Patent Publication Number: US-11649696-B2

Title: Wireline completion tool and method

Description:
FIELD 
     Embodiments of the disclosure relate to methods and apparatus used for completion of a wellbore and, more particularly, to wireline-connected apparatus and methods for performing completion operations and monitoring downhole conditions in real-time and at surface during fracturing operations. 
     BACKGROUND 
     Apparatus and methods are known for single-trip completions of deviated wellbores, such as horizontal wellbores. To date the completions industry, unlike the drilling industry which commonly utilizes intelligent apparatus for drilling wellbores in horizontal or deviated wellbores, the fracturing industry has relied largely on mechanically-actuated apparatus and well logs to locate tools in the wellbore so as to perform a majority of the operations required to complete a wellbore. This is particularly the case with wireline-deployed bottom hole assemblies (BHAs), largely due to the difficulty in providing sufficient and reliable electrical signals and power from surface to the BHA and from the BHA to surface. Further, bore restrictions, necessitated by current instrumentation subs, limit flow rates therethrough to less than 700 L/min, which is generally insufficient for contemporary fracturing operations. 
     It is known to deploy BHAs for facilitating completion operations using jointed tubulars, wireline, or cable, and coiled tubing (CT). One class of prior methodology for performing downhole operations uses a shifting tool that is run in hole for manipulating sleeve assemblies or valves. The shifting tool is conveyed downhole on tubulars or tubing typically on CT. A BHA at a distal end of the CT is fit with the shifting tool. The BHA selectively engages sliding sleeves of the sleeve valves spaced along casing with the shifting tool, accessing multiple zones in the formation. The conveyance tubing is manipulated to control the shifting tool which engages the sliding sleeves. The sliding sleeves are manipulated to open pre-existing ports at each sleeve. The BHA includes a packer which is set in the wellbore below the ports to enable fluid treatment through open ports thereabove. In other embodiments, the shifting tool can also be used to close selected sleeves to enable fluid treatment through opened ports in other sleeves. 
     Treatment fluid can be delivered downhole along the wellbore to the selected zone of the formation through the annulus between the wellbore casing and the CT, or, in some cases, through the CT, or through both at the same time. The fluid is directed through the opened ports. Typical CT conveyed BHAs comprise mechanically-operated downhole shifting tools having telescoping mandrels, packers, and tubing, controlled by axially delimited J-mechanisms for selecting a variety of operating modes. Fracturing operations using CT require specific surface equipment, including CT injection units. 
     Many fracturing operations, commonly in the US Midwest, utilize wireline, rather than CT to perform downhole operations. Unlike CT, wireline is unable to “push” a BHA downhole and is also limited in its ability to withstand significant tensile “pulling” forces. The maximum tensile load of conventional wireline is generally insufficient to overcome resistive forces for initiating an uphole, sliding operation of the sleeves. Further, because wireline lacks the rigid structure of CT, downhole shifting of the sleeves has the additional problem that the bendable wireline cannot transmit a “pushing force” applied from surface to the BHA and the sleeve engaged therewith. 
     As will be appreciated by those of skill in the art, the acquisition of data representing downhole conditions before, during and after a frac is useful to the operators. Multi-zone fracturing is characterized by setting a packer and introduction of proppant-loaded treatment fluid at high pressure to a zone or stage, then repeated release, pressure equalization, and re-location of the BHA to subsequent stages. Downhole conditions for completion operations are determined with electronic sensors and have been typically stored in memory tools carried by the BHA. The stored data is typically downloaded and reviewed at surface after the BHA is pulled out of hole. A disadvantage of storing data to on-board memory is that the downhole conditions are not known until downhole operations are already completed and after the BHA has been retrieved to surface. As such, the operator cannot adjust the operating parameters of the BHA and fracturing operation in real-time to respond to downhole conditions during the operation. 
     Real-time tools have been applied in downhole operations such as fracturing and drilling. Downhole parameters related to the downhole drilling environment and parameters have not been directly ascertainable at surface, and as a result, the operator is typically only provided with indirect data through surface measurements, such as reactive torque and string weight variation, to gauge downhole performance. Absent direct downhole data regarding wellbore conditions at the BHA, which may be located thousands of meters from surface, too much or too little string weight can be applied at surface resulting in downhole tool damage or ineffective rate of penetration when drilling. 
     With added complexity, some coiled-tubing conveyed BHAs are capable of acquiring real-time data and delivering said data to surface, such as that disclosed in published international application WO 2018/137027, incorporated herein in its entirety. An electrically enabled CT, or e-coil, which forms a non-rotating conveyance string, can conduct data readings uphole during drilling. The BHA is fit with a variety of sensors including pressure and acceleration, for gathering downhole parameters relating to the drilling interface. Such real-time e-coil is robust, in part due to the fixed arrangement which has no moving parts. However, movement of the BHA is related to fatigue connection issues. Thus, these applications are suited to fixed assemblies of components which are not subject to repeated movement and no relative movement therealong. 
     Unfortunately, currently in hydraulic fracturing, the a CT conveyed BHA is subject to repeated and relative axial movement to set the packer and cycle the J-mechanism, and is further subjected to high fluid rates of abrasive, proppant loaded fluids, thus creating hostile conditions for such real-time instrumentation subs. 
     Further, as wireline lacks the protection offered by CT frac operations utilizing, wireline is especially vulnerable to proppant wear at the ports, where frac fluid abruptly changes from an axial to a radial direction to flow out to the wellbore, resulting in turbulent flow. 
     There is interest in the industry for a downhole fracturing system that avoids the complexity and limitations of CT-conveyed tools, enables the real-time communication of data between surface and a downhole tool, and to improve access to operational data at the downhole tool for increasing the reliability and effectiveness of hydraulic fracturing operations. 
     SUMMARY 
     Herein, the inherent limitations of wireline are overcome with an electrically enabled bottom hole assembly (BHA), particularly in the manipulation of downhole sleeve assemblies for completion operations. Further, the monitoring of pressure uphole and downhole of the BHA during fracturing operations enables measurements indicative of how the formation is reacting to the fracturing operation and may also be indicative of the integrity of the isolation effectiveness of the BHA and the characteristics of the formation between adjacent zones. Instead of calculating or estimating downhole parameters from parameters measurable at surface, or reviewing data at a later date as recovered from memory stored on downhole tools, downhole data is recovered at surface in real-time. Issues with downhole applications involving wireline are managed with using electric actuators, packers, electric sleeve shifters, and protective sleeves and tubes. 
     Surface equipment, such as trucks used for wireline fracturing operations, has a lower cost than CT units and is more readily available in many areas of North America. Use of the disclosed wireline BHA, which can be applied to downhole sleeve assemblies obviates operations to clean up the wellbore for production as may be required in some applications using plugs or dissolvable plugs. The use of the wireline BHA to manipulate sleeve assemblies and utilize the full bore of a wellbore casing, means that no reduction in diameter is required as would be in conventional applications using plugs or ball-drop and dart actuated sleeves. 
     Herein, a downhole fracturing tool is provided comprising electrically enabled wireline, an interface sub and an electrically-actuated BHA. 
     In a broad aspect, a BHA electrically connected to a wireline, the BHA adapted for manipulating one or more target sleeve valves spaced along a wellbore, includes a shifting tool and a sealing element. The shifting tool having an element and electrically actuable between a radially outward biased position, a radially outward engaged position, and a radially inward collapsed position. The sealing element electrically actuable between a radially outward sealing position and a radially inward released position. When the shifting tool element is in the biased position, the BHA can be moved along the wellbore and the shifting tool element is adapted to engage a sleeve of a target sleeve valve. When the shifting tool element is in the engaged position, the shifting tool is locked axially to the target sleeve for operation of the target sleeve valve and adapted to open or close the target sleeve valve. When the sealing element is the sealing position, an annulus between the wellbore and the BHA is blocked to direct annular fluid through an opened sleeve valve. When the shifting tool element is in the collapsed position, the BHA can be moved along the wellbore. 
     In an embodiment, the BHA also includes electrically actuable slips actuable between a wellbore-engaged position and a released position, wherein when the slips are in the wellbore-engaged position, the slips are engaged with the wellbore and the BHA is restrained to the wellbore. 
     In an embodiment, the BHA also includes electrically actuable slips actuable between a wellbore-engaged position and a released position and an electrically-actuated axial stroking tool located between the slips and the shifting tool. When the slips are in the wellbore-engaged position, the slips are engaged with the wellbore, the shifting tool is engaged with the target sleeve, and the stroking tool can operate the target sleeve valve between the open and closed or closed and open positions. 
     In an embodiment, the BHA also includes an instrumentation sub having one or more sensors for measuring one or more parameters of the wellbore and BHA, the sensors in communication through the wireline. 
     In an embodiment, the shifting tool element includes a housing, an actuator and one or more dogs. The one or more dogs are supported by the housing and radially actuable by the actuator between the biased position, the engaged position and the collapsed position. 
     In an embodiment, the sleeves include axial engagement ends and the shifting tool element is adapted to engage the sleeves at one or both of the engagement ends to open or close the target sleeve valve. 
     In an embodiment, the shifting tool element includes a housing, an actuator, a mandrel and a set of fingers. The mandrel is axially moveable within the housing by the actuator and has at least three diameters. The set of fingers is radially actuable by the mandrel between the biased position corresponding to a first diameter of the mandrel, the engaged position corresponding to a second diameter of the mandrel, and the collapsed position corresponding to a third diameter of the mandrel. 
     In another broad aspect, a method of deploying a BHA for fracturing operations connected by wireline in a casing of a wellbore includes pumping fluid into the wellbore to position the BHA, radially extending a shifting tool element of the BHA to a biased position to engage walls of a sleeve, pulling the BHA by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve, setting the shifting tool element of the BHA to an engaged position to axially lock the shifting tool element to the sleeve, setting a sealing element in the casing to isolate an annular area between the wellbore and the BHA, pumping fluid into the wellbore to open the sleeve, pumping fracturing fluid into the annular area, unsetting the sealing element in the casing, waiting for pressure uphole and downhole the sealing element to equalize, retracting the shifting tool element to a collapsed position, and pulling the BHA uphole with wireline to the next sleeve. 
     In an embodiment, the method also includes setting a set of slips to engage the casing, and closing the sleeve by axially stroking the shifting tool element while the BHA is axially fixed to the casing. 
     In an embodiment, the method also includes measuring axial force on the wireline using a sensor and communicating axial force measurements through the wireline for observing wireline load. 
     In an embodiment, the step of pulling the BHA by the wireline uphole includes measuring axial force on the wireline using a sensor and communicating axial force measurements through the wireline to determine whether the shifting tool element is in a biased position, an engaged position or a collapsed position. 
     In an embodiment, the step of setting the sealing element includes measuring pressure proximate the sealing element using a sensor and communicating pressure measurements through the wireline to determine whether the sealing element is in a sealing position or a released position. 
     In an embodiment, the step of pumping fracturing fluid into the annular area includes measuring pressure uphole and downhole of the sealing element in the wellbore using sensors and communicating pressure measurements through the wireline for confirming a level of isolation provided by the sealing element. 
     In an embodiment, the step of pumping fracturing fluid into the annular area includes measuring fluid pressure in the wellbore using a sensor and communicating pressure measurements through the wireline for observing parameters of a potential screen-out of the wellbore. 
     In another broad aspect, a method of deploying a BHA for fracturing operations connected by wireline in a casing of a wellbore includes pumping fluid into the wellbore to position the BHA, radially extending a shifting tool element of the BHA to a biased position to engage walls of a sleeve, pulling the BHA by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve, setting the shifting tool element of the BHA to an engaged position to axially lock the shifting tool element to the sleeve, setting a set of slips to engage the casing, opening the sleeve by axially stroking the shifting tool element while the BHA is axially fixed to the casing, setting a sealing element in the casing to isolate an annular area between the wellbore and the BHA, pumping fracturing fluid into the annular area, unsetting the sealing element in the casing, waiting for pressure uphole and downhole the sealing element to equalize, closing the sleeve by axially stroking the shifting tool element while the BHA is axially fixed to the casing; 
     releasing the set of slips, retracting the shifting tool element to a collapsed position, and pulling the BHA uphole with wireline to the next sleeve. 
     In an embodiment, the method also includes measuring axial force on the wireline using a sensor and communicating axial force measurements through the wireline for observing wireline load. 
     In an embodiment, the step of pulling the BHA by the wireline uphole includes measuring axial force on the wireline using a sensor and communicating axial force measurements through the wireline to determine whether the shifting tool element is in a biased position, an engaged position or a collapsed position. 
     In an embodiment, the step of setting the sealing element includes measuring pressure proximate the sealing element using a sensor and communicating pressure measurements through the wireline to determine whether the sealing element is in a sealing position or a released position. 
     In an embodiment, the step of pumping fracturing fluid into the annular area includes measuring pressure uphole and downhole of the sealing element in the wellbore using sensors and communicating pressure measurements through the wireline for confirming a level of isolation provided by the sealing element. 
     In an embodiment, the step of pumping fracturing fluid into the annular area includes measuring fluid pressure in the wellbore using a sensor and communicating pressure measurements through the wireline for observing parameters of a potential screen-out of the wellbore. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG.  1 A  is a schematic side view of an embodiment of a wireline-conveyed bottom hole assembly (BHA) conveyed through a cased completion string of a wellbore and located at a downhole sleeve assembly, the formation and any cement omitted for better illustrating the casing and downhole tool; 
         FIG.  1 B  is a side view of an embodiment of a wireline-conveyed BHA in a completion string having a shifting tool actuated by an electrically-enabled stroking mechanism; 
         FIGS.  2 A to  2 C  are schematic side views of a portion of the shifting tool having an alternative sleeve engaging and shifting device having radially extendable and retractable fingers; 
         FIG.  2 D  is a schematic side view of portion of an alternative embodiment of the shifting tool having an alternative sleeve engaging and shifting device having radially extendable and retractable fingers having a partially tapered mandrel; 
         FIG.  3    is a side detail view of a profile in a sleeve for corresponding dog-type shifting tool; 
         FIGS.  4 Ai to  4 D  are schematic side views of a wellbore extending to a formation, illustrating an embodiment of an open-only BHA deployed in the wellbore (illustrations and references to the location of sleeves in  FIGS.  4 Ai to  4 D  are fanciful), and more particularly 
         FIGS.  4 Ai  and  4 Aii illustrate the open-only BHA being pumped downhole with fluid; 
         FIG.  4 B  illustrates dogs of the BHA&#39;s shifting tool being actuated to engage the wellbore casing as the BHA is pulled uphole by the wireline until the dogs engage the sleeve of a sleeve valve, as further shown in  FIG.  4 C ; 
         FIG.  4 C  illustrates the dogs having engaged the recess in the sleeve and an elastomeric sealing element being set in the wellbore to isolate the wellbore annulus, the sleeve valve being opened downhole with the assistance of fluid pumped down the annulus; 
         FIG.  4 D  illustrates treating the formation by directing treatment fluid down the annulus and out of the opened ports of the sleeve valve; 
         FIGS.  4 E to  4 G  are schematic side views of a wellbore extending to a formation, illustrating an embodiment of an open-close BHA deployed in a wellbore (illustrations and references to the location of sleeves in  FIGS.  4 E to  4 G  are fanciful), and more particularly  FIG.  4 E  illustrates the open-close BHA having been pumped downhole of a sleeve valve of interest, the shifting valve having been actuated the engage the wellbore casing the open-close BHA being pulled uphole by the wireline until the shifting tool engages the sleeve; 
         FIG.  4 F  illustrates the shifting tool engaged with the sleeve and the BHA having been anchored to the wellbore for stroking the shifting tool and engaged sleeve to an opened position in this embodiment, or closed as appropriate in an alternate completion operation, and an elastomeric sealing element being actuated isolate the wellbore annulus; 
         FIG.  4 G  illustrates treating the formation through the opened ports above the isolated annulus; 
         FIGS.  5 A to  5 F  are schematic side views of a wellbore extending to a formation, illustrating a sequence of steps to deploy and use a BHA to open and close sleeves, the BHA having a shifting tool including dogs supported on arms, and more particularly; 
         FIG.  5 A  illustrates the BHA being pumped downhole into location with fluid; 
         FIG.  5 B  illustrates dogs being activated in the BHA to engage the wellbore casing; 
         FIG.  5 C  illustrates the BHA being pulled uphole by the wireline until the dogs engage a profile in the sleeve valve&#39;s sleeve; 
         FIG.  5 D  illustrates the dogs locked to the sleeve set of slips being set to anchor the BHA to the casing, an elastomeric sealing element being set to isolate an annular area and in this embodiment use fluid pressure on the packer to shift the sleeve downhole and open the ports; 
         FIG.  5 E  illustrates treating the formation with fluid through the opened ports; 
         FIG.  5 F  illustrating release of the shifting tool after fluid treatment, the elastomeric sealing element deflated, the dogs radially collapsed and the stroking mechanism reset, if applicable; 
         FIGS.  6 A to  6 F  are schematic side views of a portion of a wellbore in a formation, illustrating a sleeve valve and a BHA located thereat, the figures illustrating a sequence of steps to open and treat the target sleeve valve using an embodiment of a BHA having radially-actuable fingers, and more particularly; 
         FIG.  6 A  illustrates the BHA being pumped downhole into location with fluid; 
         FIG.  6 B  illustrates fingers being activated in the BHA to engage the wellbore casing; 
         FIG.  6 C  illustrates the BHA being pulled uphole by the wireline until the fingers engage the sleeve; 
         FIGS.  6 D and  6 E  illustrate the elastomeric sealing element being set to isolate an annular area and fluid being pumped against the sealing element to drive the BHA and shifting tool downhole to shift the sleeve open; 
         FIG.  6 F  illustrates the sealing element being released from the wellbore, the fingers retracted, and the stroking mechanism being reset, if applicable. 
         FIGS.  7 A to  7 I  are schematic side views of a portion of a wellbore in a formation, illustrating a sleeve valve and a BHA located thereat, the figures illustrating a sequence of steps to deploy and use a dual action BHA for both opening and closing sleeves; 
         FIG.  7 A  illustrates the BHA being pumped downhole into location; 
         FIG.  7 B  illustrates the BHA extending dogs (shown), or alternatively fingers, and being pulled uphole to locate a sleeve profile of a target sleeve valve; 
         FIG.  7 C  illustrates the dogs/fingers being locked in place; 
         FIG.  7 Di  illustrates the actuating the stroking mechanism to a retracted position and actuating an elastomeric sealing element to engage the wellbore; 
       FIG.  7 Dii illustrates actuating an elastomeric sealing element to engage the wellbore; 
         FIG.  7 Ei  illustrates using fluid pressure on the packer to shift the sleeve downhole and open the ports; 
       FIG.  7 Eii illustrates the slips being set to the wellbore for restraining the BHA and illustrates actuating the stroking mechanism, pushing against the slip, to open the sleeve; 
         FIG.  7 F  illustrates directing fluid through the opened ports to the formation; 
         FIG.  7 G  illustrates actuating the stroking mechanism, pushing against the slip, to close the sleeve after treating the formation; 
         FIGS.  7 H and  7 I  illustrates the sealing element being deflated, the dogs/fingers being retracted and the stroking mechanism being reset; 
         FIGS.  8 A and  8 B  are cross-sectional views of a conventional sleeve valve with a BHA located within and the sleeve engaged by an electrically actuated finger, and the BHA set within the sleeve for opening and hydraulic fracturing treatment through the opened ports; 
         FIG.  9    is a flowchart of an example method of deploying a BHA and opening a sleeve using fluid pressure; 
         FIG.  10    is a flowchart of an example method of deploying a BHA and opening a sleeve using fluid pressure and stroking the sleeve to close after treatment; 
         FIGS.  11 A to  11 E  are flowcharts illustrating additional steps of the method of claim  9 ; 
         FIG.  12    is a flowchart of an example method of deploying a BHA and stroking a sleeve to open and close; and 
         FIGS.  13 A to  13 E  are flowcharts illustrating additional steps of the method of claim  15 . 
     
    
    
     DETAILED DESCRIPTION 
     Embodiments are described herein in the context of fracturing operations. However, systems and methods disclosed herein are also applicable to completion, stimulation, and other operations wherein it is desired to actuate downhole sleeve valves to control fluid flow into and out of a wellbore. 
     Embodiments described herein utilize electrically-actuated downhole tools incorporated into a bottom-hole assembly (BHA)  20  for completion of multiple zones of interest in a subterranean formation during a single trip into a wellbore  2  intersecting the formation. Use of electrically-actuated BHA components permits functionality heretofore unavailable in conventional, mechanically-actuated BHA components. In embodiments, separate electrically-actuated drive components permit independent, on-demand operation of BHA components, used individually or in combination, such as sleeve locating apparatus, isolation apparatus, perforating apparatus, fracturing subs, microseismic monitoring apparatus, and the like. Further, use of the electrically-actuated tools allows the BHA  20  to be more compact than conventional BHAs used for the same purposes, suitable for lubricator deployment in live pressurized wells. One further advantage is that tools incorporated in the BHA  20  are actuated electrically from surface and provide accurate times of actuation, which aid in more accurate monitoring of fracturing operations. 
     In embodiments, most, if not all, of the components of the BHA  20  are electrically-actuated. In other embodiments, only some of the components are electrically actuated and are used together with mechanically-actuated components. 
     While applicable to a variety of wellbore types, apparatus and methods described herein are shown as being used in deviated, horizontal, or directional wellbores and particularly those of very long or extended length. 
     The terms “uphole” and “downhole” used herein are applicable regardless the type of wellbore; “downhole” indicating being toward a distal end or toe of the wellbore  2  and “uphole” indicating being toward a proximal end or surface of the wellbore  2  or surface. Further, the terms “electronically-actuated” and “electrically-actuated” are used interchangeably herein and may be dependent upon the characteristics of the component being actuated. Additionally, the terms “electronically-actuated” and “electrically-actuated” can refer to any form of actuation using electric signals, such as driving a component via an electric motor or operating an electric pump of a hydraulic system. 
     The BHA  20 , according to embodiments described herein, is deployed on a wireline  6 . In embodiments, for example, the wireline  6  is a 7/32 inch or 9/32 inch hepta cable. Bi-directional communication for actuation of the electrically-actuated tools from surface, and receipt of data therefrom, is enabled via electrical conductors contained in the wireline  6 . Any wireline  6  which provides sufficient electrical capability to actuate components in the BHA  20  as well as permitting communication between the BHA  20  and surface would be suitable for use in embodiments described herein. 
     Embodiments of the BHA  20  described herein are useful for treating or fracturing both cased or open wellbore. 
     Sleeve Assemblies 
     Sleeve assemblies  10  are generally incorporated within a completion string, such as a casing string  8 , set in a wellbore  2  drilled through one or more reservoirs. The sleeve assemblies  10  comprise an outer tubular housing  16  having a housing bore formed therethrough and an internal tubular sleeve  12  axially moveable therein. An annulus is formed between the sleeve and the housing. The housing  16  defines one or more ports  18  through which fluids, such as fracturing fluid introduced from surface, can flow. The sleeve  12  is axially moveable between a closed position wherein the sleeve blocks the flow of fluid through the ports  18 , and an open position, wherein the sleeve is shifted axially away from the ports  18 , allowing the fluids to flow therethrough. In the depicted embodiments, the sleeves  12  are shifted downhole to the open position from an uphole closed position. In other embodiments, the sleeves  12  can be shifted uphole to the open position from a downhole closed position. 
     Uphole and downhole internal delimiting shoulders, such as adjacent an uphole end and a downhole end of the housing  16 , protrude radially inwardly into the housing bore and engage uphole and downhole ends of the sleeve  12 , respectively. Thus the distance the sleeve  12  can shift axially in the housing  16  between the open and closed positions is delimited with the shoulders. 
     Sleeves  12  in the completion string are generally located using a locating tool. Sleeves  12  are known to be located using a locating tool that engages an uphole stop within a radial locating recess or sleeve profile  14  formed in the sleeve bore and having an axial extent. 
     In embodiments, the initial shifting force required to actuate the sleeve  12  can be controlled using shear screws with predetermined shear strength being inserted through the sleeve housing  16  and sleeve  12 . Once the shear value of the shear screws is overcome, shear screws break and the sleeve  12  is allowed to travel to the open position. The number of screws may be adjusted to desired operating parameters to achieve the desired initial actuation force. 
     As taught in Applicant&#39;s US published application US20170058644A1 (the &#39;644 Application), incorporated herein by reference in its entirety, in embodiments separate locating and shifting tools are not required. A locating shifting tool is used to both locate and shift the sleeve and can be incorporated into a treatment tool taught therein, such as a frac tool. 
     Mechanical Shifting Tool 
     In Applicant&#39;s U.S. Pat. No. 10,472,928, incorporated herein by reference in its entirety, in embodiments a bottom hole sleeve actuator comprises dogs supported by radially controllable arms. In the &#39;644 Application, a shifting tool was disclosed using keys or dogs for engaging a sleeve profile  14  of sleeves  12  of sleeve valves  10  located along a casing string  8 . The shifting tool is incorporated as part of a BHA that is conveyed on a tubing string such as coiled tubing (CT). Dogs at the ends of radially controllable, circumferentially spaced support arms are actuated radially with a radial restraining means for controlling the radial positioning of the arms and dogs thereon. The dogs and arms are actuated radially inward with the restraining means to overcome radially outward biasing of the arms for uninhibited axial movement of the BHA through the wellbore. The dogs and arms can be released radially outwards for sleeve locating and sleeve profile engagement. The dogs can further be positively locked in the sleeve profile  14  for opening and closing of the sleeve  12 . 
     As introduced in the &#39;644 Application for a sleeve having a profile therein, the dogs of the shifting tool disclosed therein locate and engage the sleeve profile  14  intermediate the sleeve for sleeve release, opening, and closing. Manipulation of the arms and dogs is achieved using uphole and downhole movement of a shifting mandrel of a mechanical shifting mechanism having the restraining means fixed thereto, and a cam profile on the dog-supporting arms. The shifting mandrel can be moved axially relative to a housing of the shifting tool having the arms and dogs mounted thereon. The restraining means is a cam-encircling restraining ring supported on the shifting mandrel. 
     In embodiments described in the &#39;644 Application, a tubing-conveyed system was provided comprising an actuating or shifting tool as described above that is used to sequentially manipulate a large number of sleeve valves located along a casing string  8  extending downhole in an oil or gas well. The well can be a vertical, deviated, or horizontal well. The shifting tool engages a sleeve and opens or closes the sleeve in its respective sleeve housing via uphole and downhole movement of the CT and shifting tool. Each sleeve valve can be manipulated, at any time, and for various reasons without tripping the tool from the wellbore. The shifting tool can be conveyed on the conveyance string, and incorporated with other components of a BHA conveyed on the conveyance string. 
     In greater detail, Applicant&#39;s BHA, as described in the &#39;644 Application, is configured for run-in-hole (RIH) mode for free movement through downhole-to-open sleeve valves  10  and a downhole string such as a completion string  8 . The sleeve valves  10  can comprise a tubular sleeve housing  16  fit with a tubular sleeve  12  as described above. Each sleeve  10  has an annular recess or dog-receiving sleeve profile  14  formed intermediate along its length for location and shifting of the sleeve using the shifting tool. The sleeve  12  is shiftable for opening and closing ports  18  in the housing  16 . The profile  14  is annular and has a generally right angle uphole interface for positive sleeve profile locating purposes. 
     The shifting tool of the &#39;644 Application relies purely on mechanical actuation of the shifting tool via forces conveyed from surface through the CT to the BHA, and relative movement of the shifting mandrel relative to the housing of the shifting tool, to actuate the dogs to their various positions for locating, engagement with, and actuation of the sleeve valves  10 . Such relative movement of shifting tool components inhibits the use of electronic components on the BHA with electric connections to surface. 
     As taught in Applicant&#39;s US published application US20200024916A1, incorporated herein by reference in its entirety, a BHA having a shifting tool comprising a repositioning sub is used to open a sleeve with packer located outside the sleeve using fluid pressure. 
     As taught in Applicant&#39;s US published application US20210002980A1, incorporated herein by reference in its entirety, a BHA having a shifting tool uses a dual J-mechanism to pull up to open a sleeve and fluid pressure applied to a packer located downhole the sleeve to close an open sleeve. 
     Bottom Hole Assembly—Open-Only 
     Referring to  FIG.  1 A , an embodiment of an improved BHA  20  for use with a wireline  6  comprises an instrumentation sub  22  and a sleeve shifting tool  24 . The instrumentation sub  22  can comprise one or more sensors  26 , such as one or more of the following: a  3 D directional sensor, a sensor adapted to measure pressure, a sensor adapted to determine axial movement, a sensor adapted to determine rotational movement, a temperature sensor, an axial force sensor and an accelerometer. The sleeve shifting tool  24  is adapted for actuating sleeve valves  10  within the borehole between a closed position and an open position, and comprises a housing  16  supporting a set of electrically-actuated dogs  30 . The shifting tool  24  can further comprise an electrically-actuated sealing mechanism  50 . In embodiments, the dogs  30  and the sealing mechanism  50  are hydraulic elements actuated by electric pumps. The instrumentation sub  22  can be located uphole or downhole of the sealing mechanism  50 , or the BHA  20  can have two instrumentation subs  22 , one sub  22  located uphole of the sealing mechanism  50  and the other sub  22  located downhole thereof. The instrumentation sub  22  can also house the electronic components necessary for actuating the electrically-actuated components of the BHA  20 . 
     The sensors  26  located in the instrumentation sub  22  are useful for efficient operation of the methods disclosed herein. For example, the pressure sensor assists in determining the setting of packer and when pressure has equalized across a packer of the sealing mechanism  50  of the BHA  20  and the axial force sensor assists in determining wireline load and when the dogs  30  of the shifting tool  24  have engaged with a sleeve profile  14  of a target sleeve  12 . Further, the sensors  26  allow real-time monitoring of pressure and temperature during fracturing operation both above and below the BHA  20  using appropriately positioned pressure and temperature sensors. Real-time data from the instrumentation sub  22  also allows an operator during a fracturing operation to recognize a potential screen-out and take steps to recover therefrom. For example, prior to a fracturing operation plugging off completely, pump pressure builds. Using the instrumentation sub  22  having a pressure sensor allows the operator to observe the pressure build up in real time downhole in the wellbore  2  rather than waiting for the pressure build up to manifest at the surface. As plugging can take from about 30 seconds to several minutes, the real time information allows for a more timely responsive action, for example, by reducing sand concentration to avoid screen-out. 
     In embodiments, for location of the BHA  20  within the wellbore  2 , the BHA  20  further comprises an electronic casing collar locator  29  (CCL) which is capable of detecting casing collars located along the casing string  8  and which may also be capable of detecting perforations. The instrumentation sub  22  also comprises electronics associated with the operation of the CCL  29 . For example, the CCL  29  can be configured to detect electric signals emitted by casing collars to determine the location of the BHA  20  in the wellbore  2 . The electronically-actuated CCL  29  is useful throughout the completion operation for accurately determining the positioning of the BHA  20 . Use of the sensors  26  of the instrumentation sub  12  and the CCL  29  provide the ability to confirm that the correct sleeve valves  10  are being opened, that the isolation is being set up in the correct location and that the isolation is working as intended by monitoring the sensors of the instrumentation sub  22 , which is difficult to accomplish using CT-mounted mechanical BHAs and ball/dart drop systems. 
     In embodiments, the sleeve shifting tool  24  is connected to the downhole end of a wireline  6  and comprises a housing  28 , a constrictor  38 , a constrictor drive  32  located in or connected to the housing  28  and operatively connected to the constrictor  38 , one or more radially extending dogs  30 , a protective sleeve  39 , and a sealing mechanism  50 . Referring to  FIG.  1   , each dog  30  is supported on a corresponding pivotable arm  34 . Each pivotable arm  34  is attached at one end to the dog  30  and at the other end to the housing  28 . Each dog  30  is shaped and sized to engage the sleeve profiles  14  of the sleeves  12 . In embodiments, the casing  8  is 4.5 inches to 5.5 inches in diameter with a pressure rating of at least 15,000 to 20,000 pounds per square inch (psi). In embodiments, the sleeve profiles  14  comprise a downhole engagement shoulder or an uphole engagement shoulder of the sleeves  12  located at a downhole end or an uphole end of the sleeves  12 , as appropriate. 
     Referring to  FIGS.  1 A and  3   , the constrictor  38  is actuated by the constrictor drive  32 . In embodiments, each dog  30  has three functional positions: (1) a sleeve profile-engaged position (SET) wherein the position of the pivotable arm  34  is locked in a radially outward position for engagement with a sleeve profile  14 ; (2) a radially outward biased position (LOC) for locating a sleeve profiles  14 ; and (3) a radially inward collapsed position (RET) for uninhibited movement of the BHA  20  through the casing  8  and sleeve valves  10 . As each pivotable arm  34  pivots at its connection at the housing  28 , the pivotable arm  34  may also be in any position between (1) and (3). 
     Referring to  FIG.  1 A , each pivotable arm  34  has a corresponding spring  36  that is used to bias the corresponding dog  30  outwardly from the wireline  6 . The arms  34  are located radially within constrictor  38 . The constrictor  38  is axially actuable relative to the housing  28  by the constrictor drive  32 . When the constrictor  38  is moved axially uphole relative to the housing  28 , the dogs  30  are forced radially inward and when the constrictor  38  is moved axially downhole relative to the housing  28 , the dogs  30  move radially outward due to the biasing of the springs  26 . 
     The constrictor drive  32  can be an electric motor configured to axially actuate the constrictor  38 . In other embodiments, the constrictor drive  32  can comprise an electric fluid pump connected to a fluid reservoir and configured to actuate a piston coupled to the constrictor  38 . Instructions regarding actuation of the constrictor  38  are sent from surface and communicated to the constrictor drive  32  via the wireline  6 . 
     The arms  34  and the dogs  30  are held against the casing  8  with the force of the spring  36  and this force can be adjusted on a per dog basis or group basis as the case may be, such as via cam profiles of the arms  34 . The springs  36  may be steel springs. Biasing springs can be cantilevered leaf or collet-like springs, the ends of each leaf radially biasing the dog arms outwardly. The force on the dogs  30  is also balanced even if the tool is not centralized in the wellbore  2 . Only one dog  30  is required to engage the sleeve profile  14  to detect that the BHA  20  has located a sleeve  12 . The dogs  30  are designed in such a way that one dog  30  alone can withstand the entire load capacity at surface. The force generally required to open a sleeve is around 5,000 pounds. 
     Referring to  FIGS.  1 A and  3   , the sleeve profiles  14  and dogs  30  can be designed such that the dogs  30  do not locate and become caught in any gap or profile other than the sleeve profiles  14 . For example, the dogs  30  can be configured to pass over annular gaps present between the bottom of the sleeve  12  and the sleeve housing  16  when the sleeve  12  is in the uphole closed position and the BHA  20  is being pulled uphole with the dogs  30  in the LOC position to locate the sleeve profile  14 . For example, with reference to  FIGS.  1 A and  3   , the inner diameter of the sleeves  12  can taper radially outwards towards their uphole and downhole ends such that the dogs  30  pass over said ends and do not engage them. When the BHA  20  is pulled uphole with the dogs  30  in the LOC position, the dogs  30  engage the locating profile  14  of a sleeve  12  as the BHA  20  passed thereby as discussed above, preventing the BHA  20  from traveling further uphole and providing positive indication, for example about 5,000 to about 10,000 daN, that the sleeve  12  has been located. 
     Referring to  FIGS.  2 A to  2 C , an alternative sleeve locating and shifting device  24  using pins or fingers  44  and an actuation mandrel  42  is disclosed, which can be used in place of the dogs  30  and constrictor  38  described above. The sleeve locating and shifting device  40  comprises a set of fingers  44  sized and shaped to engage the sleeve profiles  14  of the sleeves  12  and pass over other profiles of the casing string  8  and sleeve valves  10 . The fingers  44  are orientated radially from the shifting tool  14  and extendable radially to three functional positions: (1) a sleeve profile-engage position (SET) wherein the fingers  44  are locked in a radially outward position for engagement with a sleeve profile  14 ; (2) a radially outward biased position (LOC) used for locating the sleeve profiles  14  of sleeves  12 ; and (3) a radially retracted position (RET). The radial extension of the fingers  44  correspond to the relative axial position of a mandrel  42  axially moveable within the shifting tool  14  and having at least three distinct diameters. Each diameter corresponds to one of the positions (1) to (3) specified above respecting the functional positions of the fingers  44 . The fingers  44  are radially inwardly biased with resilient biasing means, such as springs  48 . The mandrel  42  is configured to actuate between three axial positions corresponding to the functional positions of the fingers  44 . The three diameters can have gradual transitions between them to push the fingers  44  radially outwards when translating the mandrel  42  to move a larger diameter axially in-line with the fingers  44 . Referring to  FIG.  2 D , in embodiments, the diameter of the mandrel  42  corresponding to the LOC position can have a tapering diameter. 
     With reference to  FIGS.  2 A to  2 C , in another embodiment, the shifting tool  24  can have hydraulically actuated fingers  44  oriented radially and having three functional positions: (1) a sleeve profile-engage position (SET) wherein the fingers  44  are locked in a radially outward position for engagement with a sleeve profile  14 ; (2) a radially outward biased position (LOC) used for locating the sleeve profiles  14  of sleeves  12 ; and (3) a radially retracted position (RET). An electric pump in communication with a fluid reservoir of the shifting tool  24  can control fluid pressure applied to the fingers  44 . The fingers  44  can be radially inwardly biased such as by a spring. In the SET mode, the pump increases the hydraulic pressure applied to the fingers  44  to drive them radially outwards to engage the sleeve profile  14 . In the LOC mode, the pump applies a hydraulic pressure less than that applied in the SET mode to radially bias the fingers  44  outwards while still permitting the BHA  20  to move through the casing  8  and sleeve valve  10 . In the RET mode, the pump can apply little or no pressure such that the fingers  44  are retracted radially inward due to the radially inward biasing, thus permitting the BHA  20  to move freely through the casing  8  and sleeve valves  10 . 
     A mandrel drive  46  can be operatively connected to the mandrel  42  to actuate it axially and thus actuate the fingers  44  to their various functional positions. The mandrel drive  46  can be an electric motor configured to actuate the mandrel  42 . In other embodiments, the mandrel drive  46  can comprise an electric fluid pump connected to a fluid reservoir and configured to actuate a piston coupled to the mandrel  42 . Instructions regarding actuation of the mandrel  42  are sent from surface and communicated to the mandrel drive  46  via the wireline  6 . 
     In the LOC position, the mandrel drive  46  can apply a constant force on the mandrel  42  to overcome the radially inward bias of the springs and apply a constant radially outward force on the fingers  44 , such that the fingers  44  drag along the casing  8  and sleeve valves  10  as the BHA  20  moves therealong to locate a sleeve  12 . Such constant radially outward force is further assisted by the mandrel  42  having a tapering diameter. 
     Referring to  FIG.  1 A , in embodiments, a protective tubular sleeve  39  is located on the wireline  6  extending uphole from the sleeve shifting tool  24 . The protective tubular sleeve  39  can be made of any material suitable to resist wear from proppant fluid and should extend uphole at least to an axial location where the wireline  6  will be exposed to treatment/fracturing fluid F in the treatment area and at least uphole of the sleeve  12 . For example, the protective sleeve  39  can be positioned to the area of the wireline  6  adjacent flow ports  18  of the sleeve housing  16  when the BHA  20  is engaged with the sleeve profile  14 . The protective sleeve  39  may comprise a rope socket or any other appropriate protective means. 
     Referring to  FIG.  1 A , in embodiments, the sealing mechanism  50  can provide an annular seal between the BHA  20  and casing  8  and is located downhole from the dogs  30 . In other embodiments, as shown in  FIGS.  4 B- 4 F , the sealing mechanism  50  can be located uphole from the dogs  30 . The sealing mechanism  50  comprises an elastomeric sealing element  52  such as a packer, a fluid reservoir  54  and a pump  56 . The pump  56  is electrically actuable and pumps fluid from the fluid reservoir  54  into the elastomeric sealing element  52 , thereby actuating or inflating the elastomeric sealing element  52 . In embodiments, when the sealing mechanism  50  is released, fluid is pumped by the pump  56  from the elastomeric sealing element  52  into the fluid reservoir  54  to deflate the sealing element  52 . In embodiments, the sealing mechanism  50  can further comprise a bypass pressure valve across the uphole and downhole sides of the sealing element  52  as a further safety measure in the event the process does not function as expected. 
     In other embodiments, the sealing mechanism  50  can be actuated by any other suitable sealing actuation mechanism. For example, the sealing mechanism  50  can comprise an electric motor or hydraulic pump configured to actuate a piston to axially compress the sealing element  52  such that it expands radially outwards. Compressing the sealing element  52  a sufficient extent results in a sealing engagement between the sealing element  52  and the casing  8  or a sleeve  12 . 
     As shown in  FIGS.  4 B- 4 F , the packer  52  of the sealing mechanism  50  can be located on the BHA  20  so as to be set within a sleeve  12  once the dogs  30 /fingers  44  have located the sleeve profile  14  thereof. In other embodiments, as shown in  FIGS.  5 A- 7 I , the packer  52  can be located on the BHA  20  so as to be set in the casing  8  downhole of the sleeve  12 . The latter embodiments may enable shorter sleeve  12  to be used, as said sleeve  12  do not need to have sufficient axial length to accommodate the setting of the packer  52  therein. 
     Open and Close Embodiment 
     The bendable characteristic of wireline  6  makes it unable to exert a “pushing” force required to shift a sleeve in the downhole direction while the tensile strength of the wireline  6  limits its ability to exert a “pulling” force required to shift a sleeve  12  in the uphole direction. The downhole pushing force can be exerted on the BHA  20  by partially expanding the sealing mechanism  50  and pumping fluid down the annulus  4  between the wireline  6 /BHA  20  and the casing  8 . 
     Referring to  FIG.  1 B , another embodiment of the shifting tool  124  is shown having the capability to shift sleeves  12  in the uphole direction as well as the downhole direction. The dual action sleeve shifting tool  124  comprises the same components as the single action shifting tool  24 , and further comprises a slip mechanism  60  and stroking mechanism  70  that enables the sleeve shifting tool  124  to shift sleeves  12  in the uphole direction, for example to close a sleeve  12  after treatment of the formation therethrough. In embodiments, the slip mechanism  60  and the stroking mechanism  70  of the sleeve shifting tool  124  can be used to shift sleeves  12  in the downhole direction, for example to close a sleeve  12  prior to treatment of the formation therethrough. The stroking mechanism  70  comprises a telescoping piston  72  capable of axially extending and retracting from the BHA housing  28 . The arms  34  and dogs  30  supported thereon are mounted on the stroking mechanism  70 . The stroking mechanism  70  can be axially actuated with a stroking drive  74  in the BHA so as to axially shift the piston  72 , and the dogs  30  and arms  34 , uphole and downhole. The slip mechanism  60  is secured to the BHA housing  28 . When the BHA housing  28  is axially secured in the casing  8  such as with slip mechanism  60 , and the dogs  30  are engaged with the sleeve profile  14  of a sleeve  12 , the stroking mechanism  70  can be actuated to axially manipulate the sleeve  12  between the open and closed positions. The stroking mechanism  70  can have a stroke distance at least sufficient to enable it to actuate a sleeve  12  between the open and closed positions. 
     In embodiments, the stroking drive  74  can be an electric pump connected to a fluid reservoir and configured to hydraulically actuate the stroking piston  72  to telescopically actuate it between the extended and retracted positions relative to the BHA housing  28 . In other embodiments, the stroking drive  74  can be an electric motor configured to drive the stroking piston  72  between the extended and retracted positions relative to the BHA housing  28 . Any other suitable stroking drive  74  capable of actuating the stroking piston  72  between the extended and retracted positions may be used. 
     In embodiments, the stroking drive  74  is actuated independently of the constrictor drive  32 /mandrel drive  46 , while the constrictor  38  moves with the striking piston  72 . In this manner, movement of the dogs  30 /arms  34  with the stroking piston  72  does not change the functional position of the dogs  30 , but the constrictor  38  can be actuated independently of the stroking piston  72  to change the functional position of the dogs  30 . 
     Referring to  FIG.  1 B , in embodiments, the slip mechanism  60  comprises an electrically operated dual acting slip drive  62  and a slip arrangement  64  further comprising radially expandable slip elements  66  adapted to restrict axial movement in both uphole and downhole directions. The slip drive  62  can cause the slip elements  66  to radially expand and engage the casing  8 , restricting axial movement of the BHA housing  28 . In embodiments, the system of slips  60  has two functional modes: (1) disengaged with the slip elements  66  radially retracted; and (2) engaged with the slip elements  66  radially expanded and engaging the casing  8 . 
     In an embodiment, the slip drive  62  can comprise an electric pump connected to a fluid reservoir and configured to pump fluid from the fluid reservoir into a fluid bladder radially inward of the slip elements  66 . Expanding the bladder with the electric pump results in the slip elements  66  being radially expanded, while deflating the bladder with the pump results in the slip elements  66  being radially retracted. In another embodiment, the slip drive  62  can comprise an electric motor coupled to an annular cone configured to be axially driven into and away from radially inwardly biased slip elements  66 . Driving the annular cone toward the slip elements  66  pushes said elements radially outward, while driving the cone away from the slip elements  66  permits the slip elements  66  to radially retract inward. In yet another embodiment, the cone can be coupled to a hydraulic piston which is driven using an electric pump. Any other suitable means of actuating the slips  60  between the engaged and disengaged positions may be used. 
     In embodiments, one or more of the constrictor drive  32 /mandrel drive  46 , sealing element pump  56 , slip drive  62 , and stroking drive  74  can be part of an integrated system. For example, all of the above drives can be hydraulic systems in communication with a common fluid reservoir, but having their own discrete pumps for actuating their respective devices. 
     Operation—Single Action 
     In use, having reference to  FIG.  1 A , a single-acting BHA  20  deployable using electrically-enabled wireline  6  is shown. When deployed into the wellbore  2 , an annulus  4  is formed between the BHA  20  and the casing  8 . 
     The BHA  20  comprises at least a sleeve shifting tool  24  and an instrumentation sub  22  further comprising a plurality of sensors  26 . 
     In an embodiment, the BHA  20  is electrically connected to a distal end of the wireline  6 . Electrical connection between the wireline  6  and the BHA&#39;s components can be accomplished in a number of ways, including but not limited to conductors extending therefrom through a bore of the BHA  20  or conductors extending therefrom through an electrical race formed about a periphery of the BHA&#39;s components. Electrical communication between surface and the components of the BHA  20  is thereby enabled via the connection with the wireline  6 . 
     The casing  8  comprises a plurality of the ported sliding sleeve subs  10  spaced along the casing  8  or in a liner in the wellbore  2 . The sleeves  12  of the sleeve subs  10  can be opened for permitting fluid communication through ports  18  formed in the sleeve housing  16 . 
     Lubrication can be applied to the BHA  20  prior to deployment. Referring to  FIGS.  4 A and  5 A , in embodiments, the BHA  20  is positioned at the toe of the wellbore  2 , or downhole of the most distal sleeve valve  10  from surface, by pumping fluid F. For example, for added conveying force, fluid F can be pumped down the wellbore  2  with the sealing mechanism  50  partially expanded so as to substantially fill the annulus  4  but not so much so as to engage the casing  8  and inhibit axial movement of the BHA  20 . The sensors  26  and instrumentation sub  22  provide real-time readings, for example of axial tension force and pressure differential across the sealing mechanism  50 , allowing the operator to adjust flow, packer expansion, and any other parameters while the BHA  20  is being run in hole. The casing collar locator  29  can also assist in correctly positioning the BHA  20  in the wellbore  2 . Referring to  FIGS.  4 B and  5 B , once the BHA  20  has been positioned below a selected sleeve valve  10 , the dogs  30  of the BHA  20  are electrically actuated to the radially outward biased LOC position to engage the casing walls in locate mode with an amount of force that still permits some axial movement of the BHA  20  in the casing  8 . Referring to  FIGS.  4 B and  5 C , the BHA  20  can then be pulled by the wireline  6  uphole in the LOC mode such that the dogs  30  locate the sleeve profile  14  of the target sleeve valve  10  and extend therein once located. Referring to  FIG.  4 D , once the extended dogs  30  have located the sleeve profile  14 , they are locked therein by actuating the dogs  30  to the SET mode. The location of the sleeve profile  14  by the dogs  30  is indicated by an increased axial tension force, which can be measured in real-time by the sensors  26  and observed by the operator at surface. In embodiments, the downhole end of the sleeve housing  16 , the locating collar or lengths of adjacent casing are aggressively profiled to assist detection by the extended dogs  30 . 
     Referring to  FIGS.  4 C and  5 C , in embodiments, when the extended dogs  30  have located the sleeve profile  14 , the packer element  52  is located below the ports  18  of the sleeve valve  10 . In embodiments, as shown in  FIG.  4 C , the sleeve  12  is of a sufficient length to permit the packer  52  to be set therein. In such circumstances, the packer  52  can be electrically-actuated to sealingly engage the sleeve  12  and act to isolate the wellbore  2  therebelow. In embodiments wherein the sleeve  12  does not have sufficient length to permit the packer  52  to be set therein, such as the embodiment shown in  FIG.  5 C , the packer  52  can remain partially expanded and set once the sleeve  12  has been shifted to the open position. In embodiments, if desired, the packer  52  can be expanded further without fully setting in the casing  8  to reduce the amount of fluid flow past the partially expanded packer  52  while still allowing the BHA  20  to move axially within the casing  8 . 
     Referring to  FIGS.  4 C and  5 D , the sleeve  12  can be opened utilizing fluid F to push the packer  52  and sleeve  12  downhole and shift the sleeve axially to the open position. The wireline  6  can be slacked appropriately prior to actuating the sleeve  12  downhole to allow the associated movement without straining the wireline  6 . In embodiments wherein the packer  52  is configured to be set within the sleeve  12 , the packer  52  can be fully set within the sleeve  12  prior to pumping fluid downhole to shift the sleeve  12 . In embodiments wherein the packer  52  is configured to be set in the casing  8 , the packer  52  may not be expanded fully so as to permit the BHA  20  to move downhole while still creating sufficient pressure differential across the packer  25  to apply the requisite force to shift the sleeve  12 . 
     Referring to  FIGS.  4 D and  5 E , the setting of the packer  52  isolates the wellbore  2  below the flow ports  18  of the target sleeve valve  10  such that it is ready for treatment with fracturing fluid F. Fluid F can then be pumped through the now exposed ports  18  of the opened sleeve valve  10  to treat the formation therebeyond. During treatment, moderate tension can be maintained on the wireline  6  to prevent fluid compressing the wireline  6  and causing the formation of birdcages. During fracturing, data from the sensors  26  is provided in real-time to the operator, including pressure, isolation differential pressure and tension or compression on the wireline  6 . Other sensor data can be obtained with appropriate sensors  26  incorporated in the instrumentation sub and/or other parts of the BHA  20 . 
     Referring to  FIG.  5 F , in embodiments, once the treatment of the formation through the target sleeve valve  10  is completed, the packer  52  is deflated and the pressure above and below packer  52  is allowed to equalize. For example, the pressure differential may go from about 1,500 psi to 0 psi. The dogs  30  can remain engaged in the sleeve profile  14  of the sleeve  12  to reduce strain on the wireline  6 . Once the pressure has equalized, the dogs  30  are retracted to the RET mode to release the BHA  20  and the wireline  6  can be pulled to locate the BHA  20  to the next target sleeve valve  10  uphole. 
     With reference to  FIGS.  6 A- 6 F , the opening and treatment through a target sleeve valve  10  using a BHA  20  having fingers  44  instead of dogs  30  can be performed in substantially the same manner. 
     Operation—Dual Action 
     Referring to  FIGS.  4 E- 4 G and  7 A- 7 I , a modified dual action BHA  120  having a stroking mechanism  70  and slip mechanism  60  can be used to both open and close sleeve valves  10 . 
     Referring to  FIG.  7 A , the location of the dual action BHA  120  in the wellbore  2  is performed in a similar manner as with the single action BHA  20  by partially expanding the packer  52  and pumping fluid downhole with the dogs  30 /fingers  44  in the radially retracted RET mode. 
     With reference to  FIGS.  4 E and  7 B , with the stroking mechanism  70  in the extended position, the dogs  30 /fingers  44  of the BHA  120  can be actuated to the radially outwardly biased LOC mode and the BHA  120  pulled uphole to locate the sleeve profile  14  of the target sleeve valve  10 . 
     Referring to  FIGS.  4 F and  7 C , once the sleeve profile  14  has been located by the dogs  30 /fingers  44 , the dogs  30 /fingers  44  can be actuated to the SET mode to lock them in the profile  14 . 
     With reference to  FIGS.  7 Di and  7 Ei , in an embodiment, the sleeve  12  can be opened utilizing fluid F to shift the sleeve axially to the open position. Referring to  FIG.  7 Di , the stroking mechanism  70  can actuated to the retracted position prior to shifting in preparation for use later to close the sleeve  12 . The packer  52  can also be set to form a sealing engagement with the sleeve  12  or the casing  8 . Referring to  FIG.  7 Ei , in an embodiment, the sleeve  12  can be opened utilizing fluid F to push the packer  52  and sleeve  12  downhole and shift the sleeve axially to the open position. The wireline  6  can be slacked appropriately prior to actuating the sleeve  12  downhole to allow the associated movement without straining the wireline  6 . In embodiments wherein the packer  52  is configured to be set within the sleeve  12 , the packer  52  can be fully set within the sleeve  12  prior to pumping fluid downhole to shift the sleeve  12 . 
     With reference to FIGS.  7 Dii and  7 Eii, in an embodiment, the sleeve  12  can be opened using the stroking mechanism  70 . Referring to FIG.  7 Dii, the packer  52  can also be set to form a sealing engagement with the sleeve  12  or the casing  8 . Referring to FIG.  7 Eii, with the dogs  30 /fingers  44  in the SET mode, the slip mechanism  60  can be actuated to the engaged position to secure the BHA housing  28  to the casing  8 . In an embodiment, the stroking mechanism  70  can be used to open the sleeve. In embodiments, the stroking mechanism  70  can be actuated to the retracted position to move the dogs  30 /fingers  44  downhole. As the BHA housing  28  is anchored in the casing  8  with the slip mechanism  60 , the sleeve  12  is pulled downhole by the dogs  30 /fingers  44  to the open position. 
     In embodiments wherein the packer  52  is set within the sleeve  12 , fluid F can also be pumped downhole to assist the stroking mechanism  70  in actuating the sleeve  12  downhole where the stroking mechanism  70  is configured to be collapsible under fluid F pressure but otherwise extendible using electrical actuation. 
     With reference to  FIGS.  4 G and  7 F , the formation can then be treated through the opened sleeve valve  10 . If not already engaged, the slip mechanism  60  can be actuated to the engaged position to secure the BHA housing  28  to the casing  8 . After treatment is complete, to close the sleeve  12 , with reference to  FIG.  7 G , the stroking mechanism  70  can be actuated back to the extended position with the dogs  30 /fingers  44  still engaged in the sleeve profile  14  to push the sleeve  12  uphole to the closed position. 
     With reference to  FIGS.  7 H and  7 I , after the sleeve  12  has been closed, the packer  52  can be deflated, the dogs  30 /fingers  44  actuated to the radially retracted RET mode, and the slip mechanism  60  actuated to the disengaged position, such that the BHA  120  is free to be repositioned downhole of the next target sleeve valve  10 . 
     As the components of the BHA  120  are electrically actuated via instructions form surface communicated through the wireline  6 , each of the components can be actuated independently, and in variations of the order as described above, without mechanical cycling of the BHA  120  through various functional modes. 
     Sensor data provided by the BHA  20 / 120  in real-time allows the operator to continuously monitor information relating to wireline tension, temperature and pressure in order to ensure that the BHA  20 / 120  and other equipment is operating under specified conditions. Further, real-time data relating to tension, pressure, temperature and various movement allows the operator to confirm that dogs have been locked or released, slips and packers have been set or released and pressure differentials have been established or allowed to equalize. By being able to confirm that a step has successfully been completed prior initiating the next, the process can be conducted with less chance of error and possible damage to the BHA and other equipment. Additionally, the rate of proppant fluid flow can be controlled to maximize efficacy of the treatment process and reduce chance of excessively wearing or damaging the wireline, BHA and other equipment. 
     Methods of Use 
       FIG.  9    is a flowchart for example method  900  for deploying a BHA for fracturing operations connected by wireline in a casing of a wellbore. Referring to  FIG.  9   , at block  905 , fluid is pumped fluid into the wellbore to position the BHA. At block  910 , a shifting tool element of the BHA is radially extended to a biased position to engage walls of a sleeve. At block  915 , the BHA is pulled by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve. At block  920 , the shifting tool element of the BHA is set to an engaged position to axially lock the shifting tool element to the sleeve. At block  925 , a sealing element in the casing is set to isolate an annular area between the wellbore and the BHA. At block  930 , fluid is pumped into the wellbore to open the sleeve. At block  935 , fracturing fluid is pumped into the annular area. At block  940 , the sealing element is unset in the casing. At block  945 , wait for pressure uphole and downhole the sealing element to equalize. At block  950 , the shifting tool element is retracted to a collapsed position. At block  955 , the BHA is pulled uphole with wireline to the next sleeve. 
       FIG.  10    is a flowchart for example method  900  comprising additional steps for method for  900  of  FIG.  9   . Referring to  FIG.  10   , at block  1005 , fluid is pumped into the wellbore to position the BHA. At block  1010 , a shifting tool element of the BHA is radially extended to a biased position to engage walls of a sleeve. At block  1015 , the BHA is pulled by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve. At block  1020 , the shifting tool element of the BHA is set to an engaged position to axially lock the shifting tool element to the sleeve. At block  1025 , a sealing element is set in the casing to isolate an annular area between the wellbore and the BHA. At block  1030 , fluid is pumped into the wellbore to open the sleeve. At block  1035 , a set of slips is set to engage the casing. At block  1040 , fracturing fluid is pumped into the annular area. At block  1045 , the sealing element is unset in the casing. At block  1050 , wait for pressure uphole and downhole the sealing element to equalize. At block  1055 , the sleeve closed by axially stroking the shifting tool element while the BHA is axially fixed to the casing. At block  1060 , the shifting tool element is retracted to a collapsed position. At block  1065 , the BHA is pulled uphole with wireline to the next sleeve. 
       FIG.  11 A  is a flowchart for example method  900  comprising additional steps for method for  900  of  FIG.  9   . Referring to  FIG.  11 A , at block  1105 A, fluid is pumped into the wellbore to position the BHA. At block  1110 A, a shifting tool element of the BHA is radially extended to a biased position to engage walls of a sleeve. At block  1115 A, the BHA is pulled by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve. At block  1120 A, axial force on the wireline is measured using a sensor and axial force measurements are communicated through the wireline for observing wireline load. At block  1125 A, the shifting tool element of the BHA is set to an engaged position to axially lock the shifting tool element to the sleeve. At block  1130 A, a sealing element in the casing is set to isolate an annular area between the wellbore and the BHA. At block  1135 A, fluid is pumped into the wellbore to open the sleeve. At block  1140 A, fracturing fluid is pumped into the annular area. At block  1145 A, the sealing element is unset in the casing. At block  1150 A, wait for pressure uphole and downhole the sealing element to equalize. At block  1155 A, the shifting tool element is retracted to a collapsed position. At block  1160 A, the BHA is pulled uphole with wireline to the next sleeve. 
       FIG.  11 B  is a flowchart for example method  900  comprising additional steps for method for  900  of  FIG.  9   . Referring to  FIG.  11 B , at block  1105 B, fluid is pumped into the wellbore to position the BHA. At block  1110 B, a shifting tool element of the BHA is radially extended to a biased position to engage walls of a sleeve. At block  1115 B, the BHA is pulled by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve and measuring axial force on the wireline using a sensor and communicating axial force measurements through the wireline to determine whether the shifting tool element is in a biased position, an engaged position or a collapsed position. At block  1120 B, the shifting tool element of the BHA is set to an engaged position to axially lock the shifting tool element to the sleeve. At block  1125 B, a sealing element is set in the casing to isolate an annular area between the wellbore and the BHA. At block  1130 B, fluid is pumped into the wellbore to open the sleeve. At block  1135 B, fracturing fluid is pumped into the annular area. At block  1140 B, the sealing element is unset in the casing. At block  1145 B, wait for pressure uphole and downhole the sealing element to equalize. At block  1150 B, the shifting tool element is retracted to a collapsed position. At block  1155 B, the BHA is pulled uphole with wireline to the next sleeve. 
       FIG.  11 C  is a flowchart for example method  900  comprising additional steps for method for  900  of  FIG.  9   . Referring to  FIG.  11 C , at block  1105 C, fluid is pumped into the wellbore to position the BHA. At block  1110 C, a shifting tool element of the BHA is radially extending to a biased position to engage walls of a sleeve. At block  1115 C, the BHA is pulled by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve. At block  1120 C, the shifting tool element of the BHA is set to an engaged position to axially lock the shifting tool element to the sleeve. At block  1125 C, a sealing element is set in the casing to isolate an annular area between the wellbore and the BHA and measuring pressure proximate the sealing element using a sensor and communicating pressure measurements through the wireline to determine whether the sealing element is in a sealing position or a released position. At block  1130 C, fluid is pumped into the wellbore to open the sleeve. At block  1135 C, fracturing fluid is pumped into the annular area. At block  1140 C, the sealing element is unset in the casing. At block  1145 C, wait for pressure uphole and downhole the sealing element to equalize. At block  1150 C, the shifting tool element is retracted to a collapsed position. At block  1155 C, the BHA is pulled uphole with wireline to the next sleeve. 
       FIG.  11 D  is a flowchart for example method  900  comprising additional steps for method for  900  of  FIG.  9   . Referring to  FIG.  11 D , at block  1105 D, fluid is pumped into the wellbore to position the BHA. At block  1110 D, a shifting tool element of the BHA is radially extended to a biased position to engage walls of a sleeve. At block  1115 D, the BHA is pulled by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve. At block  1120 D, the shifting tool element of the BHA is set to an engaged position to axially lock the shifting tool element to the sleeve. At block  1125 D, a sealing element in the casing is set to isolate an annular area between the wellbore and the BHA. At block  1130 D, fluid is pumped into the wellbore to open the sleeve. At block  1135 D, fracturing fluid is pumped into the annular area and pressure uphole and downhole of the sealing element in the wellbore is measured using sensors and pressure measurements are communicated through the wireline for confirming a level of isolation provided by the sealing element. At block  1140 D, the sealing element is unset in the casing. At block  1145 D, wait for pressure uphole and downhole the sealing element to equalize. At block  1150 D, the shifting tool element is retracted to a collapsed position. At block  1155 D, the BHA is pulled uphole with wireline to the next sleeve. 
       FIG.  11 E  is a flowchart for example method  900  comprising additional steps for method for  900  of  FIG.  9   . Referring to  FIG.  11 E , at block  1105 E, pumping fluid into the wellbore to position the BHA. At block  1110 E, a shifting tool element of the BHA is radially extended to a biased position to engage walls of a sleeve. At block  1115 E, the BHA is pulled by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve. At block  1120 E, the shifting tool element of the BHA is set to an engaged position to axially lock the shifting tool element to the sleeve. At block  1125 E, a sealing element in the casing is set to isolate an annular area between the wellbore and the BHA. At block  1130 E, fluid is pumped into the wellbore to open the sleeve. At block  1135 E, fracturing fluid is pumped into the annular area and measuring fluid pressure in the wellbore using a sensor and communicating pressure measurements through the wireline for observing parameters of a potential screen-out of the wellbore. At block  1140 E, the sealing element is unset in the casing. At block  1145 E, wait for pressure uphole and downhole the sealing element to equalize. At block  1150 E, the shifting tool element is retracted to a collapsed position. At block  1155 E, the BHA is pulled uphole with wireline to the next sleeve. 
       FIG.  12    is a flowchart for example method  1200  for deploying a BHA for fracturing operations connected by wireline in a casing of a wellbore. Referring to  FIG.  12   , at block  1205 , fluid is pumped into the wellbore to position the BHA. At block  1210 , a shifting tool element of the BHA is radially extended to a biased position to engage walls of a sleeve. At block  1215 , the BHA is pulled by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve. At block  1220 , the shifting tool element of the BHA is set to an engaged position to axially lock the shifting tool element to the sleeve. At block  1225 , a set of slips is set to engage the casing. At block  1230 , sleeve is opened by axially stroking the shifting tool element while the BHA is axially fixed to the casing. At block  1235 , a sealing element in the casing is set to isolate an annular area between the wellbore and the BHA. At block  1240 , fracturing fluid is pumped into the annular area. At block  1245 , the sealing element in the casing is unset. At block  1250 , wait for pressure uphole and downhole the sealing element to equalize. At block  1255 , the sleeve is closed by axially stroking the shifting tool element while the BHA is axially fixed to the casing. At block  1260 , the set of slips is released. At block  1265 , the shifting tool element is retracted to a collapsed position. At block  1270 , the BHA is pulled uphole with wireline to the next sleeve. 
       FIG.  13 A  is a flowchart for example method  900  comprising additional steps for method for  1200  of  FIG.  12   . Referring to  FIG.  13 A , at block  1305 A, fluid is pumped into the wellbore to position the BHA. At block  1310 A, a shifting tool element of the BHA is radially extended to a biased position to engage walls of a sleeve. At block  1315 A, the BHA is pulled by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve. At block  1320 A, axial force on the wireline is measured using a sensor and axial force measurements are communicated through the wireline for observing wireline load. At block  1325 A, the shifting tool element of the BHA is set to an engaged position to axially lock the shifting tool element to the sleeve. At block  1330 A, a set of slips is set to engage the casing. At block  1335 A, the sleeve is opened by axially stroking the shifting tool element while the BHA is axially fixed to the casing. At block  1340 A, a sealing element in the casing is set to isolate an annular area between the wellbore and the BHA. At block  1345 A, fracturing fluid is pumped into the annular area. At block  1350 A, the sealing element is unset in the casing. At block  1355 A, wait for pressure uphole and downhole the sealing element to equalize. At block  1360 A, the sleeve is closed by axially stroking the shifting tool element while the BHA is axially fixed to the casing. At block  1365 A, the set of slips is released. At block  1370 A, the shifting tool element is retracted to a collapsed position. At block  1375 A, the BHA is pulled uphole with wireline to the next sleeve. 
       FIG.  13 B  is a flowchart for example method  900  comprising additional steps for method for  1200  of  FIG.  12   . Referring to  FIG.  13 B , at block  1305 B, fluid is pumped into the wellbore to position the BHA. At block  1310 B, a shifting tool element of the BHA is radially extended to a biased position to engage walls of a sleeve. At block  1315 B, the BHA is pulled by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve and axial force on the wireline is measured using a sensor and axial force measurements are communicated through the wireline to determine whether the shifting tool element is in a biased position, an engaged position or a collapsed position. At block  1320 B, the shifting tool element of the BHA is set to an engaged position to axially lock the shifting tool element to the sleeve. At block  1325 B, a set of slips is set to engage the casing. At block  1330 B, the sleeve is opened by axially stroking the shifting tool element while the BHA is axially fixed to the casing. At block  1335 B, a sealing element in the casing is set to isolate an annular area between the wellbore and the BHA. At block  1340 B, fracturing fluid is pumped into the annular area. At block  1345 B, the sealing element is unset in the casing. At block  1350 B, wait for pressure uphole and downhole the sealing element to equalize. At block  1355 B, the sleeve is closed by axially stroking the shifting tool element while the BHA is axially fixed to the casing. At block  1360 B, the set of slips is released. At block  1365 B, the shifting tool element is retracted to a collapsed position. At block  1370 B, the BHA is pulled uphole with wireline to the next sleeve. 
       FIG.  13 C  is a flowchart for example method  900  comprising additional steps for method for  1200  of  FIG.  12   . Referring to  FIG.  13 C , at block  1305 C, fluid is pumped into the wellbore to position the BHA. At block  1310 C, a shifting tool element of the BHA is radially extended to a biased position to engage walls of a sleeve. At block  1315 C, the BHA is pulled by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve. At block  1320 C, the shifting tool element of the BHA is set to an engaged position to axially lock the shifting tool element to the sleeve. At block  1325 C, a set of slips is set to engage the casing. At block  1330 C, the sleeve is opened by axially stroking the shifting tool element while the BHA is axially fixed to the casing. At block  1335 C, a sealing element in the casing is set to isolate an annular area between the wellbore and the BHA and pressure proximate the sealing element is measured using a sensor and pressure measurements are communicated through the wireline to determine whether the sealing element is in a sealing position or a released position. At block  1340 C, fracturing fluid is pumped into the annular area. At block  1345 C, the sealing element is unset in the casing. At block  1350 C, wait for pressure uphole and downhole the sealing element to equalize. At block  1355 C, the sleeve is closed by axially stroking the shifting tool element while the BHA is axially fixed to the casing. At block  1360 C, the set of slips is released. At block  1365 C, the shifting tool element is retracted to a collapsed position. At block  1370 C, the BHA is pulled uphole with wireline to the next sleeve. 
       FIG.  13 D  is a flowchart for example method  900  comprising additional steps for method for  1200  of  FIG.  12   . Referring to  FIG.  13 D , at block  1305 D, fluid is pumped into the wellbore to position the BHA. At block  1310 D, a shifting tool element of the BHA is radially extended to a biased position to engage walls of a sleeve. At block  1315 D, the BHA is pulled by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve. At block  1320 D, the shifting tool element of the BHA is set to an engaged position to axially lock the shifting tool element to the sleeve. At block  1325 D, a set of slips is set to engage the casing. At block  1330 D, the sleeve is opened by axially stroking the shifting tool element while the BHA is axially fixed to the casing. At block  1335 D, a sealing element in the casing is set to isolate an annular area between the wellbore and the BHA. At block  1340 D, fracturing fluid is pumped into the annular area and pressure uphole and downhole of the sealing element in the wellbore is measured using sensors and pressure measurements are communicated through the wireline for confirming a level of isolation provided by the sealing element. At block  1345 D, the sealing element is unset in the casing. At block  1350 D, wait for pressure uphole and downhole the sealing element to equalize. At block  1355 D, the sleeve is closed by axially stroking the shifting tool element while the BHA is axially fixed to the casing. At block  1360 D, the set of slips is released. At block  1365 D, the shifting tool element is retracted to a collapsed position. At block  1370 D, the BHA is pulled uphole with wireline to the next sleeve. 
       FIG.  13 E  is a flowchart for example method  900  comprising additional steps for method for  1200  of  FIG.  12   . Referring to  FIG.  13 E , at block  1305 E, fluid is pumped into the wellbore to position the BHA. At block  1310 E, a shifting tool is radially extended element of the BHA to a biased position to engage walls of a sleeve. At block  1315 E, the BHA is pulled by the wireline uphole until the shifting tool element of the BHA engages recesses of the sleeve. At block  1320 E, the shifting tool element of the BHA is set to an engaged position to axially lock the shifting tool element to the sleeve. At block  1325 E, a set of slips is set to engage the casing. At block  1330 E, the sleeve is opened by axially stroking the shifting tool element while the BHA is axially fixed to the casing. At block  1335 E, a sealing element is set in the casing to isolate an annular area between the wellbore and the BHA. At block  1340 E, fracturing fluid is pumped into the annular area and measuring fluid pressure in the wellbore using a sensor and communicating pressure measurements through the wireline for observing parameters of a potential screen-out of the wellbore. At block  1345 E, the sealing element is unset in the casing. At block  1350 E, wait for pressure uphole and downhole the sealing element to equalize. At block  1355 E, the sleeve is closed by axially stroking the shifting tool element while the BHA is axially fixed to the casing. At block  1360 E, the set of slips is released. At block  1365 E, the shifting tool element is retracted to a collapsed position. At block  1370 E, the BHA is pulled uphole with wireline to the next sleeve. 
     Although a few embodiments have been shown and described, it will be appreciated by those skilled in the art that various changes and modifications can be made to those skilled in the art that various changes and modifications can be made to these embodiments without changing or departing from their scope, intent or functionality. The terms and expressions used in the preceding specification have been used herein as terms of description and not of limitation, and there is no intention in the use of such terms and expressions of excluding equivalents of the features shown and described or portions thereof.