Treatment tool for use in a subterranean well

A treatment tool can include a housing with longitudinal passages, a valve that controls flow between sections of one passage, another valve that controls flow between the one passage and a section of another passage, and a locking device that prevents the first valve from being transitioned to an open configuration from a closed configuration. A method can include flowing a fluid through a passage of a service string and into an annulus about a screen, the fluid entering the screen and flowing to another annulus via another passage of the service string, then installing a plug in the first passage, thereby preventing flow through the first passage to the annulus about the screen, and creating at least one pressure differential across the plug, thereby preventing flow from an interior of the screen to the other annulus and permitting flow from the first passage to the screen interior.

BACKGROUND

This disclosure relates generally to equipment and operations utilized in conjunction with subterranean wells and, in an example described below, more particularly provides a well treatment tool and associated systems and methods.

Although variations are possible, a gravel pack is generally an accumulation of “gravel” (typically sand, proppant or another granular or particulate material, whether naturally occurring or synthetic) about a tubular filter or screen in a wellbore. The gravel is sized, so that it will not pass through the screen, and so that sand, debris and fines from an earth formation penetrated by the wellbore will not easily pass through the gravel pack with fluid flowing from the formation. Although relatively uncommon, a gravel pack may also be used in an injection well, for example, to support an unconsolidated formation.

Placing the gravel about the screen in the wellbore is a complicated process, requiring relatively sophisticated equipment and techniques to maintain well integrity while ensuring the gravel is properly placed in a manner that provides for subsequent efficient and trouble-free operation. It will, therefore, be readily appreciated that improvements are continually needed in the arts of designing and utilizing gravel pack equipment and methods.

Such improved equipment and methods may be useful with any type of gravel pack in cased or open wellbores, and in vertical, horizontal or deviated well sections. The improved equipment and methods may also be useful in well operations other than gravel packing (such as, injection operations, stimulation operations, drilling operations, etc.).

DETAILED DESCRIPTION

Representatively illustrated inFIG. 1is a gravel pack system10and associated method which can embody principles of this disclosure. However, it should be clearly understood that the system10and method are merely one example of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of the system10and method described herein and/or depicted in the drawings.

In theFIG. 1example, a wellbore12has been drilled, so that it penetrates an earth formation14. A well completion assembly16is installed in the wellbore12, for example, using a generally tubular service string18to convey the completion assembly and set a packer20of the completion assembly.

Setting the packer20in the wellbore12provides for isolation of an upper well annulus22from a lower well annulus24(although, as described above, at the time the packer is set, the upper annulus and lower annulus may be in communication with each other). The upper annulus22is formed radially between the service string18and the wellbore12, and the lower annulus24is formed radially between the completion assembly16and the wellbore.

The terms “upper” and “lower” are used herein for convenience in describing the relative orientations of the annulus22and annulus24as they are depicted inFIG. 1. In other examples, the wellbore12could be horizontal (in which case neither of the annuli would be above or below the other) or otherwise deviated. Thus, the scope of this disclosure is not limited to any relative orientations of examples as described herein.

As depicted inFIG. 1, the packer20is set in a cased portion of the wellbore12, and a generally tubular well screen26of the completion assembly16is positioned in an uncased or open hole portion of the wellbore. However, in other examples, the packer20could be set in an open hole portion of the wellbore12, and/or the screen26could be positioned in a cased portion of the wellbore. Thus, it will be appreciated that the scope of this disclosure is not limited to any particular details of the system10as depicted inFIG. 1, or as described herein.

In theFIG. 1method, the service string18not only facilitates setting of the packer20, but also provides a variety of flow passages for directing fluids to flow into and out of the completion assembly16, the upper annulus22and the lower annulus24. One reason for this flow directing function of the service string18is to deposit gravel28in the lower annulus24about the well screen26.

Examples of some steps of the method are representatively depicted inFIGS. 2-7and are described more fully below. However, it should be clearly understood that it is not necessary for all of the steps depicted inFIGS. 2-7to be performed, and additional or other steps may be performed, in keeping with the principles of this disclosure.

Referring now toFIG. 2, the system10is depicted as the service string18is being used to convey and position the completion assembly16in the wellbore12. For clarity of illustration, the cased portion of the wellbore12is not depicted inFIGS. 2-7.

Note that, as shown inFIG. 2, the packer20is not yet set, and so the completion assembly16can be displaced through the wellbore12to any desired location. As the completion assembly16is displaced into the wellbore12and positioned therein, a fluid30can be circulated through a flow passage32that extends longitudinally through the service string18. The fluid30can flow through an open valve assembly80of the service string18.

As depicted inFIG. 3, the completion assembly16has been appropriately positioned in the wellbore12, and the packer20has been set to thereby provide for isolation between the upper annulus22and the lower annulus24. In this example, to accomplish setting of the packer20, a ball, dart or other plug34is deposited in the flow passage32and, after the plug34seals off the flow passage, pressure in the flow passage above the plug is increased.

This increased pressure operates a packer setting tool36of the service string18. The setting tool36can be of the type well known to those skilled in the art, and so further details of the setting tool and its operation are not illustrated in the drawings or described herein.

Although the packer20in this example is set by application of increased pressure to the setting tool36of the service string18, in other examples the packer may be set using other techniques. For example, the packer20could be set by manipulation of the service string18(e.g., rotating in a selected direction and then setting down or pulling up, etc.), with or without application of increased pressure. Thus, the scope of this disclosure is not limited to any particular technique for setting the packer20.

Note that, although the set packer20separates the upper annulus22from the lower annulus24, in the step of the method as depicted inFIG. 3, the upper annulus and lower annulus are not yet fully isolated from each other. Instead, another flow passage38in the service string18provides for fluid communication between the upper annulus22and the lower annulus24.

InFIG. 3, it may be seen that a lower port40permits communication between the flow passage38and an interior of the completion assembly16. Openings42formed through the completion assembly16permit communication between the interior of the completion assembly and the lower annulus24. The valve assembly80remains in its open configuration.

An annular seal44is sealingly received in a seal bore46. The seal bore46is located within the packer20in this example, but in other examples, the seal bore could be otherwise located (e.g., above or below the packer).

In the step as depicted inFIG. 3, the seal44isolates the port40from another port48that provides communication between another flow passage50and an exterior of the service string18. At this stage of the method, no flow is permitted through the port48, because one or more additional annular seals52on an opposite longitudinal side of the port48are also sealingly received in the seal bore46.

An upper end of the flow passage38is in communication with the upper annulus22via an upper port54. Although not clearly visible inFIG. 3, relatively small annular spaces between the setting tool36and the packer20provide for communication between the port54and the upper annulus22.

Thus, it will be appreciated that the flow passage38and ports40,54effectively bypass the seal bore46(which is engaged by the annular seals44,52carried on the service string18) and allow for hydrostatic pressure in the upper annulus22to be communicated to the lower annulus24. This enhances wellbore12stability, in part by preventing pressure in the lower annulus24from decreasing (e.g., toward pressure in the formation14) when the packer20is set.

As depicted inFIG. 4, the service string18has been raised relative to the completion string16, which is now secured to the wellbore12due to previous setting of the packer20. In this position, another annular seal56carried on the service string18is now sealingly engaged in the seal bore46, thereby isolating the flow passage38from the lower annulus24.

However, the flow passage32is now in communication with the lower annulus24via the openings42and one or more ports58in the service string18. Thus, hydrostatic pressure continues to be communicated to the lower annulus24. The valve assembly80remains in its open configuration.

The lower annulus24is isolated from the upper annulus22by the packer20. The flow passage38is not in communication with the lower annulus24due to the annular seal56in the seal bore46. The flow passage50may be in communication with the lower annulus24, but no flow is permitted through the port48due to the annular seal52in the seal bore46. Thus, the lower annulus24is isolated completely from the upper annulus22.

In theFIG. 4position of the service string18, the packer20can be tested by applying increased pressure to the upper annulus22(for example, using surface pumps). If there is any leakage from the upper annulus22to the lower annulus24, this leakage will be transmitted via the openings42and ports58to surface via the flow passage32, so it will be apparent to operators at surface and remedial actions can be taken.

As depicted inFIG. 5, a reversing valve60has been opened by raising the service string18relative to the completion assembly16, so that the annular seal56is above the seal bore46, and then applying pressure to the upper annulus22to open the reversing valve. The service string18is then lowered to itsFIG. 5position (which is raised somewhat relative to itsFIG. 4position).

Thus, in this example, the reversing valve60is an annular pressure-operated sliding sleeve valve of the type well known to those skilled in the art, and so operation and construction of the reversing valve is not described or illustrated in more detail by this disclosure. However, it should be clearly understood that the scope of this disclosure is not limited to use of any particular type of reversing valve, or to any particular technique for operating a reversing valve.

The raising of the service string18relative to the completion assembly16can facilitate operations other than opening of the reversing valve60. In this example, the raising of the service string18can function to close a valve assembly80connected in or below a washpipe62of the service string, as described more fully below. The valve assembly80can (when closed) substantially or completely prevent flow from the flow passage32into an interior of the well screen26.

In theFIG. 5position, the flow passage32is in communication with the lower annulus24via the openings42and ports58. In addition, the flow passage50is in communication with the upper annulus22via the port48. The flow passage50is also in communication with an interior of the well screen26via the washpipe62.

A gravel slurry64(a mixture of the gravel28and one or more fluids66) can now be flowed from surface through the flow passage32of the service string18, and outward into the lower annulus24via the openings42and ports58. The fluids66can flow inward through the well screen26, into the washpipe62, and to the upper annulus22via the flow passage50for return to surface. In this manner, the gravel28is deposited into the lower annulus24(seeFIGS. 6 & 7).

As depicted inFIG. 6, the service string18has been raised further relative to the completion assembly16after the gravel slurry64pumping operation is concluded. The annular seal56is now out of the seal bore46, thereby exposing the reversing valve60again to the upper annulus22. The valve assembly80is in its closed configuration.

A clean fluid68can now be circulated from surface via the upper annulus22and inward through the open reversing valve60, and then back to surface via the flow passage32. This reverse circulating flow can be used to remove any gravel28remaining in the flow passage32after the gravel slurry64pumping operation.

After reverse circulating, the service string18can be conveniently retrieved to surface and a production tubing string (not shown) can be installed. Flow through the openings42is prevented when the service string18is withdrawn from the completion assembly16(e.g., by shifting a sleeve of the type known to those skilled in the art as a closing sleeve). A lower end of the production tubing string can be equipped with annular seals and stabbed into the seal bore46, after which fluids can be produced from the formation14through the gravel28, then into the well screen26and to surface via the production tubing string.

A treatment step is depicted inFIG. 7. This treatment step can be performed after the reverse circulating step ofFIG. 6, and before retrieval of the service string18.

As depicted inFIG. 7, another ball, dart or other plug70is installed in the flow passage32, and then increased pressure is applied to the flow passage. This increased pressure causes a lower section of the flow passage50to be isolated from an upper section of the flow passage (e.g., by closing a valve72), and also causes the lower section of the flow passage50to be placed in communication with the flow passage32above the plug70(e.g., by opening a valve74). Examples of suitable valve arrangements for use as the valves72,74are described more fully below.

The lower section of the flow passage50is, thus, now isolated from the upper annulus22. However, the lower section of the flow passage50now provides for communication between the flow passage32and the interior of the well screen26via the washpipe62. Note, also, that the lower annulus24is isolated from the upper annulus22.

A treatment fluid76can now be flowed from surface via the flow passages32,50and washpipe62to the interior of the well screen26, and thence outward through the well screen into the gravel28. If desired, the treatment fluid76can further be flowed into the formation14.

The treatment fluid76could be any type of fluid suitable for treating the well screen26, gravel28, wellbore12and/or formation14. For example, the treatment fluid76could comprise an acid for dissolving a mud cake (not shown) on a wall of the wellbore12, or for dissolving contaminants deposited on the well screen26or in the gravel28. Acid may be flowed into the formation14for increasing its permeability. Conformance agents may be flowed into the formation14for modifying its wettability or other characteristics. Breakers may be flowed into the formation14for breaking down gels used in a previous fracturing operation. Thus, it will be appreciated that the scope of this disclosure is not limited to use of any particular treatment fluid, or to any particular purpose for flowing treatment fluid into the completion assembly16.

As depicted inFIG. 7, the valve assembly80is again in its open configuration. In this open configuration of the valve assembly80, the service string18can be retrieved from the well, without “swabbing” (decreasing pressure in) the well below the packer20. The valve assembly80can be opened for retrieval of the service string18, whether or not a treatment operation is performed (e.g., the valve assembly can be opened after the reverse circulation step ofFIG. 6, whether or not the treatment fluid76is flowed into the well as depicted inFIG. 7).

Although only a single packer20, well screen26and gravel packing operation is described above for theFIGS. 1-7example, in other examples multiple packers and well screens may be provided, and multiple gravel packing operations may be performed, for respective multiple different zones or intervals of the formation14or multiple formations. The scope of this disclosure is not limited to any particular number or combination of any components of the system10, or to any particular number or combination of steps in the method.

Referring additionally now toFIGS. 8A-D, a cross-sectional view of an example of a treatment tool82is representatively illustrated. The treatment tool82can incorporate the valves72,74therein when used in the system10and method ofFIGS. 2-7. In that case, the treatment tool82would be connected in the service string18above the reversing valve60. However, it should be appreciated that the treatment tool82may be used with other systems and methods, in keeping with the principles of this disclosure.

InFIG. 8A, the treatment tool82is depicted in a run-in configuration. When used in the system10, the flow passage32extends longitudinally through the treatment tool82and, during run-in, the fluid30can be circulated through the treatment tool.

In the run-in configuration, the valve72is open and permits flow between the upper and lower sections50a,bof the flow passage50. The valve74is closed and prevents flow between the passage32and the passage50.

The valve72in this example includes a sleeve84and a seal86carried thereon. A seal bore88formed in an outer generally tubular housing90is positioned to sealingly receive the seal86therein when the sleeve84is displaced downward as described more fully below. The housing90may include multiple separate components secured together (such as, by threading, welding, etc.).

An inner generally tubular mandrel92is secured to the sleeve84(for example, by threading). The mandrel92is locked in position relative to the sleeve84with a retainer94(such as, a set screw).

When the sleeve84displaces downward relative to the housing90, a locking device96will prevent subsequent upward displacement of the sleeve84, as described more fully below. Thus, once the seal86has sealingly engaged the seal bore88, thereby isolating the flow passage upper section50afrom the flow passage lower section50b, the upper and lower sections cannot thereafter be placed in communication with each other in the treatment tool82.

The locking device96in theFIGS. 8A-Dexample includes resilient wickers or collets98extending downward from the sleeve84. The collets98have threads or serrations100formed externally thereon for gripping engagement with complementarily shaped threads or serrations102formed in the housing90.

The serrations100,102are configured so that the sleeve84can displace downwardly relative to the housing90before and after the serrations are engaged with each other. However, after the serrations100,102are engaged, upward displacement of the sleeve84relative to the housing90is prevented. In theFIGS. 8A-Dexample, the serrations100,102are initially spaced apart from each other and are not engaged, but in other examples the serrations could be engaged in the run-in configuration.

Note that the collets98with the serrations100, and the housing90with the serrations102, provide for “one-way” displacement of the sleeve84relative to the housing and, thus, the locking device96is a ratchet-type mechanism. However, the scope of this disclosure is not limited to use of ratchet-type locking devices or mechanisms, since other types of devices or mechanisms (such as, snap rings, etc.) may be used to prevent upward displacement of the sleeve84relative to the housing90after the seal is engaged with the seal bore88. The scope of this disclosure is not limited to use of any particular types or configurations of devices, mechanisms or elements of the treatment tool82as described herein or depicted in the drawings.

The valve74in theFIGS. 8A-Dexample includes a sleeve104having openings106formed through a sidewall thereof. InFIG. 8A, the valve74is closed, with the mandrel92overlying the openings106and preventing flow through the openings between the passage32and the passage50.

The sleeve104is releasably secured against displacement relative to the mandrel92by a releasable retainer108. The retainer108is depicted inFIG. 8Aas being a shear screw, but other types of releasable retainers may be used in other examples.

The mandrel92is secured against displacement relative to the housing90by another releasable retainer110that extends through a support ring112. The support ring112is confined longitudinally between a shoulder114formed in the housing90and an upper sub116. Other ways of releasably securing the mandrel92relative to the housing90may be used in other examples.

InFIG. 8B, the treatment tool82is depicted in a plugged configuration, in which the plug70(for example, a ball, dart or other plugging device) is installed in the passage32. The plug70in this example engages a seat118formed in the sleeve104.

A pressure differential can now be created across the plug70by applying increased pressure to the passage32above the plug (for example, using pumps at the surface). In the system10and method ofFIGS. 1-7, the plug70would be installed, and the pressure differential would be created across the plug, after the reverse circulating step depicted inFIG. 6.

The pressure differential across the plug70will result in a downwardly directed force applied to the sleeve104. This force will be transmitted to the mandrel92via the retainer108, and thence to the support ring112via the retainer110. The downward force is resisted (reacted) by the engagement between the ring112and the shoulder114in the housing90, so that the mandrel92and the sleeve104will displace downward in response to the downward force only when sufficient pressure has been applied to the passage32above the plug70to cause the retainer110to release.

InFIG. 8C, the treatment tool82is depicted after the retainer110has released, and the mandrel92and the sleeve104have displaced downward relative to the housing90. The sleeve84remains secured against displacement relative to the mandrel92and has, thus, displaced downward with the mandrel and sleeve104.

The valve72is closed, due to sealing engagement of the seal86in the seal bore88. The flow passage upper section50ais now isolated from the flow passage lower section50b. The locking device96prevents disengagement of the seal86from the seal bore88.

Pressure applied to the passage32above the plug70can be further increased to increase the resulting pressure differential across the plug and the downward force applied to the sleeve104. When the pressure differential and downward force are increased sufficiently, the retainer108will release and thereby allow the sleeve104to displace downwardly relative to the mandrel92and housing90.

InFIG. 8D, the treatment tool82is depicted after the increased pressure differential across the plug70has caused the sleeve104to displace downwardly relative to the mandrel92and housing90. The valve74is now open, and treatment fluid76can be flowed from the passage32above the plug70to the flow passage lower section50b.

When used in the system10and method ofFIGS. 1-7, this actuated configuration of the treatment tool82corresponds to the treatment operation depicted inFIG. 7. The open valve74allows the treatment fluid76to flow into the completion assembly16(for example, into the screen26and thence into the gravel28in the lower annulus24, and possibly into the formation14) via the flow passage lower section50b. The closed valve72prevents the treatment fluid76from flowing to the upper annulus22via the flow passage upper section50a.

Referring additionally now toFIGS. 9A-D, another example of the treatment tool82is representatively illustrated. As with the treatment tool82ofFIGS. 8A-D, theFIGS. 9A-Dexample incorporates the valves72,74and may be used with the system10and method ofFIGS. 1-7, or it may be used with other systems and methods.

InFIG. 9A, the treatment tool82is depicted in its run-in configuration. The fluid30can be circulated through the flow passage32as the completion assembly16and service string18are installed.

The valve72is open, and the valve74is closed. The valve74of theFIGS. 9A-Dexample is very similar to that of theFIGS. 8A-Dexample, in that it includes the openings106in the sleeve104blocked by the mandrel92in its closed configuration.

The valve72of theFIGS. 9A-Dexample, however, is significantly different from that of theFIGS. 8A-Dexample. As depicted inFIG. 9A, the valve72includes the seal86in an initial radially retracted condition. To close the valve72, the seal86is radially extended into sealing engagement with the seal bore88in response to longitudinal compression, as described more fully below.

The locking device96is also significantly different in theFIGS. 9A-Dexample as compared to theFIGS. 8A-Dexample. As depicted inFIG. 9A, the locking device96includes an internally and externally serrated lock ring120interposed radially between the housing90and the sleeve84. The sleeve84is externally serrated and does not carry the seal86externally thereon, but instead is used for longitudinally compressing the seal, as described more fully below.

InFIG. 9B, an enlarged scale view of the locking device96is representatively illustrated, apart from the remainder of the treatment tool82. In this view, the manner in which the lock ring120is complementarily engaged with both of the sleeve84and the housing90is more easily seen.

The lock ring120is split or “C” shaped, so that it is radially resilient. That is, the lock ring120can displace radially between the sleeve84and the housing90. In this example, the lock ring120is resiliently biased radially outward, so that relatively fine ramped external serrations122on the lock ring will engage the internal serrations102in the housing90. The lock ring120also has relatively coarse ramped internal serrations124that engage complementarily shaped serrations126formed externally on the sleeve84.

The two sets of serrations102/122and124/126are appropriately configured (e.g., with mating ramped faces appropriately oriented), so that the lock ring120permits the sleeve84(and the mandrel92connected thereto) to displace downward relative to the housing90, but prevents upward displacement of the sleeve relative to the housing. Thus, the locking device96ofFIG. 9Bis another example of a “one-way” or ratchet-type mechanism.

InFIG. 9C, the treatment tool82is depicted after the plug70has been installed and a sufficient pressure differential has been applied across the plug to cause the retainer110to release. The mandrel92and the sleeve104have displaced downward in response to the downward force resulting from the differential pressure across the plug70.

Note that the seal86has been longitudinally compressed between the sleeve84and the support ring112. The seal86now sealingly engages the seal bore88, thereby closing the valve72.

Subsequent upward displacement of the sleeve84and mandrel92is prevented by the locking device96. Thus, the valve72cannot be reopened (since the seal86will remain compressed between the sleeve84and the support ring112), although in other examples provisions may be included for reopening the valve.

InFIG. 9D, the treatment tool82is depicted after a further increased pressure differential is applied across the plug70, with the increased pressure differential being sufficient to release the retainer108. The sleeve104is now downwardly displaced relative to the mandrel92, so that the valve74is now open.

Treatment fluid76can be flowed from the passage32above the plug70to the flow passage lower section50b. When used in the system10and method ofFIGS. 1-7, this actuated configuration of the treatment tool82corresponds to the treatment operation depicted inFIG. 7.

The open valve74allows the treatment fluid76to flow into the completion assembly16(for example, into the screen26and thence into the gravel28in the lower annulus24, and possibly into the formation14) via the flow passage lower section50b. The closed valve72prevents the treatment fluid76from flowing to the upper annulus22via the flow passage upper section50a.

Referring additionally now toFIGS. 10A-D, another example of the treatment tool82is representatively illustrated. As with the treatment tool82ofFIGS. 8A-9D, theFIGS. 10A-Dexample incorporates the valves72,74and may be used with the system10and method ofFIGS. 1-7, or it may be used with other systems and methods.

InFIG. 10A, the treatment tool82is depicted in its run-in configuration. The fluid30can be circulated through the flow passage32as the completion assembly16and service string18are installed.

The valve72is open, and the valve74is closed. The valve74of theFIGS. 10A-Dexample is very similar to that of theFIGS. 8A-Dexample, in that it includes the openings116in the sleeve104blocked by the mandrel92in its closed configuration. However, the sleeve104in theFIGS. 10A-Dexample is carried externally on the mandrel92.

The locking device96is somewhat different in theFIGS. 10A-Dexample as compared to theFIGS. 9A-Dexample. The locking device96in theFIGS. 10A-Dexample includes the internally and externally serrated lock ring120interposed radially between the mandrel92and a lock ring housing128extending downwardly from the support ring112(which is secured to the upper sub116with one or more fasteners130). The external serrations126are formed on the mandrel92, and the internal serrations are formed in the lock ring housing128. In this example, the support ring112and the lock ring housing128are a single component.

InFIG. 10B, the treatment tool82is still in the run-in configuration, but a cross-sectional view is depicted which is rotated somewhat about its longitudinal axis as compared toFIG. 10A. In the view depicted inFIG. 10B, the releasable retainers108securing the sleeve104relative to the mandrel92are visible, as is the upper section50aof the flow passage50.

Note that the valve74includes openings132formed through the mandrel92above the seat118. The openings132are not in communication with the openings106in the sleeve104when the valve74is in its closed configuration. As depicted inFIG. 10A, rotational alignment between the openings106,132is maintained by one or more fasteners134secured to the mandrel92and reciprocably engaged with respective longitudinally extending slots136formed through the sleeve104.

Another difference in the example ofFIGS. 10A-Dis that this example includes a plug retainer138for securing the plug70in the flow passage32. The plug retainer138prevents the plug70from displacing upward through the flow passage32in subsequent operations, as described more fully below.

The plug retainer138in this example includes radially displaceable retainer members140(such as, balls, lugs, dogs, etc.) received in openings142formed through the mandrel92between the seat118and the openings132. Initially (as inFIGS. 10A-C), the retainer members140are radially outwardly disposed and engaged with a radially enlarged annular recess144formed in the sleeve104. Thus, the retainer members140do not initially protrude into the flow passage32.

InFIG. 10B, the plug70has been installed in the flow passage32. The plug70sealingly engages the seat118below the openings132in the mandrel92. The plug retainer138does not prevent the plug70from sealingly engaging the seat118, since the retainer members140do not obstruct the flow passage32at this point.

InFIG. 10C, the treatment tool82is depicted after a sufficient pressure differential has been applied across the plug70to cause the retainer110to release. The mandrel92and the sleeve104have displaced downward in response to the downward force resulting from the differential pressure across the plug70.

Note that the seal86now begins to sealingly engage the seal bore88, thereby closing the valve72. The sleeve104contacts a support surface148, thereby preventing further downward displacement of the sleeve.

Subsequent upward displacement of the sleeve84, seal86and mandrel92is prevented by the locking device96. Thus, the valve72cannot be reopened, although in other examples provisions may be included for reopening the valve.

InFIG. 10D, the treatment tool82is depicted after a further increased pressure differential is applied across the plug70, with the increased pressure differential being sufficient to release the retainer108(seeFIG. 10B). The mandrel92is now downwardly displaced relative to the sleeve104, so that the valve74is now open (openings106,132are aligned and in communication with each other).

Treatment fluid76can be flowed from the passage32above the plug70to the flow passage lower section50b. When used in the system10and method ofFIGS. 1-7, this actuated configuration of the treatment tool82corresponds to the treatment operation depicted inFIG. 7.

The open valve74allows the treatment fluid76to flow into the completion assembly16(for example, into the screen26and thence into the gravel28in the lower annulus24, and possibly into the formation14) via the flow passage lower section50b. The closed valve72prevents the treatment fluid76from flowing to the upper annulus22via the flow passage upper section50a.

When the mandrel92displaces downward relative to the sleeve104and the valve74opens, the retainer members140are displaced radially inward, so that they now protrude into the flow passage32above the seat118. The retainer members140are outwardly supported in this position by an internal portion146of the sleeve104that is radially reduced relative to the recess144.

In this position of the retainer members140, the plug70cannot displace upward substantially in the flow passage32. Therefore, in subsequent operations (e.g., after the treatment operation), if a pressure differential is created from below to above the plug70, this will not result in substantial upward displacement of the plug through the flow passage32.

Although, in the above descriptions of the treatment tool82examples ofFIGS. 8A-10D, a first pressure differential across the plug70is used to close the first valve72, and a second pressure differential across the plug is used to open the second valve74, it is not necessary for the first and second pressure differentials to comprise different pressure differential levels. For example, the retainer110could be selected to release the mandrel92for displacement relative to the housing90(to thereby close the first valve72) in response to a selected pressure differential created across the plug70, and the retainer108could be selected to release the sleeve104for displacement relative to the mandrel (to thereby open the second valve74) in response to a combination of the selected pressure differential (or substantially the same pressure differential) and inertial effects due to the mandrel displacement suddenly ceasing while the plug and sleeve can continue to displace downward.

In other examples, the retainer110could be selected to release the mandrel92for displacement relative to the housing90(to thereby close the first valve72) in response to a combination of inertial effects due to the plug70momentum as it engages the seat118and a selected pressure differential created across the plug. Thus, the scope of this disclosure is not limited to any particular technique for releasing the mandrel92or sleeve104for displacement, or to any particular relationship between one or more pressure differentials used to actuate the treatment tool82or its valves72,74.

It may now be fully appreciated that the above disclosure provides significant advancements to the arts of constructing and utilizing equipment for well operations. In examples described above, the treatment tool82provides for control of flow paths for the slurry64, the slurry fluid66and the treatment fluid76, and can be conveniently operated by installing the plug70and applying one or more pressure differentials across the plug.

The above disclosure provides to the art a treatment tool82for use with a subterranean well. In one example, the treatment tool82can include an outer housing90with first and second flow passages32,50extending longitudinally through the outer housing90, a first valve72that, in respective open and closed configurations, selectively permits and prevents flow between first and second sections50a,bof the second flow passage50, a second valve74that selectively prevents and permits flow between the first flow passage32and the second section50bof the second flow passage50, and a locking device96that prevents the first valve72from being transitioned to the open configuration from the closed configuration.

The locking device96may permit displacement of a member (such as, the sleeve84) of the first valve72in a first direction, but prevent displacement of the member of the first valve72in a second direction opposite to the first direction. The first and second directions may comprise longitudinal directions. The locking device96may permit displacement of the member of the first valve72only in the first direction.

The treatment tool82may include a mandrel92that circumscribes the first flow passage32, and the locking device96may permit displacement of the mandrel92in a first longitudinal direction, but prevent displacement of the mandrel92in a second longitudinal direction opposite to the first longitudinal direction. A seal86of the first valve72may engage a seal bore88in response to displacement of the mandrel92in the first longitudinal direction. The seal86may be longitudinally compressed in response to the displacement of the mandrel92in the first longitudinal direction.

The treatment tool82may include a sleeve104of the second valve74releasably secured to the mandrel92, and displacement of the sleeve104relative to the mandrel92in the first longitudinal direction may cause the second valve74to permit flow between the first flow passage32and the second section50bof the second flow passage50. A seat118may be disposed in the sleeve104, and a first pressure differential created across a plug70engaged with the seat118may cause the mandrel92to displace in the first longitudinal direction.

The first pressure differential may cause the first valve72to prevent flow between the first and second sections50a,bof the second flow passage50. A second pressure differential across the plug70may cause the sleeve104to displace relative to the mandrel92in the first longitudinal direction. The second pressure differential may cause the second valve74to permit flow between the first flow passage32and the second section50bof the second flow passage50. The second pressure differential may be substantially equal to, or greater than, the first pressure differential.

A seat118may extend about the first flow passage32, and a pressure differential created across a plug70engaged with the seat118can cause the mandrel92to displace in the first longitudinal direction. The treatment tool82may include a plug retainer138that secures the plug70in the first flow passage32.

The above disclosure also provides to the art a method of treating a subterranean well. In one example, the method can comprise: installing a completion assembly16with a service string18in the well; setting a packer20of the completion assembly16, thereby separating a first annulus22from a second annulus24, the second annulus surrounding a screen26of the completion assembly16; flowing a first fluid66through a first flow passage32of the service string18and into the second annulus24, the first fluid66entering the screen26and flowing to the first annulus22via a second flow passage50of the service string18; then installing a plug70in the first flow passage32, thereby preventing flow through the first flow passage32to the second annulus24; and creating at least one pressure differential across the plug70, thereby preventing flow from an interior of the screen26to the first annulus22and permitting flow from the first flow passage32to the interior of the screen.

The “at least one” pressure differential can comprise first and second pressure differentials, the first pressure differential causing flow to be prevented from the interior of the screen26to the first annulus22, and the second pressure differential causing flow to be permitted from the first flow passage32to the interior of the screen26.

The step of preventing flow from the interior of the screen26to the first annulus22may be performed prior to the step of permitting flow from the first flow passage32to the interior of the screen26.

The method can include flowing a second fluid76through the service string18and from the first flow passage32to the interior of the screen26. The second fluid76may be a treatment fluid. The treatment fluid76may comprise an acid or other type of fluid.

The step of preventing flow from the interior of the screen26to the first annulus22may include a locking device96preventing a first valve72from transitioning from a closed configuration to an open configuration. The locking device96may maintain a seal86of the first valve72engaged with a seal bore88. The locking device96may maintain a longitudinal compression of the seal86.

The step of permitting flow from the first flow passage32to the interior of the screen26may comprise opening a second valve74. The step of preventing flow from the interior of the screen26to the first annulus22may comprise closing the first valve72by displacing a mandrel92relative to an outer housing90, the mandrel92circumscribing the first flow passage32, and the step of opening the second valve74may comprise displacing a sleeve104relative to the mandrel92.

The method may include securing the plug70in the first flow passage32, thereby restricting displacement of the plug70through the first flow passage32.

A system10for use with a subterranean well is also described above. In one example, the system10can comprise a completion assembly16including a packer20and a screen26, the packer separating a first annulus22from a second annulus24surrounding the screen; and a service string18engaged with the completion assembly16, the service string including a treatment tool82with first and second flow passages32,50extending longitudinally through the treatment tool. A plug70in the first flow passage32prevents flow through the service string18from the first flow passage32to the second annulus24, a first valve72of the treatment tool82prevents flow through the second flow passage50from an interior of the screen26to the first annulus22, and a second valve74of the treatment tool82permits flow from the first flow passage32to the interior of the screen26through the second flow passage50.

A locking device96of the treatment tool82may prevent the first valve72from being transitioned from a closed configuration to an open configuration. The locking device96may prevent disengagement of a seal86of the first valve72from a seal bore88. The locking device96may prevent the seal86from being longitudinally decompressed.

The service string18may include a plug retainer138that secures the plug70in the first flow passage32. The plug retainer138may include retainer members140that displace radially inward in response to opening of the valve74.

In the above description of the representative examples, directional terms (such as “above,” “below,” “upper,” “lower,” “upward,” “downward,” etc.) are used for convenience in referring to the accompanying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein.