Sleeve valves, shifting tools and methods for wellbore completion operations therewith

A shift uphole-to-open sleeve assembly is provided for insertion along a tubular string for multi-stage, selectable wellbore treatment. The sleeve assemblies are very short in length, being too short for in-sleeve engagement, and instead have a downhole shoulder engageable for opening using dogs of a conventional shifting tool. Use of a common J-mechanism having four axial inappropriately places the sealing packer of a downhole tool above the sleeve ports. Multiple extra J-mechanism cycles are required to position the packer downhole thereof. Herein a modified downhole tool is disclosed including a biased repositioning sub to eliminate many of the extra tool cycles. In embodiments the short sleeve can replace casing collars.

FIELD

Embodiments taught herein relate to apparatus and methods for use in wellbore completion operations and, more particularly, to apparatus and methods for shifting sleeves for opening ports spaced along a tubular string in a wellbore.

BACKGROUND

Conventional sleeve assemblies are used to open and close ports in tubular string extending along a wellbore. Each sleeve assembly comprises a tubular housing fit with a sleeve. The sleeve assemblies are typically spaced along casing, for permitting the flow of fluids through ports when the sleeve is shifted axially to expose ports in the housing or to block the flow of fluids therethrough when the sleeve covers the ports. Shifting tools are used for shifting the sleeve in a single shift operation to an open position, or can be manipulated to both open and to close in a multi-cycle operation. Downhole sliding sleeves having multiple open and close cycles, as guided by a J-mechanism, have been termed “multi-cycle” since at least 2003 as disclosed by Smith International Inc in U.S. Pat. No. 7,337,847B2 and “multi-cycle” dump valve for fracturing of packer isolated annulus intervals since 2002 as disclosed in US70909202 to Schlumberger Technology Corp.

Tubing-conveyed shifting tools sequentially manipulate a large number of sliding sleeve valves (cemented or uncemented) spaced along a casing string extending downhole for fracturing in an oil or gas well (vertical, deviated or horizontal). Open-only sleeve assemblies are typically operated in a toe-to-heel treatment and, for each treatment, a releasable packer can be positioned to isolate each treated zone below from the next uphole zone above.

Shifting tools have been utilized for decades in the wellbore cementing industry and in the late 1990's were typically limited to running in a profiled, key-type shifting tool downhole to shift a sleeve, which is then pulled out of hole, and then a subsequent tool is run in for fracturing through the open sleeve above a packer or between straddle packers.

Further, shifting sleeves downhole in extended horizontal wells becomes a challenge as surface applied force becomes weak and difficult to discriminate at great depths. In U.S. Pat. No. 5,513,703 to Mills and issued in 1996, the reliability of shifting a sleeve downhole to close was improved by actuating a packer to engage a sleeve and seal between the shifting tool and the sleeve. The impetus to drive the sleeve downhole to cycle the sleeve was assisted by a downward force on the packer, acting as a piston, generated by the fluid pressure introduced above the packer and into the annulus between the shifting tool and the packer-engaged sleeve.

In U.S. Pat. No. 8,794,331 to Getzlaf et al, the port closure sleeve assemblies implemented therein were located using a shifting tool having an implementation of casing collar locator at a downhole end thereof and which located the bottom of the sliding sleeve in the assembly. The sliding sleeves are therefore manufactured long enough to necessarily accept the concatenation of components above the collar locator including a J-mechanism and a resettable slip and packer assembly, the packer assembly being spaced uphole from the locator for engaging the inside of the sleeve thereabove.

Despite the challenges in the downhole shifting of remote sleeves, such sleeves are also susceptible to engagement and accidental shifting by a tool passing thereby while being run-in-hole (RIH) past the sleeve assembly. It is not unknown in completion operations that downward-facing shoulders or other protrusions on shifting tools can accidentally engage a sleeve and, if sufficient force is applied on run-in, can accidentally shift the sleeve downhole and unexpectedly open the ports. In some cases, the act of accidental shifting of the sleeve to the open position may not be detected at surface and is only discovered later when tubing integrity pressure tests fail or fluid is released to the formation at an unplanned zone therein. Particularly in multi-zone completions, there is a need for assurance regarding which sleeve assembly is open and which is not.

Another challenge with conventional sleeve valves assemblies is that they can often be relatively long so as to ensure there is sufficient length in which to ensure locating and in-sleeve engagement of the shifting tool intermediate along the sleeve. It is not unknown that such assemblies are over two or even over four feet in length. Further, additional lengths of tubulars or subs, which can be a further four or more feet in length, may be required at either end of the sleeve assembly to enable locating and ensure positioning and operating of the compatible bottomhole assembly (BHA) having shifting tools thereon. Additional sleeve length translates into additional material and manufacturing complexity and cost. Further, the heavy sleeves are more difficult to manage, even requiring the implementation of additional equipment simply for handling during makeup of the string.

There is interest in the oil and gas industry for sleeve assemblies that are relatively simple in design, hand-manageable, have a low cost, and furthermore are reliably engaged and operated to open ports, such as for hydraulic fracturing operations.

SUMMARY

Generally, due to the embodiments described herein, the resulting sleeve assemblies are suitable for multi-stage, selectable wellbore communication, such as for hydraulic fracturing. The sleeve assemblies are very short in length, low in unit cost, easy to handle by site personnel, and can be readily and reliably opened using known shifting tools having bore-engaging elements. In embodiments, a completion casing string, using sleeve assemblies, can replace the usual need for coupling casing collars, economically utilizing the sleeve assemblies as the only connections between adjacent casing sections.

In embodiments a known BHA, incorporating a shifting tool, is also disclosed that is capable of a basic single-shift, sleeve-opening function. Further, a modified BHA is additionally equipped with a repositioning sub for dragging the BHA downhole below an opened sleeve assembly with a minimum of cycling between tool operational modes, thus reducing operations costs, cycle fatigue of the tool-conveyance tubing string, and a per-unit cost of the sleeve assemblies themselves.

In combination, methods of multi-zonal fracturing are achieved using short open-only sleeve assemblies and a low-cycle or reduced-cycle BHA.

In one broad aspect of the invention, a completion string is provided for accessing a downhole formation comprising a string of tubulars at least some of which are connected by sleeve assemblies for selectable fluid communication from the tubular string to the formation. Each sleeve assembly has a sleeve housing having a housing bore and one or more ports to the formation formed through the housing. A sleeve is fit slidably to the housing bore and has a sleeve bore, the sleeve being slidable from a downhole closed position in which the ports are blocked by the sleeve, to a uphole open position in the which the ports are open. An annular recess is formed in the housing bore downhole of the sleeve and has a diameter greater than that of the sleeve bore, the sleeve having a downhole engagement shoulder extending radially into the housing bore.

In embodiments, a BHA having a shifting tool incorporated therein can engage the annular recess and downhole engagement shoulder with an engagement element or dog for shifting the sleeve uphole to the open position.

In embodiments, each sleeve assembly of the completion string can be short in length wherein each of the one or more ports have an axial extent; and the sleeve has a sleeve length between about 2.5 and about 3 times the axial extent of the ports. In embodiments, the sleeve length accommodates the axial extent of the ports and enough uphole and downhole sleeve overhangs to house uphole and downhole seals therein. For example, for ports having an axial extent of about 1 inch, the short open only sleeve has a sleeve length between about 2.5 and about 3 inches.

In embodiments, for incorporating an annular recess for receiving an BHA's engagement element, the sleeve bore has a diameter at or larger than that of the tubular string; and the annular recess has a diameter larger than that of the sleeve bore, the sleeve having a downhole engagement shoulder extending radially into the housing bore. Further, the housing bore has a downhole stop formed therein and the ports being spaced uphole therefrom, the sleeve bearing axially against the downhole stop in the closed position to block the ports uphole thereof, and the sleeve's downhole engagement shoulder extending radially into the housing bore at the downhole stop.

In another aspect, a sleeve assembly for a tubular string completed into a formation comprises a tubular sleeve housing having a housing bore within, one or more ports distributed circumferentially thereabout at an axial port location along the housing and formed therethrough, the ports having an axial extent; and a sleeve having a sleeve bore and fit to the housing bore and forming a sleeve annulus therebetween. The sleeve is slidably moveable axially along the housing bore from a first downhole position, blocking the one or more ports between the tubular bore and the formation, to a second uphole position, opening the one or more ports for fluid communication therethrough to the formation. The sleeve has an uphole end, a downhole end, and an axial length therebetween, the sleeve length accommodating at least an uphole annular seal in the sleeve annulus to seal the blocked ports from the sleeve annulus uphole thereof and at least a downhole annular seal to seal the blocked ports from the sleeve annulus downhole thereof.

In embodiments, the sleeve length can be minimized wherein each of the one or more ports have an axial extent; and the sleeve length is between 2.5 and 3 times the axial extent of the ports.

In another broad aspect, a method is provided for treating a zone in a formation accessed with a completion string having one or more sleeve assemblies therealong comprising running a bottom hole assembly (BHA) downhole on a conveyance string, to a location in the completion string below a selected sleeve assembly of the plurality of sleeves. The sleeve assembly is located and actuated to the open position by pulling uphole on the BHA to cycle an engagement element of the BHA to a locating mode and continue pulling up in locating mode until the engagement element radially engages an annular recess in a sleeve housing of the sleeve assembly, the recess being adjacent and downhole of a sleeve slidable in the sleeve housing. One continues pulling uphole on the BHA to engage the sleeve with the engagement element and shift the sleeve uphole to an open position to open treatment ports through in the sleeve housing. Once open, one runs the BHA downhole to cycle the engagement element to a run-in-hole mode and continues running the BHA downhole to position a resettable packer and slip assembly of the BHA downhole of the selected sleeve assembly. To treat the formation, one sets the packer and slips across the completion string and begins treating the formation through the opened treatment ports. After treatment, the BHA is pulled uphole to release the resettable packer and slip assembly and continue pulling uphole reposition the BHA uphole of the selected sleeve assembly.

In embodiments, the the BHA has a J-mechanism comprising at least four axial positions, an intermediate downhole position D1in which the engagement elements are constrained radially inward for free run-in hole (RIH) movement downhole; an extreme uphole position U1in which the engagement elements are biased radially outward for locating (LOC) the housing recess downhole of the sleeve; an extreme downhole position D2for setting (SET) the resettable packer and slip assembly across the completion string; and an intermediate uphole position U2in which the engagement elements are constrained radially inward for free pull-out-of-hole (POOH) movement uphole.

Implementing the four position J-mechanism, and after shifting the sleeve uphole to the open position, the step of running of the BHA to position the resettable packer and slip assembly to below the selected sleeve assembly further comprises: running the BHA downhole in RIH mode to cycle the J-mechanism; soft setting the BHA in SET mode to cycle the J-mechanism; pulling the BHA to POOH mode and position the BHA above the selected sleeve; running the BHA downhole to below the selected sleeve assembly in RIH mode; pulling the BHA to LOC mode to cycle the J-mechanism; and setting down on the BHA for setting the packer and slips across the completion string in SET mode.

In embodiments the number of cycles between opening successive sleeve assemblies is reduced with a modified BHA wherein the BHA further comprises a telescopic BHA repositioning sub situate between the J-mechanism uphole thereof and a drag block downhole thereof, and wherein: the shifting of the sleeve uphole to the open position further comprises telescoping the repositioning sub to an extended, energized position; and, the running of the BHA to position the resettable packer and slip assembly to below the selected sleeve assembly further comprises setting down on the BHA in SET mode for releasing the energy of the extended repositioning sub for collapsing the repositioning sub and dragging at least a slip portion of the resettable packer and skip assembly downhole of the open, selected sleeve assembly without actuating the resettable packer and slip assembly; and once the repositioning sub is collapsed, further setting down on the BHA for setting the packer and slips across the completion string in SET mode.

The telescoping of the repositioning sub to an extended, energized position comprises frictionally restraining a J-mechanism housing and slips with the drag block, pulling a J-mechanism mandrel uphole to space the packer from the slips in LOC mode, and operatively energizing a biasing spring within the repositioning sub between the mandrel and the housing; the setting down of the BHA for releasing the energy of the extended repositioning sub comprises biasing the J-mechanism housing and slips downhole towards the drag block while the J-mechanism mandrel follows downhole, the BHA repositioning below the open, selected sleeve.

In another aspect, a modified bottom hole assembly (BHA) is provided and conveyed downhole on a conveyance string for actuating a sleeve assembly of a completion string having one or more of the sleeve assemblies therealong. The BHA comprises a BHA mandrel slidable within a BHA housing downhole thereof and a J-mechanism operative therebetween, the BHA mandrel connected at an uphole end to a conveyance string and having a packer thereon, the BHA housing having slips at an uphole end thereof and connected to a drag block at a downhole end for restraining the BHA housing along the completion string, and a telescopic BHA repositioning sub situate between the BHA housing uphole thereof and the drag block downhole thereof wherein, the repositioning sub having a slack mandrel connected to the BHA housing, a slack housing connected to the drag block and a biasing spring between the slack mandrel and the slack housing for energizing upon compression thereof upon an uphole pull of the BHA mandrel and connected slack mandrel and energy being released upon a release of the sleeve engagement elements from the sleeve housing for telescoping the slack mandrel towards the slack housing and dragging the BHA housing downhole thereof.

The BHA further comprises a shifting tool having one or more engagement elements connected to the BHA housing and movable axially relative to the BHA mandrel and radially actuable between a radially outward biased position to locate and shift the sleeve assembly to an open treatment position, and a radially inward collapsed position for free movement in the completion string, a cone movable axially with the BHA mandrel between two positions, an engaged position with the housing's engagement elements to urge them in the radially outward position and a disengaged position, and a packer for sealing to the completion string in the cone's engaged position.

In embodiments, the slack mandrel telescopically extends from the slack housing by a stroke length, the stroke length being greater than the distance between the spacing between slips and the packer in the cone engaged position wherein when the cone moves axially from the engaged to the disengaged position, the slack mandrel telescopically drags the BHA housing downhole and the packer is dragged downhole of the sleeve assembly.

DETAILED DESCRIPTION

Having reference toFIGS. 1 and 2, embodiments taught herein comprise a single-shift sleeve assembly10, wherein a tubular sleeve12is axially shiftable within a bore14of a tubular housing16. The housing16is installed, such as by threaded connections, between facing ends of adjacent tubulars in a tubular string along the wellbore, typically a completion or casing string40.

At least some of the tubulars in the string, such as those in the formation of interest, are connected by sleeve assemblies10for selectable fluid communication from the tubular string to the formation. The sleeve12is fit slidably to the housing bore16and has a sleeve bore13, the sleeve12being slidable from a downhole closed position in which the ports are blocked by the sleeve, to an uphole open position in which the ports are open. The one or more ports are formed through the housing16and are openable and closeable to the formation.

The sleeve12is initially in a closed position (FIG. 1), aligned axially in the housing16for blocking flow through one or more ports18located and distributed circumferentially about in the housing16at an axial port location along the housing16and formed therethrough. The ports have an axial extent, typically circular, that determines the minimum length of the sleeve12.

For fluid communication between the tubular bore14and the wellbore outside of the tubular16, the sleeve12is shifted uphole to an open position (FIG. 2) to axially expose the ports18and permit flow of treatment fluids therethrough.

Shifting uphole-to-open is contrary to most conventional completion operations for treatments such as multi-stage hydraulic fracturing operations. As shown inFIG. 6A, Applicant has also employed in shift downhole-to-open sleeve assemblies, having certain advantages in implementing the J-mechanism shifting cycles. However, in long horizontal wellbores, the shifting of sleeves downhole becomes increasingly challenging proportionately to the length of wellbore to be treated, due to the increasing difficulty of applying a functional downhole force through the long slender conveyance string to a downhole bottom hole assembly (BHA).

Accordingly, herein, an open-uphole sleeve assembly is provided, the pulling of a conveyance string having some advantages in the application of force over the conventional downhole push arrangements. Further, the modification in the operation of conventional BHAs and an alternate BHA is reviewed herein.

Having reference again toFIG. 1, in the initial closed position, the open uphole sleeve12is a tubular, slidably fit to the housing bore14, and having a bore13smaller than that of the housing bore14. An annular recess14R formed in the housing bore14downhole of the sleeve12and has a diameter greater than that of the sleeve's bore13. The sleeve bore13has a diameter at or larger than a string bore diameter of the tubular string for passage of BHA therethrough. The annular recess14R has a diameter larger than that of the sleeve bore13resulting in a downhole engagement shoulder extending radially from the sleeve12into the housing bore14, forming a downhole-facing shoulder20at a distal end26thereof.

The housing bore14has an uphole-facing stop22formed therein and the ports18are spaced uphole therefrom. A closed sleeve bears axially against the uphole-facing stop in the closed position to block the ports18uphole thereof, and the sleeve's downhole engagement shoulder20extends radially into the housing bore at the uphole-facing stop.

Closed, the sleeve's shoulder20rests against the uphole facing stop22formed at a localized narrowing of the bore14of the tubular housing16downhole of the sleeve12. A pair of seals30,30, situate in the annulus between the housing bore14and the sleeve12, axially straddle the ports18to minimize fluid leaks therethrough and provide pressure integrity when closed.

The sleeve12has an uphole end27, the downhole end20, and an axial length therebetween, the sleeve length accommodating at least an uphole annular seal30in the sleeve annulus to seal the blocked ports18along the sleeve annulus uphole thereof and at least a downhole annular seal to seal the blocked ports along the sleeve annulus downhole thereof.

Minimizing the sleeve length, each of the one or more ports18have an axial extent and the sleeve12has a sleeve length between about 2.5 and about 3 times the axial extent of the ports.

The sleeve12can be temporarily retained in the downhole closed position using a first retainer24, such as a detent or shear screw acting between the housing16and the sleeve12. The sleeve's downhole-facing shoulder20bears against the uphole-facing stop22to mitigate against accidental movement of the sleeve12when a BHA, or other tool is run-in-hole (RIH) through the sleeve assembly bore14. Further, the first retainer24can have a low retaining force which is overcome to operate the sleeve to the open position compared to prior art retainers for downhole-opened sleeves that are exposed to accidental downhole opening forces. In embodiments, the first retainer24can be released at a force of less than about 2000 daN and is better suited to the weak at-tool application forces available in deep wells.

Generally, the risk of accidental uphole opening of a sleeve on any particular uphole traverse is low. Most downhole tools or BHAs are already designed with tapered uphole shoulders and connections to freely allow the tools to readily be pulled-out-of-hole (POOH) without significant engagement with the casing string, sleeves, and the like. Accordingly, there is low risk that even the low-force detent could be accidently overcome to open the shift-up-to-open sleeve12.

In embodiments taught herein, the downhole-facing shoulder20of the sleeve12extends radially inwardly from the housing bore14. Described in greater detail below, the BHA and integrated shifting tool, having radially extending sleeve engaging elements, can be pulled uphole into the housing16to traverse the housing bore14. The engaging elements engage a recess15formed by the radial difference between the housing bore14and the sleeve bore13. The recess15is formed downhole of the sleeve12at the downhole-facing shoulder20. An additional uphole force on the elements overcomes the first retainer24to shift the sleeve12uphole.

With reference toFIG. 2, after the sleeve12is pulled uphole, the exposed ports18are open between the tubular bore14and the wellbore outside of the tubular16.

Best seen inFIG. 2, the first retainer24can be cooperating collet and annular rings, the tubular collet having flexible fingers29extending uphole from the housing16and the sleeve12which bears complementary annular rings27upstanding radially between the housing16and sleeve12.

The sleeve12is absent a profile or other feature along the axial length of the sleeve that would need to cooperate directly in juxtaposition with a shifting tool and having a comparative recess-accommodating length. Thus, an overall length of the sleeve12and assembly10can be manufactured significantly shorter than prior art sleeves valves and benefiting from commensurate manufacturing and installation cost savings as a result.

In embodiments, the length of the sleeve12can be as short as about 2.5 to about 3 times the axial extent of the ports18, typically the diameter thereof. By way of example, the axial length of the overall sleeve assembly10, including about 5½″ (or API standard 5.563″) diameter housings16, is about 9 inches (about 23 cm) compared to Applicant's prior art, in-sleeve engagement sleeve assemblies, which are from about 26 to about 30 inches (about 66 cm to about 76 cm) in length, or known in-sleeve shifting sleeve assemblies that can be up to many feet long. The illustrated sleeve12, located within the housing bore14, is about 3 inches in length (about 7.6 cm), having 1 inch diameter ports and the sleeve travels axially therein about 2 inches (about 5 cm) between closed and open positions. In other embodiments, the length of the sleeve12can be limited to that needed to cover the axial extent of the circumferential array of ports and having uphole and downhole end that extend or overhang beyond the ports18sufficiently to support the seals30,30. In embodiments, the overhang is about 1″ (2.5 cm).

The sleeve12comprises two or more O-ring seals30, at least two of which are spaced apart on an outer surface32of the sleeve12for positioning at least one O-ring seal30in sealing engagement against the housing16uphole of the one or more ports18and at least one O-ring seal30downhole of the one or more ports18in the closed position. The seals30,30seal between the sleeve12and the tubular housing16and need only be competent to prevent leakage thereby before being opened.

InFIG. 2, in embodiments, in the open position, the sleeve12can be held open using a second retainer34, such as a detent, grapple lock, snap ring, or the like, acting between the sleeve12and the housing16to engage the sleeve12thereto. Not detailed, a grapple hook can reside within an annular recess at the uphole end of the housing bore14. The retainer34need not be releasable, or easily releasable, as the sleeve12is expected to remain open in normal service.

Engagement of the sleeve12by the BHA is generally observed as a weight change at surface. As the BHA is pulled uphole, the uphole pulling force first overcomes the first retainer24for releasing the sleeve12from the housing16. Continued pulling force causes the27sleeve12to shift uphole for opening the plurality of ports18. The uphole end of the sleeve bears against a stop32at the uphole end of the housing bore14and detected at surfaced with an indicated force greater than that of the prior first retainer release force.

Single-Shift Sleeve Assembly as a Casing Coupling

Having reference toFIGS. 3 to 5, the short tubular housing16enables incorporation of the single-shift sleeve assembly in a casing string40as the means for coupling sections of adjacent tubulars in the wellbore and which can replace conventional couplers or collars. Duplication of casing-coupling at the depth of the reservoir zones for treatment, by both collars and sleeve assemblies, is avoided. As a result, the overall cost of the completion string40is lower than would be the case where both casing couplers and added sleeve assemblies10are used.

In embodiments, the housing16of the sleeve assembly10can be designed to be incorporated into a string of casing or other tubulars40having a variety of different coupling configurations, including conventional tubulars having opposing pin and box ends (FIGS. 1 and 2), opposing pin ends (FIG. 3) or external upset casing box ends (FIGS. 4 and 5).

The assembly of the housing16is manufactured so as to enable axial installation of the sleeve12into the housing bore14. The housing16can be two parts17,19to incorporate a first housing portion17having a housing bore14and ports18, the bore14being full diameter at a first end for axial access for initial installation of the sleeve12thereinto and a second housing portion19having a reduced diameter portion14R, or sub, threadably coupled to the first portion17, securing the sleeve12therein. The uphole end of the reduced diameter housing bore14R can form the uphole facing shoulder22or stop for the sleeve shoulder20.

As shown inFIGS. 1 and 2, a conventional pin end can be threaded into an uphole box end of the housing16and a box end can be threaded onto the downhole end of the housing16.

As shown inFIG. 3, in embodiments, a casing tubular40having opposing pin ends can be threaded into uphole and downhole box ends of the sleeve's housing16.

Having reference toFIG. 4, in embodiments for use with external upset box end casing, the downhole end42of the first housing portion17has an internal diameter capable of accommodating the larger outer diameter of the second housing portion19formed by the external upset44on the downhole casing40, when threaded therein. A separate conventional second portion or sub is not required as the first portion17of the housing16is threaded to connect directly to the upset casing. External threads46are machined on an external surface48of the upset portion44for threading into threads50machined in the downhole end42of the first portion of the housing16. An uphole end52of the external upset portion44of the casing40, when threaded into the sleeve housing16, forms the uphole-facing shoulder22upon which the distal end26of the sleeve12rests, acting as the downhole-facing shoulder20. The distal end26of the sleeve12extends radially inwardly into the bore14beyond the downhole casing40for engagement therewith by the shifting tool.

As shown inFIG. 5, in an embodiment, casing40having an external upset44with a thick wall can be machined to form the bore14R and to permit a box end thread to be cut therein for use with conventional casing collars. The additional machining accommodates the sleeve's housing16and forms the uphole facing shoulder22. In this embodiment, instead of the box end thread being cut, pin end threads56are cut on the external surface48of the upset portion44, and material is removed from the inner diameter to form the uphole facing shoulder22. Care is taken in removing the excess material to provide a transition from the upset portion44to the remainder of the casing40to avoid forming a shoulder or protrusion on which tools run through the casing40and sleeve assembly10could engage.

In embodiments, each joint of casing40extending along the treatment portion of the wellbore has pre-assembled thereon a sleeve assembly10configured as a casing coupler, as taught above, eliminating the need to make an additional connection for every joint of casing40during lining of a wellbore, thus saving additional cost.

Apparatus and Methods for Shifting of the Single-Shift Sleeve

Embodiments taught herein are described generally in the context of a BHA having a shifting tool engaging within the sleeve12of a sleeve assembly10. As is well understood in the art, in embodiments used in a multiple-stage fracturing operation, the shifting tool is incorporated into a downhole tool or BHA. The BHA incorporates components used to open the ports18, isolate the wellbore below the open ports, and to deliver fracturing fluid to the formation thereabout. The downhole tool may be referred to in combination as a BHA, or as a BHA incorporating a shifting tool as the context suggests.

BHA with Standard Shifting Tool

As shown inFIG. 6A, a prior art, standard BHA100utilizes sequential up and down J-mechanism cycles for each tool mode. In Applicant's pending application published as US20170058644A1 on Mar. 2, 2017, the entirety of which is incorporated herein by reference, a shifting tool was incorporated in a BHA100using shifting elements such as keys or dogs62intended for use in the engaging within an annular profile formed intermediate prior art sleeves. The BHA100is conveyed downhole on a tubing conveyance string66, such as coiled tubing (CT) or jointed tubulars. The dogs62are located at uphole ends of radially controllable, and circumferentially-spaced, support arms68.

The dogs62of the prior art BHA100locate and engage at an intermediate location65along a sleeve5of the sleeve assembly3. Movement of the dogs62manipulates the shifting of the sleeve5, for either opening or closing. Manipulation of the arms68and dogs62are achieved using uphole and downhole movement of the BHA100and an associated BHA mandrel80. The arm68is fit with cams67for variable control of the radial position of the connected dogs62. A cam-encircling ring forms a restraining ring69axially slidable along the arm's cams67for determining various radially inward and outward shifting options. An alternate form of the restraining ring69is disclosed in Applicant's co-pending US provisional application U.S. 62/619,707, filed Jan. 19, 2018.

In short, the BHA100has a BHA housing90that is frictionally engaged in the casing40by a drag mechanism82. The BHA mandrel80is telescopically movable within the BHA housing90. The BHA mandrel80is connected to the conveyance string66. Movement of the conveyance string66moves the BHA mandrel80and connected J-Pin along a J-Profile71for manipulating the mandrel80axially relative to the housing90and arms68. The housing90and mandrel80are fit with the J mechanism70for changing axial modes.

The J-mechanism70enables arms68and dogs62to be actuable radially inward, overcoming biasing, constrained to a smaller diameter for either downhole run-into-hole (RIH) mode and uphole pull-out-of-hole (POOH) mode movement. Further, the dogs62can be released radially outwardly for locating the sleeve (LOC) mode or locked into engagement with the sleeve or casing including actuating resettable packer74and cone75for blocking the casing annulus41.

With reference also toFIGS. 8A and 13, in embodiments, a J-Profile enables actuation of the BHA100to at least four axial positions. Of the four axial positions, two are extreme positions: one first extreme position downhole D2that drives a cone into engagement with the dogs62to lock the dogs into a located sleeve profile (SET) mode; and one second extreme uphole position U1that first frees the dogs for biased dragging or locating (LOC) mode along the inside wall of the completion string for locating the sleeve profile. The remaining modes are intermediate axial positions (U2, D1), both of which restrain the dogs' radial position to enable free movement uphole (POOH) mode and downhole (RIH) mode within the casing string40respectively.

As shown inFIG. 7, the prior art BHA100would be RIH to a location in the casing40below the sleeve assembly3. The J-mechanism70was cycled by a pull uphole, releasing the arms68axially to LOC mode, the dogs62biased against the casing and dragged uphole to locate the sleeve5. Once located in profile65, the conveyance string66was lowered to SET mode, engaging the packer cone75and dogs62for locking the dogs and sleeve5together, and setting the packer74sealably across the sleeve5for fracturing through the opened sleeve assembly3. An uphole pull released the packer74, separated the cone75from the dogs62and restrained the arms76to the inward position for POOH mode. Continued uphole movement permitted movement of the BHA100to the next sequential sleeve.

However, for the current embodiment, for a short, shift-open sleeve assembly, a packer cannot set across the short sleeve, as the ports would also be covered. Thus, the packer is to be set in the casing40below the sleeve assembly. The prior art J-mechanism sequence can also be implemented for free running in the casing40and setting of the packer74downhole of the sleeve assembly. However, as the prior art J-mechanism sequence moves directly from sleeve LOC to SET mode of the packer, extra repeated cycles would now need to be required so as to manipulate the BHA100below the sleeve assembly before setting the packer to seal the casing40.

Prior Art BHA for Open-Only Sleeves

Turning to the J-Profile71ofFIG. 8Aand the flowchart ofFIG. 8B, the axial position of the BHA mandrel80ofFIG. 6Bto the sleeve ofFIG. 1is controlled by the J-mechanism70of conventional design. Axial positioning of the BHA mandrel80, relative to the cams67on the dog arms68, at least selectively restrains or constrains the dog's radial position for enabling engagement and disengagement of the sleeve12. The J-mechanism70applies at least four distinct positions of the restraining ring69along the arms68so as to positively actuate the dogs62for both uphole and downhole operation, to engage the sleeve12, to lock the dogs to the sleeve12or lock the dogs to the casing40for fracturing operations, and yet also be releasable for longitudinal or axial movement to the next sleeve assembly10.

In summary, the BHA has a J-mechanism comprising at least four axial positions, an intermediate downhole position D1in which the engagement elements are constrained radially inward for free run-in hole (RIH) movement downhole; an extreme uphole position U1in which the engagement elements are biased radially outward for locating (LOC) the housing recess downhole of the sleeve; an extreme downhole position D2for setting (SET) the resettable packer and slip assembly across the completion string; and an intermediate uphole position U2in which the engagement elements are constrained radially inward for free pull-out-of-hole (POOH) movement uphole.

Generally, a method for treating a zone in the formation accessed by the completion string comprises running the BHA100downhole on the conveyance string66, to a location below a selected sleeve assembly10of the plurality of sleeve assemblies. One pulls uphole on the BHA to cycle the dogs of the BHA to the LOC mode and a continued pulling radially engages the dogs62in the annular recess14R in the sleeve housing16. Further pulling uphole on the BHA100engages the sleeve12and dog62and shifts the sleeve uphole to an open position to open the treatment ports18through the sleeve housing. Once open, the BHA is run downhole to cycle the dogs to the RIH mode. The BHA is run downhole to position the resettable packer74and dogs62downhole of the selected sleeve assembly10.

This conventional BHA100requires additional J-mechanism cycles to set the packer and dogs across the completion string and before treating the formation through the opened treatment ports. After treatment; pulling uphole on the BHA100releases the resettable packer and slip assembly and a continued pulling uphole repositions the BHA uphole of the selected sleeve assembly.

In more detail, the BHA mandrel80is initially cycled for run-in-hole RIH mode D1and the BHA100is run downhole to a location in the casing40below the sleeve12. The BHA mandrel80is cycled by pulling uphole to LOC mode U1wherein the arms68and dogs62are released radially outwardly. Pulling up on the conveyance string66drags the dogs62along the casing40until the dogs62locate the increased diameter recess15of the sleeve housing bore14downhole of the sleeve12. The dogs62engage the distal or downhole end26of the sleeve12.

Location of the distal end26of the sleeve12by the dogs62is noted by the operator at surface as an increase in coiled tubing (CT) weight on a CT weight indicator. The operator continues to pull uphole to overcome the first retainer24and the single-shift sleeve12shifts uphole to the open position. The opening of the sleeve12can be verified by continuing to pull uphole with the dog62bearing against the sleeve12and the opened sleeve bearing against an uphole shoulder32of the housing16. The overpull weight is observed on the CT weight indicator at surface. The CT depth is then recorded and is indicative of the location of the distal end of the single-shift sleeve. CT depth is most accurate when the CT is being pulled in tension.

As shown inFIG. 2, once shifted to the open position, the sleeve12is engaged in the open position by the second retainer34which prevents the sleeve12from shifting back to the closed position ofFIG. 1, as discussed above.

All that is required next is to block the wellbore below the sleeve assembly10to treat the formation through the opened ports18. However, the next available J-mechanism sequence is to lower the BHA mandrel80downhole which engages the cone75and dogs62in SET mode for expanding the packer74. Setting the BHA100in this intermediate position is ineffective for the fracturing step as the packer74, at the time of the SET mode, is located uphole of the frac18ports and the dogs62remain located within the sleeve assembly housing16, substantially positioned at the frac ports. Instead, additional cycles are performed to enable repositioning of the packer74of the BHA to a new position below the sleeve assembly before the SET mode is attempted again.

With reference more specifically toFIG. 8A, in one embodiment of operation, this known BHA100and the operating mode of the shifting tool arrangement therein can be implemented to locate, engage, and shift the operating sleeve12uphole and then include further cycles to reset16BHA by running the BHA further downhole to below the opened sleeve12for setting the packer74to the casing string40to seal or block the wellbore and frac through the opened18ports18above the packer. The manipulation of the BHA100through the various modes is performed using a series of up and downhole cycling of the conveyance string66.

To axially move and set the packer74downhole, the BHA100is first cycled downhole by a soft-set of the packer, cone, and dog arrangement, temporarily moving to the SET mode D2merely to cycle the J-mechanism. The BHA100is cycled again to the POOH mode U2to constrain the dogs62and arms68radially inwardly and the BHA is pulled uphole so that the dogs62are repositioned above the sleeve12, typically by a displacement distinguishable at surface, say by a few feet. Next the BHA100is cycled downhole again to RIH mode D1to allow the BHA to be moved axially and freely downhole. The arms and dogs are restrained in the radially inward collapsed position and the BHA100is RIH until the BHA is below the recorded CT tension depth, such as about 10 feet below.

The J-mechanism70is then cycled to POOH mode U2by pulling uphole, after which the BHA is moved to SET mode again by setting down to mode D2to engage the cone and packer with the dogs, setting the dogs in the case40as slips and compressing the packer74to ensure the casing is seated below the sleeve assembly10to isolate the wellbore therebelow.

Following fracturing, the BHA is pulled uphole to POOH mode U2to release the packer74, collapsing the arms68and dogs62for releasing the BHA100which is pulled axially uphole to the next sleeve assembly10in the casing string40. Prior to reaching the next sleeve assembly and still downhole thereof, axial movement of the BHA is stopped and the J-mechanism70is cycled to RIH mode D1to the LOC mode U1. The process as described above is then repeated.

In summary, five additional cycles are employed before the treatment can proceed, namely, running the BHA downhole in RIH mode to cycle the J-mechanism; soft setting the BHA in SET mode to cycle the J-mechanism; pulling the BHA to POOH mode and positioning the BHA above the selected sleeve; running the BHA downhole to below the selected sleeve assembly in RIH mode; pulling the BHA to LOC mode to cycle the J-mechanism; and setting down on the BHA for setting the packer and slips across the completion string in SET mode to seal the casing string below the open sleeve.

Accordingly, while multiple sleeves assemblies10,10. . . can be sequentially opened subjected to fracturing operations the using the prior art shifting tool, the process requires a number of operational steps merely used for cycling the BHA axially uphole and downhole through J-mechanism so as to reposition the BHA below the opened ports18. The additional cycles can also introduce inaccuracy in the settling location of the packer depending upon the accuracy of the determination of the CT tension depth at surface.

Reduced Cycle Shifting Tool

As shown in an alternate embodiment ofFIGS. 9, 10A to 10G, 11andFIGS. 12A through 12E, embodiments of a reduced cycle BHA102are shown having a reduced cycle shifting tool incorporated therein.

The modified BHA102is described in which the number of operating cycles, to shift the sleeve12uphole to open the frac ports18and then move the resettable packer74downhole of the open frac ports for hydraulic fracturing, can be reduced and avoid cycling through the full J-Profile to configure the BHA before setting.

The modified BHA102further comprises a slack sub120for enabling a biased-downhole displacement or repositioning of the shifting tool housing after a uphole manipulation. Unlike conventional J-mechanisms, the BHA102can be shifted from the sleeve opening to reposition downhole of the sleeve assembly10without a need to manipulate the conveyance string66through extra cycles.

The J-mechanism applied with the modified BHA102comprises the previously described and complementary BHA mandrel80and BHA housing90components, one connected to the uphole conveyance string and the other connected to a downhole drag block. Typically the mandrel80is connected to the conveyance string and the housing90connected to the drag block.

Simply, a reduced cycle telescopic BHA102is provided including a repositioning or slack sub situate between the J-mechanism70uphole thereof and the drag block82downhole thereof. The method of using the reduced cycle BHA102comprises energizing the repositioning sub to an extended, energized position upon the shifting of the sleeve12uphole to the open position. To reposition the BHA below the opened sleeve, one runs the BHA102downhole to position the resettable packer74and dog62assembly to a location below the selected sleeve assembly10by setting down on the BHA in SET mode for releasing the energy of the extended repositioning sub by collapsing the repositioning sub and dragging at least the dog portion downhole of the open, selected sleeve assembly10without actuating the resettable packer74. Once the repositioning sub is collapsed, further setting down on the BHA102sets the packer and dogs across the completion string in SET mode.

In detail, the repositioning or slack sub120is situate between the downhole drag beam82and the BHA housing90. The mandrel80is secured to the conveyance string, the surface movement of which is insensitive to the relatively weak axial forces downhole. Uphole movement of the conveyance string66pulls the mandrel80uphole.

The slack sub102acts between a downhole end of the BHA housing90and the drag beam82for biasing the BHA housing downhole from the LOC mode position when released from the sleeve. The BHA housing90is biased downhole to a fracturing location below the sleeve assembly10, wherein the packer74and dogs62are spaced below the distal end of the assembly10.

The slack sub120acts to eliminate the series of extra manipulations ofFIGS. 8A and 8B, that are required when using the prior art shifting tool100to configure the BHA100to move the packer74and the dogs62to a position below the sleeve assembly10.

As shown inFIGS. 11B and 11D, the slack sub120is a telescoping apparatus, having a tubular outer slack housing122and an inner slack mandrel124, the slack mandrel124and a slack annulus126formed therebetween. The slack mandrel124is telescopically and axially moveable into and out of the slack housing122between a collapsed position (FIGS. 9, 8, 11Aand B) and an extended position (FIGS. 10, 11C and 11D) relative to the outer housing122. A drag spring128is positioned annularly about the mandrel124in the slack annulus126and is retained thereabout within the slack housing122. The drag spring128acts to bias the slack mandrel124back for retraction into the slack housing122to the collapsed position.

An uphole sub134of the slack housing122forms a downward facing shoulder as an uphole spring stop130and a downhole sub136for connection with the drag beam82assembly. The slack mandrel124further comprises a top sub140for connection with the downhole end of the BHA housing90. The downhole end of the slack mandrel124further comprises an adjustable spring retention nut142adjacent a distal end thereof and forming a downhole spring stop132for engaging the distal end of the drag spring128. As the slack mandrel extends out of the slack housing, the drag spring128is compressed between stop130and stop132. The uphole sub134has a bore135through which the slack mandrel124slidably passes. The drag spring128is compressed between the uphole spring stop130and the downhole stop132of the adjustable spring retention nut142. The adjustable spring retention nut142and can be variably positioned and retained axially along the slack mandrel to pre-establish variable tension in the drag spring128and a distance of travel of the BHA120connected thereto.

Slack mandrel124has an uphole end140that is connected to the downhole of the BHA housing90, typically to the bottom of the J-housing70, and a downhole end136of the slack housing122is connected to the drag beam assembly82.

In use, the slack sub120adopts the collapsed position when the BHA is being run-in-hole (RIH) and during fracing in SET mode. When the BHA102is pulled uphole, such as to locate or to shift the sleeve12of the sleeve assembly10, the drag beam assembly82provides sufficient frictional restraining drag force to retain the position of the slack housing122axially within the casing40while the slack mandrel124is pulled axially uphole with the BHA102. The downhole retention nut142of the slack mandrel124approaches the uphole stop130of the slack housing122as the slack mandrel124moves to the extended position. The slack spring128is compressed to an energized position.

As shown inFIGS. 12C and 14A, when the dogs62are released from the sleeve assembly10, the energy of the drag spring128pulls downhole on the BHA housing90. InFIG. 14B, the BHA housing90, at least the arms68and dogs62are dragged downhole, spacing the dogs62from the cone75carried by the BHA mandrel80.

The setting down of the BHA releases the energy of the extended slack sub120, biasing the J-mechanism housing90and dogs62downhole towards the drag block82while the J-mechanism mandrel follows downhole, the BHA repositioning below the open, selected sleeve10. The slack mandrel124telescopically extends from the slack housing122by a stroke length, the stroke length being greater than the distance between the spacing between the dogs and the packer74in the cone-engaged position and wherein upon the dogs10disengaging from the sleeve assembly10, the slack mandrel124telescopically drags the BHA housing90downhole and the packer74is dragged downhole of the sleeve assembly10.

As shown inFIGS. 12D and 14C, the axial magnitude of the collapsing slack sub120is such that, when the BHA housing90is biased downhole by the drag spring128, the dogs62are positioned below the sleeve assembly10when the BHA mandrel, packer74and cone75engage the dogs62in SET mode and anchor the dogs in the casing40therebelow.

In embodiments, there is sufficient spacing between the slack housing and the slack mandrel so as to minimize adverse effects of sand and debris therein on the axial movement of the BHA housing90relative to the casing40. Further, the tubular components can be perforated therethrough to assist with sand and debris removal there between.

In embodiments the slack mandrel's extended position is defined by the length of the mandrel124and the positioning of the adjustable spring retention nut142thereto.

In embodiments, the slack sub is incorporated into the drag beam assembly and is not a separate component, which acts to shorten the length of the BHA.

Method of Shifting a Uphole-Opening Sleeve

Having reference again toFIGS. 11A to 11G, 12A to 12E and 13, sleeve12is shifted uphole to the open position, using Applicant's BHA102. As shown inFIG. 11A, in RIH mode, the BHA's packer74is relaxed and the slack sub-120is initially in the collapsed position all of which is RIH to a depth below the sleeve assembly10. As shown inFIG. 11C, the J-mechanism70is cycled to the LOC Mode as described above and the BHA102is pulled uphole until the radially extending dogs62on the arms note the sleeve housing bore14and engage the distal end of the sleeve12. As shown inFIG. 11D, the BHA102is pulled uphole to locate the distal end26of the sleeve12. During uphole movements, the frictional force of the drag beam82on the casing14exceeds that of the force to compress drag spring128, and slack mandrel124telescopes axially from the slack housing122to the extended position.

As shown inFIG. 11E, continuing to pull the BHA102uphole with the dogs62engaged with the distal end of the single-shift sleeve overcomes the first retainer28, and the sleeve12is shifted uphole to open the ports18. The packer74is currently located uphole of the frac ports18and the dogs62are positioned at about the frac ports. The slack sub-120remains engaged in the extended position (FIG. 11D).

Thereafter, as shown inFIG. 11F, the J-mechanism70is cycled towards a SET/FRAC mode, which releases the dogs62and allows the drag spring128to drag the slack mandrel124downhole towards collapsed position (FIG. 11B). The BHA housing90attached to the slack mandrel124is also dragged downhole to below the sleeve assembly10and BHA mandrel, packer74and cone75thereon can follow without actuation.

The effect of slack sub is not necessarily limited by the BHA housing90. InFIGS. 17A and 17B, the BHA can be fit with a fracturing fluid valve250uphole of the packer74. The valve250is telescopic, having an inner tubular valve stem252and an outer tubular valve sleeve254. The inner valve stem252is connected to the conveyance string66at an uphole end and has a downhole plug256. The outer valve sleeve254is connected at a downhole end to the BHA mandrel80. When the valve stem252is actuated downhole, the plug256blocks the bore of the BHA mandrel80and side fluid apertures262,264in both the valve stem252and sleeve254respectively align for fracturing fluid egress. When the valve stem252is actuated uphole, upon an upward pull of the conveyance string66, plug256pulls opens from the BHA mandrel80and the side fluid apertures262,264misalign for blocking fracturing fluid flow from the conveyance string66and valve stem aperture262. The action of the slack sub120can, depending on the relative uphole downhole relationship of the conveyance string66and BHA102, also drag the valve sleeve254portion downhole. Firstly, as BHA housing90is pulled downhole, the uphole J-Profile is lowered over the uphole J-Pin of the BHA mandrel80. Once the J-Pin is engaged, by one of the U1or U2J-Profile positions, the BHA mandrel80, packer74and cone75can also be dragged downhole therewith, maintaining a spaced, but close relationship with the BHA housing80.

Once the slack sub120is fully in the collapsed position and there is no further downward movement of the BHA housing90, the packer, cone and dogs are set in the casing below the sleeve assembly10for fracturing through the open ports18.

As shown inFIG. 11G, following fracturing, the J-mechanism70is cycled to the POOH mode, the packer74is again relaxed and the arms and dogs are constrained radially inwardly. The BHA102is then pulled uphole toward the next sleeve assembly10to be opened, the slack mandrel124once again moving axially, within the slack housing122, to the extended position.

As with the prior BHA100ofFIG. 6A, prior to reaching the next sleeve assembly10, axial uphole movement is stopped, and the J-mechanism70is cycled to the LOC Mode so that, when pulled further uphole, the next sleeve assembly10to be opened can be positively located by the dogs62and the process as described above repeated for shifting the sleeve and fracturing through the open ports.

Low Friction Roller Sub

As shown inFIG. 6B, centralizers91can be provided to reduce friction between the BHA102and the casing40, the centralizer generally being manufactured from low friction materials, such as polyurethane. The centralizer can enable the slack sub120to more effectively drag the BHA downhole as described above.

In other embodiment, and having reference toFIGS. 14A, 14B and 14C, in situations where there are significant amounts of sand or debris in the wellbore, or where there are other concerns with respect to resistance to the ability of the slack sub to reciprocate between the retracted and extended positions and reliably drag the BHA housing90to the collapsed position, the BHA may further comprise a roller sub150. Centralizers and rollers are also known in the centralizing of reciprocating rod strings.

In embodiments, the roller sub150comprises a tubular housing having a plurality of low-friction surfaces152extending radially outwardly therefrom, such as pads, roller wheels or the like, to engage the casing and to reduce the effect of friction on downhole axial movement of the BHA therein when dragged by the slack sub.

As shown, in embodiments the roller sub is incorporated into the BHA housing90such as between the arms68and the J-mechanism70.

In embodiments, where there may be significant initial impediments to spring-induced dragging movement of the BHA housing, or where there are other concerns regarding the ability of the slack sub to reliably drag the BHA downhole, the BHA may further comprise a positive energy source to aid the BHA. A nudge sub160may be used in instead of the roller sub150, or alternatively can be used in combination therewith, to induce initial movement of the slack sub's housing122and BHA housing90.

In embodiments, the nudge sub160acts to provide a momentary downhole force on the slack sub's housing122to initiate downhole movement so as to aid the slack sub to drag the BHA housing90downhole.

Having reference toFIGS. 15 and 16, the nudge sub160comprises a tubular nudge housing162having a bore164therethrough. The nudge housing162is connected to the slack mandrel124of the slack sub120therebelow. A nudge mandrel166extends sealably, through seals167, through an uphole end168of the housing162and is axially moveable along the bore164. The nudge mandrel166is connected to the BHA mandrel80thereabove which, when cycled downhole to RIH mode, also drives the nudge mandrel166downhole into the nudge bore164. A downhole end184of the nudge sub housing162is connected to the slack mandrel124of the slack sub120. The nudge mandrel162momentarily drives the nudge housing164downhole so as to drive the slack mandrel124to move axially downhole against debris-related annular resistance.

Adjacent an uphole end of the bore164is a circular constriction170, dividing the bore into an uphole chamber172and a main chamber174downhole thereof. The upper chamber172receives a distal end of the nudge mandrel166therein. The uphole and main chambers172,174are fluidly connected. The nudge bore164is filled with an incompressible fluid, such as oil.

The distal end of the nudge mandrel166fit with a cylindrical nudge piston180thereon. The diameter of the nudge piston180is sized to pass axially through the circular constriction. The first constriction170is spaced downhole from the nudge housing's uphole end168and forms the upper chamber172therebetween. The constriction170has a diameter slightly larger than that of the piston180as shown inFIG. 16, such that when the nudge piston180passes through the constriction170, there is a hydraulic resistance to the passage of the piston therethrough. The axial extent or length of the constriction172is relatively short compared to the travel of the nudge mandrel166so as to provide a fluid connection for a limited duration with the slack mandrel124so as to initiate movement thereof as described below. Once the nudge piston180passes through the constriction170, the downhole movement of the BHA mandrel80and connected nudge mandrel166is effectively disconnected from the slack sub120.

During the passage of the piston through the constrictor170, oil is fluidly displaced from the main chamber174to flow into a lower chamber176. The oil in main chamber174is moved between the main and lower chamber174,176as the nudge mandrel166moves axially uphole and downhole. The lower chamber is merely a housing for the axial movement and retention of a compensator piston186moveable with the volume of displaced fluid.

The compensator piston186is located axially within the lower chamber176between an uphole stop182and the downhole sub184, moving in response to displacement of oil as the nudge mandrel166moves axially within the bore164. The compensator piston186is in fluid communication on the uphole side with the clean oil in the housing and is in fluid communication with the dirty wellbore fluid on the downhole side. The compensator piston186ensures that the pressure of the oil in the nudge sub160is balanced with the wellbore pressure, which varies with wellbore depth, while accommodating the movement of oil in the bore164. Balancing the pressure in the bore164with the wellbore fluids of the casing string40ensure the mandrel seals167are not subjected to a high, different pressure.

Further, as shown inFIG. 15, the nudge piston180has a check valve190therein, such as flapper valve, to enable substantially free uphole movement of the nudge mandrel166and nudge piston180thereon and displacement of fluid from the uphole chamber172, such as when the BHA is pulled uphole (POOH) and the nudge piston180resets by passing uphole through the constrictor170.

As can be seen inFIG. 15, wherein the nudge sub160is shown juxtaposed with J-profile ofFIG. 13, the location of the constriction170is coordinated axially, within the nudge housing162, with respect to the cycling of the J-mechanism. The constriction170is spaced along the nudge sub160so to coordinate the timing of the push or nudge, applied by the nudge housing162to the slack mandrel124, with release of the dogs62and the dragging action of the slack mandrel124intermediate the BHA cycle to the SET mode at D2of the J-Profile. In embodiments, the nudge piston180reaches the constriction170as the arms and dogs62of the BHA are being constrained radially inwardly at U2of the J-Profile so as to allow free axial movement of the BHA downhole within the wellbore.

In use, when the J-mechanism70is cycled to SET mode, the BHA mandrel80, the nudge mandrel166, and the nudge piston180are permitted to move freely downhole until the piston reaches the constriction170. A momentary hydraulic restriction is formed thereat, which effectively acts to momentarily lock or couple the nudge piston180to the nudge housing162. The coupled movement of the nudge housing162causes a forceful downhole movement of the slack sub's mandrel124towards the collapsed position, breaking a stuck BHA housing90free of the casing string and permitting the energy of the compressed spring128to take over to drag the BHA housing90downhole therewith.

In embodiments, the nudge sub160may assist in initiating movement from a static friction mode to a dynamic friction mode such that the slack mandrel124and spring168can maintain dragging movement under the lower dynamic friction conditions.