Patent Publication Number: US-2022228452-A1

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

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of U.S. patent application Ser. No. 16/515,881, filed Jul. 18, 2019, which claims priority to U.S. Provisional Patent Application No. 62,702,200, filed Jul. 23, 2018, the entirety of each of which are incorporated fully herein by reference. 
    
    
     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&#39;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&#39;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&#39;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 D 1  in which the engagement elements are constrained radially inward for free run-in hole (RIH) movement downhole; an extreme uphole position U 1  in which the engagement elements are biased radially outward for locating (LOC) the housing recess downhole of the sleeve; an extreme downhole position D 2  for setting (SET) the resettable packer and slip assembly across the completion string; and an intermediate uphole position U 2  in 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&#39;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&#39;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. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a cross-sectional view of a single-shift sleeve assembly of a tubular housing and a sleeve therein, according to an embodiment taught herein, the sleeve shown in a downhole closed position for blocking the flow of fluids through a plurality of ports in the tubular housing; 
         FIG. 2  is a cross-section view of the single-shift sleeve, according to  FIG. 1 , shown with the sleeve shown in the axial uphole open position for unblocking flow of fluids to the plurality of ports; 
         FIG. 3  is a cross-sectional view of an embodiment of the single-shift sleeve assembly with a sectional housing configured as a casing coupler between pin-end joints of conventional casing, an annular shifting recess formed in the housing and located adjacent a downhole end of the sleeve in the closed position; 
         FIG. 4  is a cross-sectional view of an embodiment of the single-shift sleeve assembly with an alternate unitary structural embodiment of the assembly housing used as a casing coupler for jointed casing, the downhole casing having external upset casing compatible with the unitary housing structure and forming the shifting recess therein; 
         FIG. 5  is a cross-sectional view of an embodiment of the single-shift sleeve assembly with an alternate unitary structural embodiment of the assembly housing of  FIG. 4 , the upset casing having the inner diameter of the uphole end machined radially to enlarge the bore greater than that of the sleeve&#39;s bore for forming the shifting recess for receiving shifting elements of shifting tool and functional access to the sleeve&#39;s downhole shifting shoulder; 
         FIG. 6A  is a schematic cross-sectional view of Applicant&#39;s prior art BHA published as US20170058644A1; 
         FIG. 6B  is a cross-sectional view of the shift tool portion of Applicant&#39;s prior art BHA according to  FIG. 6A , and having recess-engaging elements or dogs controlled through cycling of a J-mechanism; 
         FIG. 7  is a flowchart outlining the steps of shifting a prior art sleeve using a BHA fit with the prior art J-mechanism equipped shifting tool of  FIG. 6A  to engage the prior art sleeve&#39;s internal profile or recess and enable shifting of the functions of the sleeve; 
         FIG. 8A  is a rolled-out illustration of a J-mechanism J-Profile, having extreme and intermediate uphole stops and extreme and intermediate downhole stops, being manipulated through two cycles used to open the single shift shifting sleeve and then reposition the prior art BHA of  FIG. 6A  below the sleeve assembly for treatment before moving to the next sleeve uphole, the functional cycles bolded in outline; 
         FIG. 8B  is a flowchart outlining the steps for operation of the prior art shifting tool of  FIGS. 6A, 6B  and cycling the J-mechanism for locating an open-only sleeve of  FIGS. 1, 2 , shifting the sleeve, treating the formation through the selected sleeve and re-locating to the next sleeve; 
         FIG. 9  is a cross-sectional view of a low-cycle alternative embodiment of a single shift BHA and shifting tool further incorporating a telescopic repositioning sub, or slack sub for reducing J-mechanism cycles and repositioning the BHA&#39;s packer and slip assembly, after opening the sleeve for fracturing according to embodiments taught herein, the slack sub being situate between the J-mechanism and the drag block, the slack sub shown in the collapsed position; 
         FIG. 10  is a cross-sectional view of the reduced cycle BHA embodiment according to  FIG. 9 , the slack sub shown in the extended position; 
         FIGS. 11A to 11G  are cross-sectional representations of components of the single-shift BHA of  FIGS. 9 and 10 , according to embodiments taught herein, and more particularly, 
         FIG. 11A  illustrates the uphole end of the single shift BHA with a releasable sealing element, and a J-shifting mechanism comprising arms and sleeve engagement elements or dogs thereon, the dogs shown in a collapsed position to permit running into hole (RIH) such as casing; 
         FIG. 11B  illustrates the slack sub in isolation, having a slack housing and having a slack mandrel for coupling with the BHA J-mechanism, the slack sub shown in an axially-collapsed position with the drag spring situate between the slack mandrel and housing in the extended, relaxed position presented during run-in-hole (RIH), and set (SET) for fracturing; 
         FIG. 11C  illustrates the BHA in a pull-to-locate (LOC) mode having the arms and dogs biased radially outwardly to ride along the bore of the casing string and shown having located a sleeve housing recess downhole of the sleeve; and 
         FIG. 11D  illustrates the slack sub in an extended position with the slack mandrel telescopically extended from the slack housing and the drag spring energized or compressed therebetween, such as during LOC and POOH modes; 
         FIG. 11E  illustrates the engagement dogs having engaged the sleeve housing recess having been pulled uphole to the open position, the slack sub now extended and the spring energized according to  FIG. 11D ; 
         FIG. 11F  illustrates the dogs having been dragged downhole from the sleeve assembly, the energized slack mandrel having dragged the J-housing arms and associated dogs downhole towards the drag block, the slack sub moving from the extended position to the collapsed position and auto-cycling the J-mechanism from pull to open LOC to SET modes for setting the dogs in the casing string and compressing the packer element in the casing string below the sleeve assembly; and 
         FIG. 11G  illustrates the reduced cycle BHA, subsequently cycled uphole to retract the arms and dogs for pulling-out-of-hole (POOH), the packer having been relaxed, the slack mandrel being pulled uphole, and moving again to the extended position, compressing the drag spring; 
         FIGS. 12A through 12E  respectively are cross-sectional side views of the BHA with shifting tool and slack sub in various stages of operation, the view diameter being exaggerated for better illustrating the cross-sectional elements; 
         FIG. 12A  illustrates the BHA while RIH just downhole of the closed sleeve assembly; 
         FIG. 12B  illustrates the BHA while LOC, the dogs engaging the downhole end of the sleeve; 
         FIG. 12C  illustrates the BHA with the sleeve pulled uphole to open and the slack sub fully energized; 
         FIG. 12D  illustrates the slack sub collapsed, shown having drawn the dogs downhole from the sleeve and still spaced from the resettable packer assembly; 
         FIG. 12E  illustrates the BHA while in POOH mode with the BHA uphole of the selected sleeve for repositioning at the next sleeve or tripping out of the wellbore; 
         FIG. 12F , shown side by side with  FIGS. 7 and 8B , is a flowchart outlining the reduced number of cycles for shifting the sleeve according to embodiments taught herein utilizing the BHA of  FIGS. 9-12E ; 
         FIG. 13  is a rolled-out illustration of a J-mechanism profile, having extreme and intermediate uphole stops and extreme and intermediate downhole stops, for use with the reduced cycle BHA of  FIGS. 11A to 11G ; 
         FIGS. 14A, 14B and 14C  are diagrammatic illustrations of embodiments the BHA of  FIGS. 11A to 11G  further incorporating a roller sub to aid in downhole axial movement of the shifting tool portion of the BHA when the slack sub collapses from the extended position ( FIG. 14A ) to the collapsed position ( FIG. 14B ) and after the conveyance string follows the dogs downhole to engage and set the dogs as slips in the casing string ( FIG. 14C ); 
         FIG. 15  is a cross-sectional schematic view of a hydraulic nudge sub for incorporation into the BHA according to embodiments taught herein, the nudge sub assisting with initiation of axial movement of the slack sub from the extended position to the collapsed position and shown in relation to a J-profile according to  FIG. 13 , to illustrate timing of the nudge sub; 
         FIG. 16  is a cross-sectional view of the nudge sub of  FIG. 15 , the nudge mandrel shown connected to the distal or bottom end of the J-mandrel and having a nudge housing cemented between the downhole end of the J-housing and the slack mandrel and shown at a stage when the nudge mandrel is passing through a constriction for hydraulically nudging the mandrel of the slack sub connected therebelow; and 
         FIGS. 17A and 17B  are cross-sectional, diameters exaggerated views of a slidable aperture fracturing valve above the BHA mandrel&#39;s resettable packer assembly, the BHA mandrel and lower valve sleeve portion ultimately also being axially movable relative to the conveyance string and upper valve stem portion, uphole thereof, draggable with the BHA housing once the BHA mandrel uphole J-Pins engaged one of the U 1  or U 2  positions of the uphole J-Profile as the BHA housing moves downhole thereabout. 
     
    
    
     DETAILED DESCRIPTION 
     Having reference to  FIGS. 1 and 2 , embodiments taught herein comprise a single-shift sleeve assembly  10 , wherein a tubular sleeve  12  is axially shiftable within a bore  14  of a tubular housing  16 . The housing  16  is installed, such as by threaded connections, between facing ends of adjacent tubulars in a tubular string along the wellbore, typically a completion or casing string  40 . 
     At least some of the tubulars in the string, such as those in the formation of interest, are connected by sleeve assemblies  10  for selectable fluid communication from the tubular string to the formation. The sleeve  12  is fit slidably to the housing bore  16  and has a sleeve bore  13 , the sleeve  12  being 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 housing  16  and are openable and closeable to the formation. 
     The sleeve  12  is initially in a closed position ( FIG. 1 ), aligned axially in the housing  16  for blocking flow through one or more ports  18  located and distributed circumferentially about in the housing  16  at an axial port location along the housing  16  and formed therethrough. The ports have an axial extent, typically circular, that determines the minimum length of the sleeve  12 . 
     For fluid communication between the tubular bore  14  and the wellbore outside of the tubular  16 , the sleeve  12  is shifted uphole to an open position ( FIG. 2 ) to axially expose the ports  18  and 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 in  FIG. 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 to  FIG. 1 , in the initial closed position, the open uphole sleeve  12  is a tubular, slidably fit to the housing bore  14 , and having a bore  13  smaller than that of the housing bore  14 . An annular recess  14 R formed in the housing bore  14  downhole of the sleeve  12  and has a diameter greater than that of the sleeve&#39;s bore  13 . The sleeve bore  13  has a diameter at or larger than a string bore diameter of the tubular string for passage of BHA therethrough. The annular recess  14 R has a diameter larger than that of the sleeve bore  13  resulting in a downhole engagement shoulder extending radially from the sleeve  12  into the housing bore  14 , forming a downhole-facing shoulder  20  at a distal end  26  thereof. 
     The housing bore  14  has an uphole-facing stop  22  formed therein and the ports  18  are spaced uphole therefrom. A closed sleeve bears axially against the uphole-facing stop in the closed position to block the ports  18  uphole thereof, and the sleeve&#39;s downhole engagement shoulder  20  extends radially into the housing bore at the uphole-facing stop. 
     Closed, the sleeve&#39;s shoulder  20  rests against the uphole facing stop  22  formed at a localized narrowing of the bore  14  of the tubular housing  16  downhole of the sleeve  12 . A pair of seals  30 , 30 , situate in the annulus between the housing bore  14  and the sleeve  12 , axially straddle the ports  18  to minimize fluid leaks therethrough and provide pressure integrity when closed. 
     The sleeve  12  has an uphole end  27 , the downhole end  20 , and an axial length therebetween, the sleeve length accommodating at least an uphole annular seal  30  in the sleeve annulus to seal the blocked ports  18  along 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 ports  18  have an axial extent and the sleeve  12  has a sleeve length between about 2.5 and about 3 times the axial extent of the ports. 
     The sleeve  12  can be temporarily retained in the downhole closed position using a first retainer  24 , such as a detent or shear screw acting between the housing  16  and the sleeve  12 . The sleeve&#39;s downhole-facing shoulder  20  bears against the uphole-facing stop  22  to mitigate against accidental movement of the sleeve  12  when a BHA, or other tool is run-in-hole (RIH) through the sleeve assembly bore  14 . Further, the first retainer  24  can 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 retainer  24  can 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 sleeve  12 . 
     In embodiments taught herein, the downhole-facing shoulder  20  of the sleeve  12  extends radially inwardly from the housing bore  14 . Described in greater detail below, the BHA and integrated shifting tool, having radially extending sleeve engaging elements, can be pulled uphole into the housing  16  to traverse the housing bore  14 . The engaging elements engage a recess  15  formed by the radial difference between the housing bore  14  and the sleeve bore  13 . The recess  15  is formed downhole of the sleeve  12  at the downhole-facing shoulder  20 . An additional uphole force on the elements overcomes the first retainer  24  to shift the sleeve  12  uphole. 
     With reference to  FIG. 2 , after the sleeve  12  is pulled uphole, the exposed ports  18  are open between the tubular bore  14  and the wellbore outside of the tubular  16 . 
     Best seen in  FIG. 2 , the first retainer  24  can be cooperating collet and annular rings, the tubular collet having flexible fingers  29  extending uphole from the housing  16  and the sleeve  12  which bears complementary annular rings  27  upstanding radially between the housing  16  and sleeve  12 . 
     The sleeve  12  is 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 sleeve  12  and assembly  10  can 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 sleeve  12  can be as short as about 2.5 to about 3 times the axial extent of the ports  18 , typically the diameter thereof. By way of example, the axial length of the overall sleeve assembly  10 , including about 5½″ (or API standard 5.563″) diameter housings  16 , is about 9 inches (about 23 cm) compared to Applicant&#39;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 sleeve  12 , located within the housing bore  14 , 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 sleeve  12  can 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 ports  18  sufficiently to support the seals  30 , 30 . In embodiments, the overhang is about 1″ (2.5 cm). 
     The sleeve  12  comprises two or more O-ring seals  30 , at least two of which are spaced apart on an outer surface  32  of the sleeve  12  for positioning at least one O-ring seal  30  in sealing engagement against the housing  16  uphole of the one or more ports  18  and at least one O-ring seal  30  downhole of the one or more ports  18  in the closed position. The seals  30 , 30  seal between the sleeve  12  and the tubular housing  16  and need only be competent to prevent leakage thereby before being opened. 
     In  FIG. 2 , in embodiments, in the open position, the sleeve  12  can be held open using a second retainer  34 , such as a detent, grapple lock, snap ring, or the like, acting between the sleeve  12  and the housing  16  to engage the sleeve  12  thereto. Not detailed, a grapple hook can reside within an annular recess at the uphole end of the housing bore  14 . The retainer  34  need not be releasable, or easily releasable, as the sleeve  12  is expected to remain open in normal service. 
     Engagement of the sleeve  12  by 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 retainer  24  for releasing the sleeve  12  from the housing  16 . Continued pulling force causes the  27  sleeve  12  to shift uphole for opening the plurality of ports  18 . The uphole end of the sleeve bears against a stop  32  at the uphole end of the housing bore  14  and 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 to  FIGS. 3 to 5 , the short tubular housing  16  enables incorporation of the single-shift sleeve assembly in a casing string  40  as 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 string  40  is lower than would be the case where both casing couplers and added sleeve assemblies  10  are used. 
     In embodiments, the housing  16  of the sleeve assembly  10  can be designed to be incorporated into a string of casing or other tubulars  40  having 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 housing  16  is manufactured so as to enable axial installation of the sleeve  12  into the housing bore  14 . The housing  16  can be two parts  17 ,  19  to incorporate a first housing portion  17  having a housing bore  14  and ports  18 , the bore  14  being full diameter at a first end for axial access for initial installation of the sleeve  12  thereinto and a second housing portion  19  having a reduced diameter portion  14 R, or sub, threadably coupled to the first portion  17 , securing the sleeve  12  therein. The uphole end of the reduced diameter housing bore  14 R can form the uphole facing shoulder  22  or stop for the sleeve shoulder  20 . 
     As shown in  FIGS. 1 and 2 , a conventional pin end can be threaded into an uphole box end of the housing  16  and a box end can be threaded onto the downhole end of the housing  16 . 
     As shown in  FIG. 3 , in embodiments, a casing tubular  40  having opposing pin ends can be threaded into uphole and downhole box ends of the sleeve&#39;s housing  16 . 
     Having reference to  FIG. 4 , in embodiments for use with external upset box end casing, the downhole end  42  of the first housing portion  17  has an internal diameter capable of accommodating the larger outer diameter of the second housing portion  19  formed by the external upset  44  on the downhole casing  40 , when threaded therein. A separate conventional second portion or sub is not required as the first portion  17  of the housing  16  is threaded to connect directly to the upset casing. External threads  46  are machined on an external surface  48  of the upset portion  44  for threading into threads  50  machined in the downhole end  42  of the first portion of the housing  16 . An uphole end  52  of the external upset portion  44  of the casing  40 , when threaded into the sleeve housing  16 , forms the uphole-facing shoulder  22  upon which the distal end  26  of the sleeve  12  rests, acting as the downhole-facing shoulder  20 . The distal end  26  of the sleeve  12  extends radially inwardly into the bore  14  beyond the downhole casing  40  for engagement therewith by the shifting tool. 
     As shown in  FIG. 5 , in an embodiment, casing  40  having an external upset  44  with a thick wall can be machined to form the bore  14 R and to permit a box end thread to be cut therein for use with conventional casing collars. The additional machining accommodates the sleeve&#39;s housing  16  and forms the uphole facing shoulder  22 . In this embodiment, instead of the box end thread being cut, pin end threads  56  are cut on the external surface  48  of the upset portion  44 , and material is removed from the inner diameter to form the uphole facing shoulder  22 . Care is taken in removing the excess material to provide a transition from the upset portion  44  to the remainder of the casing  40  to avoid forming a shoulder or protrusion on which tools run through the casing  40  and sleeve assembly  10  could engage. 
     In embodiments, each joint of casing  40  extending along the treatment portion of the wellbore has pre-assembled thereon a sleeve assembly  10  configured as a casing coupler, as taught above, eliminating the need to make an additional connection for every joint of casing  40  during 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 sleeve  12  of a sleeve assembly  10 . 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 ports  18 , 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 in  FIG. 6A , a prior art, standard BHA  100  utilizes sequential up and down J-mechanism cycles for each tool mode. In Applicant&#39;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 BHA  100  using shifting elements such as keys or dogs  62  intended for use in the engaging within an annular profile formed intermediate prior art sleeves. The BHA  100  is conveyed downhole on a tubing conveyance string  66 , such as coiled tubing (CT) or jointed tubulars. The dogs  62  are located at uphole ends of radially controllable, and circumferentially-spaced, support arms  68 . 
     The dogs  62  of the prior art BHA  100  locate and engage at an intermediate location  65  along a sleeve  5  of the sleeve assembly  3 . Movement of the dogs  62  manipulates the shifting of the sleeve  5 , for either opening or closing. Manipulation of the arms  68  and dogs  62  are achieved using uphole and downhole movement of the BHA  100  and an associated BHA mandrel  80 . The arm  68  is fit with cams  67  for variable control of the radial position of the connected dogs  62 . A cam-encircling ring forms a restraining ring  69  axially slidable along the arm&#39;s cams  67  for determining various radially inward and outward shifting options. An alternate form of the restraining ring  69  is disclosed in Applicant&#39;s co-pending US provisional application U.S. 62/619,707, filed Jan. 19, 2018. 
     In short, the BHA  100  has a BHA housing  90  that is frictionally engaged in the casing  40  by a drag mechanism  82 . The BHA mandrel  80  is telescopically movable within the BHA housing  90 . The BHA mandrel  80  is connected to the conveyance string  66 . Movement of the conveyance string  66  moves the BHA mandrel  80  and connected J-Pin along a J-Profile  71  for manipulating the mandrel  80  axially relative to the housing  90  and arms  68 . The housing  90  and mandrel  80  are fit with the J mechanism  70  for changing axial modes. 
     The J-mechanism  70  enables arms  68  and dogs  62  to 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 dogs  62  can be released radially outwardly for locating the sleeve (LOC) mode or locked into engagement with the sleeve or casing including actuating resettable packer  74  and cone  75  for blocking the casing annulus  41 . 
     With reference also to  FIGS. 8A and 13 , in embodiments, a J-Profile enables actuation of the BHA  100  to at least four axial positions. Of the four axial positions, two are extreme positions: one first extreme position downhole D 2  that drives a cone into engagement with the dogs  62  to lock the dogs into a located sleeve profile (SET) mode; and one second extreme uphole position U 1  that 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 (U 2 , D 1 ), both of which restrain the dogs&#39; radial position to enable free movement uphole (POOH) mode and downhole (RIH) mode within the casing string  40  respectively. 
     As shown in  FIG. 7 , the prior art BHA  100  would be RIH to a location in the casing  40  below the sleeve assembly  3 . The J-mechanism  70  was cycled by a pull uphole, releasing the arms  68  axially to LOC mode, the dogs  62  biased against the casing and dragged uphole to locate the sleeve  5 . Once located in profile  65 , the conveyance string  66  was lowered to SET mode, engaging the packer cone  75  and dogs  62  for locking the dogs and sleeve  5  together, and setting the packer  74  sealably across the sleeve  5  for fracturing through the opened sleeve assembly  3 . An uphole pull released the packer  74 , separated the cone  75  from the dogs  62  and restrained the arms  76  to the inward position for POOH mode. Continued uphole movement permitted movement of the BHA  100  to 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 casing  40  below the sleeve assembly. The prior art J-mechanism sequence can also be implemented for free running in the casing  40  and setting of the packer  74  downhole 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 BHA  100  below the sleeve assembly before setting the packer to seal the casing  40 . 
     Prior Art BHA for Open-Only Sleeves 
     Turning to the J-Profile  71  of  FIG. 8A  and the flowchart of  FIG. 8B , the axial position of the BHA mandrel  80  of  FIG. 6B  to the sleeve of  FIG. 1  is controlled by the J-mechanism  70  of conventional design. Axial positioning of the BHA mandrel  80 , relative to the cams  67  on the dog arms  68 , at least selectively restrains or constrains the dog&#39;s radial position for enabling engagement and disengagement of the sleeve  12 . The J-mechanism  70  applies at least four distinct positions of the restraining ring  69  along the arms  68  so as to positively actuate the dogs  62  for both uphole and downhole operation, to engage the sleeve  12 , to lock the dogs to the sleeve  12  or lock the dogs to the casing  40  for fracturing operations, and yet also be releasable for longitudinal or axial movement to the next sleeve assembly  10 . 
     In summary, the BHA has a J-mechanism comprising at least four axial positions, an intermediate downhole position D 1  in which the engagement elements are constrained radially inward for free run-in hole (RIH) movement downhole; an extreme uphole position U 1  in which the engagement elements are biased radially outward for locating (LOC) the housing recess downhole of the sleeve; an extreme downhole position D 2  for setting (SET) the resettable packer and slip assembly across the completion string; and an intermediate uphole position U 2  in 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 BHA  100  downhole on the conveyance string  66 , to a location below a selected sleeve assembly  10  of 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 dogs  62  in the annular recess  14 R in the sleeve housing  16 . Further pulling uphole on the BHA  100  engages the sleeve  12  and dog  62  and shifts the sleeve uphole to an open position to open the treatment ports  18  through 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 packer  74  and dogs  62  downhole of the selected sleeve assembly  10 . 
     This conventional BHA  100  requires 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 BHA  100  releases 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 mandrel  80  is initially cycled for run-in-hole RIH mode D 1  and the BHA  100  is run downhole to a location in the casing  40  below the sleeve  12 . The BHA mandrel  80  is cycled by pulling uphole to LOC mode U 1  wherein the arms  68  and dogs  62  are released radially outwardly. Pulling up on the conveyance string  66  drags the dogs  62  along the casing  40  until the dogs  62  locate the increased diameter recess  15  of the sleeve housing bore  14  downhole of the sleeve  12 . The dogs  62  engage the distal or downhole end  26  of the sleeve  12 . 
     Location of the distal end  26  of the sleeve  12  by the dogs  62  is 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 retainer  24  and the single-shift sleeve  12  shifts uphole to the open position. The opening of the sleeve  12  can be verified by continuing to pull uphole with the dog  62  bearing against the sleeve  12  and the opened sleeve bearing against an uphole shoulder  32  of the housing  16 . 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 in  FIG. 2 , once shifted to the open position, the sleeve  12  is engaged in the open position by the second retainer  34  which prevents the sleeve  12  from shifting back to the closed position of  FIG. 1 , as discussed above. 
     All that is required next is to block the wellbore below the sleeve assembly  10  to treat the formation through the opened ports  18 . However, the next available J-mechanism sequence is to lower the BHA mandrel  80  downhole which engages the cone  75  and dogs  62  in SET mode for expanding the packer  74 . Setting the BHA  100  in this intermediate position is ineffective for the fracturing step as the packer  74 , at the time of the SET mode, is located uphole of the frac  18  ports and the dogs  62  remain located within the sleeve assembly housing  16 , substantially positioned at the frac ports. Instead, additional cycles are performed to enable repositioning of the packer  74  of the BHA to a new position below the sleeve assembly before the SET mode is attempted again. 
     Conventional J-Mechanism 
     With reference more specifically to  FIG. 8A , in one embodiment of operation, this known BHA  100  and the operating mode of the shifting tool arrangement therein can be implemented to locate, engage, and shift the operating sleeve  12  uphole and then include further cycles to reset  16  BHA by running the BHA further downhole to below the opened sleeve  12  for setting the packer  74  to the casing string  40  to seal or block the wellbore and frac through the opened  18  ports  18  above the packer. The manipulation of the BHA  100  through the various modes is performed using a series of up and downhole cycling of the conveyance string  66 . 
     To axially move and set the packer  74  downhole, the BHA  100  is first cycled downhole by a soft-set of the packer, cone, and dog arrangement, temporarily moving to the SET mode D 2  merely to cycle the J-mechanism. The BHA  100  is cycled again to the POOH mode U 2  to constrain the dogs  62  and arms  68  radially inwardly and the BHA is pulled uphole so that the dogs  62  are repositioned above the sleeve  12 , typically by a displacement distinguishable at surface, say by a few feet. Next the BHA  100  is cycled downhole again to RIH mode D 1  to allow the BHA to be moved axially and freely downhole. The arms and dogs are restrained in the radially inward collapsed position and the BHA  100  is RIH until the BHA is below the recorded CT tension depth, such as about 10 feet below. 
     The J-mechanism  70  is then cycled to POOH mode U 2  by pulling uphole, after which the BHA is moved to SET mode again by setting down to mode D 2  to engage the cone and packer with the dogs, setting the dogs in the case  40  as slips and compressing the packer  74  to ensure the casing is seated below the sleeve assembly  10  to isolate the wellbore therebelow. 
     Following fracturing, the BHA is pulled uphole to POOH mode U 2  to release the packer  74 , collapsing the arms  68  and dogs  62  for releasing the BHA  100  which is pulled axially uphole to the next sleeve assembly  10  in the casing string  40 . Prior to reaching the next sleeve assembly and still downhole thereof, axial movement of the BHA is stopped and the J-mechanism  70  is cycled to RIH mode D 1  to the LOC mode U 1 . 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 assemblies  10 , 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 ports  18 . 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 of  FIGS. 9, 10A to 10G, 11  and  FIGS. 12A through 12E , embodiments of a reduced cycle BHA  102  are shown having a reduced cycle shifting tool incorporated therein. 
     The modified BHA  102  is described in which the number of operating cycles, to shift the sleeve  12  uphole to open the frac ports  18  and then move the resettable packer  74  downhole 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 BHA  102  further comprises a slack sub  120  for enabling a biased-downhole displacement or repositioning of the shifting tool housing after a uphole manipulation. Unlike conventional J-mechanisms, the BHA  102  can be shifted from the sleeve opening to reposition downhole of the sleeve assembly  10  without a need to manipulate the conveyance string  66  through extra cycles. 
     The J-mechanism applied with the modified BHA  102  comprises the previously described and complementary BHA mandrel  80  and BHA housing  90  components, one connected to the uphole conveyance string and the other connected to a downhole drag block. Typically the mandrel  80  is connected to the conveyance string and the housing  90  connected to the drag block. 
     Simply, a reduced cycle telescopic BHA  102  is provided including a repositioning or slack sub situate between the J-mechanism  70  uphole thereof and the drag block  82  downhole thereof. The method of using the reduced cycle BHA  102  comprises energizing the repositioning sub to an extended, energized position upon the shifting of the sleeve  12  uphole to the open position. To reposition the BHA below the opened sleeve, one runs the BHA  102  downhole to position the resettable packer  74  and dog  62  assembly to a location below the selected sleeve assembly  10  by 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 assembly  10  without actuating the resettable packer  74 . Once the repositioning sub is collapsed, further setting down on the BHA  102  sets the packer and dogs across the completion string in SET mode. 
     In detail, the repositioning or slack sub  120  is situate between the downhole drag beam  82  and the BHA housing  90 . The mandrel  80  is secured to the conveyance string, the surface movement of which is insensitive to the relatively weak axial forces downhole. Uphole movement of the conveyance string  66  pulls the mandrel  80  uphole. 
     The slack sub  102  acts between a downhole end of the BHA housing  90  and the drag beam  82  for biasing the BHA housing downhole from the LOC mode position when released from the sleeve. The BHA housing  90  is biased downhole to a fracturing location below the sleeve assembly  10 , wherein the packer  74  and dogs  62  are spaced below the distal end of the assembly  10 . 
     The slack sub  120  acts to eliminate the series of extra manipulations of  FIGS. 8A and 8B , that are required when using the prior art shifting tool  100  to configure the BHA  100  to move the packer  74  and the dogs  62  to a position below the sleeve assembly  10 . 
     As shown in  FIGS. 11B and 11D , the slack sub  120  is a telescoping apparatus, having a tubular outer slack housing  122  and an inner slack mandrel  124 , the slack mandrel  124  and a slack annulus  126  formed therebetween. The slack mandrel  124  is telescopically and axially moveable into and out of the slack housing  122  between a collapsed position ( FIGS. 9, 8, 11A  and B) and an extended position ( FIGS. 10, 11C and 11D ) relative to the outer housing  122 . A drag spring  128  is positioned annularly about the mandrel  124  in the slack annulus  126  and is retained thereabout within the slack housing  122 . The drag spring  128  acts to bias the slack mandrel  124  back for retraction into the slack housing  122  to the collapsed position. 
     An uphole sub  134  of the slack housing  122  forms a downward facing shoulder as an uphole spring stop  130  and a downhole sub  136  for connection with the drag beam  82  assembly. The slack mandrel  124  further comprises a top sub  140  for connection with the downhole end of the BHA housing  90 . The downhole end of the slack mandrel  124  further comprises an adjustable spring retention nut  142  adjacent a distal end thereof and forming a downhole spring stop  132  for engaging the distal end of the drag spring  128 . As the slack mandrel extends out of the slack housing, the drag spring  128  is compressed between stop  130  and stop  132 . The uphole sub  134  has a bore  135  through which the slack mandrel  124  slidably passes. The drag spring  128  is compressed between the uphole spring stop  130  and the downhole stop  132  of the adjustable spring retention nut  142 . The adjustable spring retention nut  142  and can be variably positioned and retained axially along the slack mandrel to pre-establish variable tension in the drag spring  128  and a distance of travel of the BHA  120  connected thereto. 
     Slack mandrel  124  has an uphole end  140  that is connected to the downhole of the BHA housing  90 , typically to the bottom of the J-housing  70 , and a downhole end  136  of the slack housing  122  is connected to the drag beam assembly  82 . 
     In use, the slack sub  120  adopts the collapsed position when the BHA is being run-in-hole (RIH) and during fracing in SET mode. When the BHA  102  is pulled uphole, such as to locate or to shift the sleeve  12  of the sleeve assembly  10 , the drag beam assembly  82  provides sufficient frictional restraining drag force to retain the position of the slack housing  122  axially within the casing  40  while the slack mandrel  124  is pulled axially uphole with the BHA  102 . The downhole retention nut  142  of the slack mandrel  124  approaches the uphole stop  130  of the slack housing  122  as the slack mandrel  124  moves to the extended position. The slack spring  128  is compressed to an energized position. 
     As shown in  FIGS. 12C and 14A , when the dogs  62  are released from the sleeve assembly  10 , the energy of the drag spring  128  pulls downhole on the BHA housing  90 . In  FIG. 14B , the BHA housing  90 , at least the arms  68  and dogs  62  are dragged downhole, spacing the dogs  62  from the cone  75  carried by the BHA mandrel  80 . 
     The setting down of the BHA releases the energy of the extended slack sub  120 , biasing the J-mechanism housing  90  and dogs  62  downhole towards the drag block  82  while the J-mechanism mandrel follows downhole, the BHA repositioning below the open, selected sleeve  10 . The slack mandrel  124  telescopically extends from the slack housing  122  by a stroke length, the stroke length being greater than the distance between the spacing between the dogs and the packer  74  in the cone-engaged position and wherein upon the dogs  10  disengaging from the sleeve assembly  10 , the slack mandrel  124  telescopically drags the BHA housing  90  downhole and the packer  74  is dragged downhole of the sleeve assembly  10 . 
     As shown in  FIGS. 12D and 14C , the axial magnitude of the collapsing slack sub  120  is such that, when the BHA housing  90  is biased downhole by the drag spring  128 , the dogs  62  are positioned below the sleeve assembly  10  when the BHA mandrel, packer  74  and cone  75  engage the dogs  62  in SET mode and anchor the dogs in the casing  40  therebelow. 
     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 housing  90  relative to the casing  40 . Further, the tubular components can be perforated therethrough to assist with sand and debris removal there between. 
     In embodiments the slack mandrel&#39;s extended position is defined by the length of the mandrel  124  and the positioning of the adjustable spring retention nut  142  thereto. 
     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 to  FIGS. 11A to 11G, 12A to 12E and 13 , sleeve  12  is shifted uphole to the open position, using Applicant&#39;s BHA  102 . As shown in  FIG. 11A , in RIH mode, the BHA&#39;s packer  74  is relaxed and the slack sub- 120  is initially in the collapsed position all of which is RIH to a depth below the sleeve assembly  10 . As shown in  FIG. 11C , the J-mechanism  70  is cycled to the LOC Mode as described above and the BHA  102  is pulled uphole until the radially extending dogs  62  on the arms note the sleeve housing bore  14  and engage the distal end of the sleeve  12 . As shown in  FIG. 11D , the BHA  102  is pulled uphole to locate the distal end  26  of the sleeve  12 . During uphole movements, the frictional force of the drag beam  82  on the casing  14  exceeds that of the force to compress drag spring  128 , and slack mandrel  124  telescopes axially from the slack housing  122  to the extended position. 
     As shown in  FIG. 11E , continuing to pull the BHA  102  uphole with the dogs  62  engaged with the distal end of the single-shift sleeve overcomes the first retainer  28 , and the sleeve  12  is shifted uphole to open the ports  18 . The packer  74  is currently located uphole of the frac ports  18  and the dogs  62  are positioned at about the frac ports. The slack sub- 120  remains engaged in the extended position ( FIG. 11D ). 
     Thereafter, as shown in  FIG. 11F , the J-mechanism  70  is cycled towards a SET/FRAC mode, which releases the dogs  62  and allows the drag spring  128  to drag the slack mandrel  124  downhole towards collapsed position ( FIG. 11B ). The BHA housing  90  attached to the slack mandrel  124  is also dragged downhole to below the sleeve assembly  10  and BHA mandrel, packer  74  and cone  75  thereon can follow without actuation. 
     The effect of slack sub is not necessarily limited by the BHA housing  90 . In  FIGS. 17A and 17B , the BHA can be fit with a fracturing fluid valve  250  uphole of the packer  74 . The valve  250  is telescopic, having an inner tubular valve stem  252  and an outer tubular valve sleeve  254 . The inner valve stem  252  is connected to the conveyance string  66  at an uphole end and has a downhole plug  256 . The outer valve sleeve  254  is connected at a downhole end to the BHA mandrel  80 . When the valve stem  252  is actuated downhole, the plug  256  blocks the bore of the BHA mandrel  80  and side fluid apertures  262 , 264  in both the valve stem  252  and sleeve  254  respectively align for fracturing fluid egress. When the valve stem  252  is actuated uphole, upon an upward pull of the conveyance string  66 , plug  256  pulls opens from the BHA mandrel  80  and the side fluid apertures  262 , 264  misalign for blocking fracturing fluid flow from the conveyance string  66  and valve stem aperture  262 . The action of the slack sub  120  can, depending on the relative uphole downhole relationship of the conveyance string  66  and BHA  102 , also drag the valve sleeve  254  portion downhole. Firstly, as BHA housing  90  is pulled downhole, the uphole J-Profile is lowered over the uphole J-Pin of the BHA mandrel  80 . Once the J-Pin is engaged, by one of the U 1  or U 2  J-Profile positions, the BHA mandrel  80 , packer  74  and cone  75  can also be dragged downhole therewith, maintaining a spaced, but close relationship with the BHA housing  80 . 
     Once the slack sub  120  is fully in the collapsed position and there is no further downward movement of the BHA housing  90 , the packer, cone and dogs are set in the casing below the sleeve assembly  10  for fracturing through the open ports  18 . 
     As shown in  FIG. 11G , following fracturing, the J-mechanism  70  is cycled to the POOH mode, the packer  74  is again relaxed and the arms and dogs are constrained radially inwardly. The BHA  102  is then pulled uphole toward the next sleeve assembly  10  to be opened, the slack mandrel  124  once again moving axially, within the slack housing  122 , to the extended position. 
     As with the prior BHA  100  of  FIG. 6A , prior to reaching the next sleeve assembly  10 , axial uphole movement is stopped, and the J-mechanism  70  is cycled to the LOC Mode so that, when pulled further uphole, the next sleeve assembly  10  to be opened can be positively located by the dogs  62  and the process as described above repeated for shifting the sleeve and fracturing through the open ports. 
     Low Friction Roller Sub 
     As shown in  FIG. 6B , centralizers  91  can be provided to reduce friction between the BHA  102  and the casing  40 , the centralizer generally being manufactured from low friction materials, such as polyurethane. The centralizer can enable the slack sub  120  to more effectively drag the BHA downhole as described above. 
     In other embodiment, and having reference to  FIGS. 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 housing  90  to the collapsed position, the BHA may further comprise a roller sub  150 . Centralizers and rollers are also known in the centralizing of reciprocating rod strings. 
     In embodiments, the roller sub  150  comprises a tubular housing having a plurality of low-friction surfaces  152  extending 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 housing  90  such as between the arms  68  and the J-mechanism  70 . 
     Movement-Starting Nudge Sub 
     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 sub  160  may be used in instead of the roller sub  150 , or alternatively can be used in combination therewith, to induce initial movement of the slack sub&#39;s housing  122  and BHA housing  90 . 
     In embodiments, the nudge sub  160  acts to provide a momentary downhole force on the slack sub&#39;s housing  122  to initiate downhole movement so as to aid the slack sub to drag the BHA housing  90  downhole. 
     Having reference to  FIGS. 15 and 16 , the nudge sub  160  comprises a tubular nudge housing  162  having a bore  164  therethrough. The nudge housing  162  is connected to the slack mandrel  124  of the slack sub  120  therebelow. A nudge mandrel  166  extends sealably, through seals  167 , through an uphole end  168  of the housing  162  and is axially moveable along the bore  164 . The nudge mandrel  166  is connected to the BHA mandrel  80  thereabove which, when cycled downhole to RIH mode, also drives the nudge mandrel  166  downhole into the nudge bore  164 . A downhole end  184  of the nudge sub housing  162  is connected to the slack mandrel  124  of the slack sub  120 . The nudge mandrel  162  momentarily drives the nudge housing  164  downhole so as to drive the slack mandrel  124  to move axially downhole against debris-related annular resistance. 
     Adjacent an uphole end of the bore  164  is a circular constriction  170 , dividing the bore into an uphole chamber  172  and a main chamber  174  downhole thereof. The upper chamber  172  receives a distal end of the nudge mandrel  166  therein. The uphole and main chambers  172 , 174  are fluidly connected. The nudge bore  164  is filled with an incompressible fluid, such as oil. 
     The distal end of the nudge mandrel  166  fit with a cylindrical nudge piston  180  thereon. The diameter of the nudge piston  180  is sized to pass axially through the circular constriction. The first constriction  170  is spaced downhole from the nudge housing&#39;s uphole end  168  and forms the upper chamber  172  therebetween. The constriction  170  has a diameter slightly larger than that of the piston  180  as shown in  FIG. 16 , such that when the nudge piston  180  passes through the constriction  170 , there is a hydraulic resistance to the passage of the piston therethrough. The axial extent or length of the constriction  172  is relatively short compared to the travel of the nudge mandrel  166  so as to provide a fluid connection for a limited duration with the slack mandrel  124  so as to initiate movement thereof as described below. Once the nudge piston  180  passes through the constriction  170 , the downhole movement of the BHA mandrel  80  and connected nudge mandrel  166  is effectively disconnected from the slack sub  120 . 
     During the passage of the piston through the constrictor  170 , oil is fluidly displaced from the main chamber  174  to flow into a lower chamber  176 . The oil in main chamber  174  is moved between the main and lower chamber  174 , 176  as the nudge mandrel  166  moves axially uphole and downhole. The lower chamber is merely a housing for the axial movement and retention of a compensator piston  186  moveable with the volume of displaced fluid. 
     The compensator piston  186  is located axially within the lower chamber  176  between an uphole stop  182  and the downhole sub  184 , moving in response to displacement of oil as the nudge mandrel  166  moves axially within the bore  164 . The compensator piston  186  is 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 piston  186  ensures that the pressure of the oil in the nudge sub  160  is balanced with the wellbore pressure, which varies with wellbore depth, while accommodating the movement of oil in the bore  164 . Balancing the pressure in the bore  164  with the wellbore fluids of the casing string  40  ensure the mandrel seals  167  are not subjected to a high, different pressure. 
     Further, as shown in  FIG. 15 , the nudge piston  180  has a check valve  190  therein, such as flapper valve, to enable substantially free uphole movement of the nudge mandrel  166  and nudge piston  180  thereon and displacement of fluid from the uphole chamber  172 , such as when the BHA is pulled uphole (POOH) and the nudge piston  180  resets by passing uphole through the constrictor  170 . 
     As can be seen in  FIG. 15 , wherein the nudge sub  160  is shown juxtaposed with J-profile of  FIG. 13 , the location of the constriction  170  is coordinated axially, within the nudge housing  162 , with respect to the cycling of the J-mechanism. The constriction  170  is spaced along the nudge sub  160  so to coordinate the timing of the push or nudge, applied by the nudge housing  162  to the slack mandrel  124 , with release of the dogs  62  and the dragging action of the slack mandrel  124  intermediate the BHA cycle to the SET mode at D 2  of the J-Profile. In embodiments, the nudge piston  180  reaches the constriction  170  as the arms and dogs  62  of the BHA are being constrained radially inwardly at U 2  of the J-Profile so as to allow free axial movement of the BHA downhole within the wellbore. 
     In use, when the J-mechanism  70  is cycled to SET mode, the BHA mandrel  80 , the nudge mandrel  166 , and the nudge piston  180  are permitted to move freely downhole until the piston reaches the constriction  170 . A momentary hydraulic restriction is formed thereat, which effectively acts to momentarily lock or couple the nudge piston  180  to the nudge housing  162 . The coupled movement of the nudge housing  162  causes a forceful downhole movement of the slack sub&#39;s mandrel  124  towards the collapsed position, breaking a stuck BHA housing  90  free of the casing string and permitting the energy of the compressed spring  128  to take over to drag the BHA housing  90  downhole therewith. 
     In embodiments, the nudge sub  160  may assist in initiating movement from a static friction mode to a dynamic friction mode such that the slack mandrel  124  and spring  168  can maintain dragging movement under the lower dynamic friction conditions.