know, the location of the first locator profile can be determined by monitoring the distance moved by the tool. When keys34are located in a locator profile12, shoulder34acan be set against wall12a. Shoulder34atransfers compressive force into the liner. Increased compressive force packs off sealing element26to create a pressure tight seal between liner inner wall2band the outer surface of the tool. This compressive force also shears the releasable lock on valve62such that the valve ports70can be closed. This prevents fluid flow past valve62and with seal26, communication from string16to the liner below the tool is restricted.

Once the tool has located with key34in profile12, only a simple, single pushing force, such as slacking off weight on the tool, is required to achieve compression.

Applied annular pressure in annular area15can be increased to open ports60. In particular, applied annular pressure shears screws66holding sleeve64in place, which allows spring67to shift the sleeve to the open position (FIG. 5). When this occurs, communication is established between the inside of string16/bore18cand annulus15.

Applied pressure through string16causes a pressure increase in the annulus adjacent port6and the fluid can be used to treat the formation accessed at wellbore wall4a.

Wellbore treatment fluid can be pumped down string16, arrows F, and into contact with the formation. Circulation is prevented back up annulus15by closing an annulus wellhead valve. Also, annular space15may be pressured up to an amount substantially equal to the break down pressure of the formation.

When treatment is complete at port6, tool18is pulled into tension. A straight up pull is all that is required to release the tool. This opens valve62, allowing pressure to balance from end18ato openings46. Excess proppant or other debris that may have accumulated above valve62may be flushed into the liner below tool18. After the pressure has balanced, seal26retracts to the unset position and tool18can be moved to another locator profile. Because the seal cannot retract before the tool is pulled into tension, the engagement of sealing element26against liner wall2bensures that valve62telescopes to open and tool body pulls up through key housing41to release the tension from element26. The keys34remain in an active position and tool18cannot be moved down past that profile12, but keys34can collapse inwardly against the bias in springs37to allow keys34to be pulled up toward surface.

The location of the next profile of interest can be determined by monitoring the distance moved by the tool and the tool will auto-locate in the next profile of interest because keys34match the shape of the profile. Again, compressive force transferred through the tubing string16into keys34and the shoulder of the profile against which the keys are engaged causes isolation seal26to expand out while closing valve62. The formation at the port associated with the next profile of interest can be treated as noted above.

The tool remains active once activated and thus compression is all that is required to prepare the tool for a next treatment. Since tool18can only be compressed when located in a locator profile, the operator can precisely control tool operational positioning and seal expansion.

This process is repeated for all ports and profiles of interest. If the operator does not wish to treat a particular port, that port can be passed without treatment. The keys34land in the profile for that port but can be pulled through. Treatments through the skipped ports could be deferred or targeted in future re-entries or re-fracs.

The tool ofFIGS. 2 to 5is for through-tubing treatments. Another tool embodiment is shown inFIG. 6, which is useful for annular fluid treatments. The tool118ofFIG. 6includes a tool body118b, an upper end118aof which is connectable to a manipulation string116. A compression set sealing element126encircles long axis x of the tool body. Body118bis formed to permit a compression thereof to set the sealing element126. Keys134are carried on the tool to engage the liner102in which the tool is conveyed to permit a compressive force to be applied to the tool.

To treat the well, fluids may be pumped through ports106in liner102and, thereby into contact with the formation at wall104a. Tool118serves to direct fluid to a selected port. To do so, tool118is moved through liner102to a position adjacent the selected port106and the tool is then manipulated to direct fluid to that selected port, as by setting seal element126to divert fluid to port106.

Tool118is formed to fit within and move through a liner102. Manipulation of string from surface string116moves the tool118axially through the liner. String116may have a solid or a tubular form. Since the illustrated tool includes features that are reactive to through tubing pressure, string116has a tubular form.

Optionally, tool118may include a marker key124capable of fitting within a marker profile (not shown). This key is as described above.

If desired and as described above, key134may be a no-go type key formed to engage no-go wall112ain the liner inner wall102b.

Since liner102may contain more than one stop wall112, key134may have (i) an inactive condition and (ii) an active condition. The activation of key134is as described above, although other activation processes are possible as noted above.

Sealing element126is set by compressive force, which moves compression rings128a,128btoward each other and compresses therebetween the sealing element to extrude it outwardly. Compressive force can be generated in the tool, by engaging key134against stop wall112a, as described above.

Because the tool is intended for annular treatments it does not require a port, such as port60ofFIGS. 2 to 4, from its inner bore118cto the outer surface. Also, a valve, such as valve62ofFIGS. 2 to 4, is not required to seal off flow through bore118cof the tool.

However a bypass valve162may be provided between upper end118aand seal126. Bypass valve162may be useful after a treatment has been conducted to pressure equalize above and below the sealing element and to permit debris to be flushed off the seal. Bypass valve162is closed during wellbore treatments but is openable when the tool is pulled into tension (FIG. 7) to unset the sealing element Bypass valve162is also closed during run in, as shown inFIG. 6, but can be activated when downhole to be openable when the tool is pulled into tension.

Various bypass configurations are possible. In the illustrated embodiment, valve162is incorporated in a telescoping portion of tool body118b. Valve162may include a telescoping sleeve169including ports170that are open when body118bis in tension (FIG. 7), but close when body is compressed (FIG. 6). Compression of the tool shifts sleeve169into a section of bore118cwhere ports170are blocked.

During run in, valve162is inactive and cannot open. However, it may be activated when downhole, which in this embodiment is via the same process as that to activate keys134. In particular, sleeve169can slide back and forth within bore118cto expose and close ports170to outer surface. Shear pins may be employed to resist telescoping during run in. However, ports170are normally closed by an extension of sliding sleeve154in which ball seat142ais installed. When ball seat142ais moved by a ball (not shown) landing therein and applying a force capable of shearing shears143, that movement is also moves sleeve154to expose ports170and, thereby, activate valve162to actually allow fluid flow or stop fluid flow by compression. Thus, activation of keys134and activation of bypass valve162can occur through the same operation and that operation is also the same as that to activate seal126, as described above in referenceFIGS. 2 to 4.

The tool can include other features such as a disconnect174. The illustrated disconnect is a mechanical/hydraulic disconnect, but other configurations are possible. The disconnect is selected with a small outside diameter to avoid a blockage in the annular area115between tool118and wall102b.

Tool118, by setting sealing element126, may be used to isolate an upper portion of the liner from a lower portion thereof. The tool may be positioned adjacent a port106, sealing element126may be set to create a seal in the liner below port106and then a fluid treatment may be conveyed through annular area115and out through ports106into contact with the formation. The tool can be run in to the position adjacent port106in an inactive condition (FIG. 6), but activated (FIG. 7) downhole to set the seal, etc.

To more fully appreciate operational options of the presently described embodiment, note that in one embodiment, a liner is run into the well with a marker profile (not shown) and locator profiles112on inner wall102b. Each locator profile112is a known distance uphole from the marker profile and each profile112has a similar stop wall112aand is a known distance downhole from an associated port106.

For use, tool118is first connected to string116, which is formed of tubing. Tool118is run into liner102in an inactive condition, as shown inFIG. 6. In the inactive condition, no-go keys134and sealing element126are held in a retracted condition and, therefore, they do not drag along inner wall102b. During deployment marker keys124, which are biased outwardly by springs125, contact the liner's inner wall. However, keys124are shaped (i.e. sized and/or machined) such that they do not catch in other profiles. For example, keys124pass over locator profiles112without catching therein. Eventually, the tool is moved by string116to a depth where marker keys124land in the marker profile. At this point, keys124expand out and engage the matching shape of the marker profile. This engagement point is used as a reference to correlate tool depth to liner depth.

During run in, fluids can be forward or reverse circulated through the tool.

When the tool is downhole, the tool is activated before it is required for the first wellbore treatment. To do so, pressure is applied to string116and that fluid pressure is communicated down through bore118c. A ball may be dropped from surface to seal against seat142aand tubing pressure can be increased above seat142a. Eventually pressure, communicated through channel139, increases in chamber138and shears shear screws permitting restraining pistons136to move away from selective no-go keys134. Springs located below keys134exert a force on the keys to push them radially out from housing141.

A further increase in pressure pumps seat142aand its ball down past openings146. This opens the bore again to flow therethrough from upper end118ato openings146. The action of seat142abeing driven down also (i) moves sleeve154to activate bypass valve162and (ii) unlocks the collet connection, freeing the no-go key housing141from its fixed position on body118b, allowing the sealing element to be compressed by appropriate action of the tool body relative to the key housing. The tool is then fully activated.

The tool can then be moved to engage keys134in a first locator profile112of interest. Because the distances between the marker profile and profiles112are know, the location of the first profile can be determined by monitoring the distance moved by the tool. When keys134are located in a locator profile112, shoulder134acan be set against wall112a. Shoulder134atransfers compressive force into the liner. Increased compressive force packs off sealing element126to create a substantially pressure tight seal between liner inner wall102band the outer surface of the tool. This compressive force also closes valve162such that there is no communication between annular area115and inner bore118cand, thus, with seal126now expanded, the upper liner is isolated from the lower liner.

Applied annular pressure from surface then can move through annular area115and is diverted by seal126through ports106and into contact with the formation to provide a wellbore treatment.

When treatment is complete at port106, tool118is pulled into tension. This opens valve162, allowing pressure to balance from end118ato openings146. Excess proppant or other debris that may have accumulated above seal126may be flushed through valve162and bore118cinto the liner below tool118. After the pressure has balanced, seal126retracts to the unset position (FIG. 7). Tool118can then be moved up to another locator profile. The keys134remain in an active position and tool118cannot be moved down past that profile112or any other stop wall112a, but keys134can collapse inwardly against the bias in springs137to allow keys134to be pulled up out of a profile toward surface.

The location of the next profile of interest can be determined by monitoring the distance moved by the tool and the tool will auto-locate in the next profile of interest because keys134match the shape of the profile. Again, compressive force transferred through the tubing string116into keys134and the shoulder of the profile against which the keys are engaged causes isolation seal126to expand out while closing valve162. The formation at the port associated with the next profile of interest can be treated, as noted above.

This process is repeated for all ports of interest. If the operator does not wish to treat a particular port, it can be passed without treatment. The keys134land in the profile for that port but can be pulled through.

In the present system, burst disks or shiftable sleeves can close ports6,106. The tool may be employed to pressure effect ports6,106(i.e. burst the disk, hydraulically open the sleeve, etc.) and/or to pressure effect the formation accessed through the port at that area of the wellbore (i.e. to pump fluid through the port into contact with the formation).

For example, tool18,118may be set adjacent a port with a burst disk therein. Element26,126, being set below the perforations, seals the tool against the liner such that fluid pressures can be built up in the annular area at the port. Pressure applied through the tool or through the annular area can be used to rupture the burst disk and open communication with the formation. Stimulation fluid can then be pumped through the port opened by bursting the disk to access the formation.

The tools can also be employed to open a hydraulically shifted wellbore valve, such as one having a piston such as a sleeve or poppet and possibly thereafter to inject fluid into the formation accessed behind the wellbore valve. While many such wellbore valves may be employed, one particularly useful valve sub80is shown inFIG. 7.

The valve sub80includes a hydraulically driven piston member, which herein is a sleeve82but may take other forms such as non-cylindrical sleeves, poppets, pocket pistons, etc., installed in a tubular wall84. The sleeve may be installed such that a pressure differential can be established across the sleeve, between its ends82a,82b, and it can be moved as a piston. The sleeve, for example, may be installed in the wall with a pressure communication path accessing one end82aof the sleeve and another, separate pressure communication path accessing the other end82bof the sleeve.

In one embodiment, for example, tubular wall84can include an upper end84aand a lower end84b. The tubular wall may be formed for connection into a string, such as by forming ends84a,84bas threaded pins or boxes. The tubular wall has an outer surface84cand an inner facing surface84dwhich defines therewithin a bore, which in the drawings is open to the bore102aof the liner102.

Wall84includes chamber86formed therein between outer surface84cand inner facing surface84dand sleeve82is positioned in the chamber. Chamber86is formed such that sleeve82can slide axially in chamber, except as limited by releasable locking structures if any. Since in this embodiment, the sleeve has a cylindrical structure, chamber86herein has an annular form following the circumference of the tubular wall.

Port106extends through wall84passing through annular chamber86. Port106provides fluid communication between bore102aand outer surface84c, which is placeable in communication with a wellbore wall104a, and therethrough a formation, when the sub is installed in a string and the string is installed in a wellbore. Formation communication port106is actually two openings, one through the wall thickness between inner facing surface84dand chamber86and the other through the wall thickness between chamber86and outer surface84c, but these two openings can be collectively considered as port106through which fluids may be communicated between inner bore102aand outer surface84c.

Sleeve82is positioned to open and close port106. For example, sleeve82can be placed in a position in annular chamber86to close port106, wherein the sleeve spans across the port, and sleeve82can be placed in a position in the annular chamber wherein it is retracted from across the port, wherein port106is open to fluid flow therethrough. Sleeve82is moveable within chamber86between a closed port position and an opened port position. As noted above, sleeve82may be moved from the closed port position to the opened port position by generating a pressure differential between ends82aand82bof the sleeve. Chamber86is sized to accommodate this movement having an enlarged space on at least one side of the sleeve into which sleeve82can move.

An opening90is provided from bore102ato chamber86where it is open to end82aof the sleeve and another opening92, that is separate and spaced from opening90, is provided from bore102ato chamber86where it is open to end82bof the sleeve. Thus, pressure can be communicated from bore102ato the ends of the sleeve through ports90,92to create a pressure differential across the sleeve. In the illustrated sub, sleeve82is configured to open by moving down toward end84b. Chamber86has an enlarged space86abetween port106and end84bthat is sized to accommodate sleeve82when it is moved from across port106. Chamber86may further have an end wall86bpositioned between port106and end84b. Opening90, which communicates the opening pressure to chamber86is positioned between port106and end84a. Opening92, which acts as a vent from chamber86to prevent a pressure lock as the sleeve moves, is positioned between port106and end84b. As will be appreciated, if chamber86is closed except for opening92, a pressure lock would occur if sleeve82was sought to be moved beyond opening92. Thus, opening92is spaced sufficiently from port106, for example a length corresponding to at least the length of the sleeve, to permit the sleeve to move through chamber86to open the port. In one embodiment, opening92is positioned well on the opposite side of space86afrom port106, close to end wall86b. When a pressure differential is established between opening90and opening92, these pressures are communicated to ends82a,82bof the sleeve, respectively, and the sleeve will move to the lower pressure side.

Opening90and port106are spaced from opening92with a length D of inner facing wall102bbetween them. The sleeve is positioned behind that length of the inner facing wall and access to the sleeve is prevented by the wall except through openings90,92and port106.

Seals94are provided between the walls defining chamber86and sleeve82to resist leakage between bore102aand outer surface84cpast the sleeve when it is closed and to resist fluid leakage between end82aand end82bto ensure that a pressure differential can be established therebetween. Since some fluid may be communicated to the sleeve through port106as well, as through port90, seals94may be positioned to also ensure that a pressure differential can be established between port106and end82b.

Releasable locking devices may be employed to releasably hold the sleeve in a closed position and/or an open position. For example, shear pins, snap rings, collets, etc. may be employed between the sleeve and the wall. In the illustrated embodiment, shear pins96aare installed between the sleeve and wall84to hold the sleeve in the closed position. The shear pins may be selected such that the sleeve only moves after a sufficient pressure differential is achieved across the sleeve. A collet/gland96b/care employed to hold the sleeve in the open position.

In use, valve sub80may be connected into a liner string102, such as of casing, liner, etc., and installed in a borehole to provide access via ports106from its inner bore102ato the formation through which the borehole is drilled. Valve sub80can accommodate and be operated by a tool such as tool118that can set a seal on inner wall length D such that a pressure differential can be established between port90and92. If there is no isolation between ports90and92, forces are equalized across sleeve82and it will not move to open.

FIG. 7shows tool118in an operative position in sub80. Tool118is set to expand element126isolating the pressure communication path to one end82aof the sleeve from the pressure communication path to opposite end82b. Using tool118, therefore, a pressure differential can be readily established across the sleeve from end82ato end82bthereof and the sleeve can be moved as a piston.

As noted above, length D of inner facing surface84dspans between port106and opening92. This length is sufficient to accept sealing engagement of element126thereagainst, between openings90and92. Port90, being uphole of element126, is in communication with surface through the annulus, as shown, and, thus, pressures can be communicated thereto and to end82a. A pressure differential may be established across sleeve82by increasing the pressure above element126, which is communicated to end82a, while the area below element126, and therefore the pressure at end82b, remains at ambient. When a sufficient pressure differential is reached to shear pins96a, the sleeve moves down toward end84bfrom a closed position to an open position (FIG. 7). When the dogs of collet96breach gland96c, the dogs will lock into the gland to hold the sleeve up in an opened position.

The holding strength of shear pins can be selected. As such, sleeve82can be held from opening until the liner is that the liner may be brought to considerable pressures before shear pins96ashear. Thus, shear pins can be selected such that a pressure hammer can be developed on the formation when sleeve82finally opens.

Valve80is also useful with a through-tubing tool18(FIG. 4), the only operational difference is that fluids are supplied through the tubing string16, rather than through the annular area115. The tool and the valve are selected such that the ports in the tool open before the ports in the valve.

When sleeve82is opened, fluids (arrows F2) can be pumped through ports106to treat the formation accessed at wellbore wall104a.

If sub80is employed with a tool employing locator profile112, the positions of locator profile112, port106and openings90,92can be considered when spacing seal126from keys134, so that sealing element126is properly positioned between openings90,92, when key134is set against locator profile112. Because of the close proximity of keys134and sealing element, valve sub80can be relatively compact with locator profile112, port106and openings90,92all on one tubular body. Thus, if desired, pup joints need not be employed in the liner, making the liner more flexible.

Valve sub80requires venting through opening92into a lower portion of the liner. Thus, the string below the valve must provide for or be opened to provide for displacement of the vented fluid from port92into the string below. In some assemblies, there may be a concern that there is insufficient capacity to vent fluid from chamber86ainto the liner. This may occur if port106of interest is the lowest one in the liner. In such a case, an outwardly venting valve may be provided, where the lower opening vents to outer surface84brather than to inner bore102a. Such a valve is shown inFIG. 4, wherein port6is closed by a sliding sleeve182that is opened by creating a pressure differential between its ends, one end of which is exposed to liner pressure and the other end of which is exposed to annular pressure between liner2and wellbore wall4a. An opening190provides fluid communication between one end of sleeve182and liner inner bore2aand another opening192provides fluid communication between the opposite end of sleeve182exposed in chamber186aand liner outer surface2c.

A liner including a plurality of ports may employ a plurality of valve subs that have communication ports open to the inner wall of the liner, such as for example those described in reference to valve sub80ofFIG. 7, since such a valve sub is only openable when a tool is set to isolate upper opening90from lower opening92. Without a seal set between the openings90,92of any particular sub80, the sleeve cannot open. If a liner has a closed lower end, however, an outwardly venting valve, such as that described in respect ofFIG. 4, may be employed as the lower-most valve in the liner.