Patent Publication Number: US-2021172305-A1

Title: Real-time system for hydraulic fracturing

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of U.S. Provisional Application 62/943,676, filed Dec. 4, 2019, the entirety of which is incorporated fully herein by reference. 
    
    
     FIELD 
     Embodiments herein relate to methods and apparatus used for completion of a wellbore and, more particularly, to methods for performing completion operations and monitoring in real-time, at surface, downhole conditions during completion operations. 
     BACKGROUND 
     Apparatus and methods are known for single-trip completions of deviated wellbores, such as horizontal wellbores. To date, unlike the drilling industry which commonly utilizes intelligent apparatus for drilling wellbores, particularly horizontal or deviated wellbores, the fracturing industry has relied largely on mechanically-actuated apparatus to perform a majority of the operations required to complete a wellbore. This is particularly the case with coiled tubing (CT) deployed bottom hole assemblies (BHA&#39;s), largely due to the difficulty in providing sufficient, reliable electrical signals and power from surface to the BHA and vice versa. Further, fracturing operations require relatively high flow rates through the CT, in the order of about 1 m 3 /min or greater. The bore restrictions necessitated by the inclusion of electronic equipment on existing instrumentation subs, such as those used in drilling operations, limits flow rates therethrough to an extent that is not conducive for fracturing operations. 
     It is known to deploy BHAs for completion operations using jointed tubular, wireline or cable, or coiled tubing (CT). Further, it is known to use wireline deployed within an interior of CT to electrically actuate conventional select-fire perforation charges and to transmit signals associated with casing-collar locators used in depth measurement, such as taught in U.S. Pat. No. 7,059,407 to Toman. 
     One class of prior methodology for performing fracturing operations is commonly referred to as “plug and perf”. Fracturing operations at multiple zones in a formation have used wireline-deployed electrically-actuated bridge plugs which are pumped into the wellbore. The known pump-down bridge plugs have a single, fixed diameter being slightly smaller than the wellbore for deployment into the wellbore and require a valve at a toe of the wellbore to remove fluid used to pump the bridge plug into place. As wireline is comparatively weak and cannot pull more than about 2500 lbs at surface, and much less at depth, the wireline cannot be reliably used to release or to pull the bridge plugs to surface. Thus, multiple bridge plugs must be used and left in the wellbore to be drilled out later, at considerable expense. After the bridge plug has been set, the casing is perforated with perforating guns located above the bridge plug. The bridge plug and the perforating guns are often deployed together so that both operations, isolating and perforating, can be done in the same wireline run. When the perforations have been shot, the wireline is pulled out of the hole and the fracture fluid is pumped through the casing. Once the fracture is completed, the steps of setting the bridge plug and perforating followed by pumping the frac are repeated for sequential uphole intervals until the fracturing job on the wellbore is complete. Following fracturing of all of the zones, the bridge plugs are drilled out. 
     In other embodiments, a plurality of sliding sleeve subs, each sub having pre-existing fracturing ports, are spaced along a casing string or a liner of a wellbore and located at zones of interest in the formation. The sliding sleeves of the sleeve subs are selectively opened to expose the pre-existing fracturing ports, minimizing the need to perforate the casing to access the formation therebeyond. In some cases, the sleeves can also be actuated back to a closed position for isolating portions of the formation from fluids flowing through the casing, such as when fracturing through the ports of other sleeves, or to permit the zone of the formation to “heal”. The sleeve subs can be opened using a variety of conventional sleeve opening and closing techniques, including, but not limited to, setting a packer of a BHA within the sleeve, expanding the packer element, and thereafter utilizing a tensile pull for or fluid flow in the annulus to force the first packer and sleeve to shift the sleeve axially therein. Other sleeve actuation techniques involve electronically or mechanically actuating a shifting tool incorporated in a BHA installed on CT to engage and axially shift the sleeve, or by actuating a rotational opening tool to engage and rotate the sleeve to an open position. Alternatively, differential pressure can be used to hydraulically open the sleeve. 
     In fracturing operations using sleeve subs, a shifting tool is run in hole, typically on CT having a BHA at a distal end that is fit with the shifting tool. The CT is run into the wellbore and the shifting tool is used to selectively engage and actuate the sliding sleeves to establish or shut off communication between the wellbore and the various zones in the formation. Once the shifting tool has engaged a target sleeve, the CT is manipulated to selectively open the sleeve and expose the fracturing ports at said sleeve. A packer set below the fracturing ports directs fracturing fluid to exit the wellbore through open ports thereabove. In embodiments, the shifting tool can also close selected sleeves, such as to permit the formation to heal, or enable fracturing through opened ports in other sleeves therebelow. Treatment fluid can be delivered to the selected zone of the formation through the annulus between the casing and the CT, through the CT, or through both at the same time. Typical sleeve-shifting BHA&#39;s comprise mechanically-operated downhole tools having telescoping mandrels, packers and tubing, controlled by axially delimited J-mechanisms for selecting a variety of operating modes of the shifting tool. While reliable, the axially reciprocating components of the shifting tool introduce challenges as described below. 
     As will be appreciated by those of skill in the art, the acquisition of downhole conditions before, during, and after fracturing is performed is useful to 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 fracturing stages. Downhole conditions are determined with electronic sensors and the data is typically stored in memory located in tools carried by the BHA. In conventional methods, the data pertaining to downhole conditions is stored in memory and reviewed at surface after the BHA is pulled out of hole. A disadvantage of storing sensor data to on-board memory is that the downhole conditions are not known until such operations are completed and the BHA has been retrieved to surface. As such, the operator cannot adjust the operating parameters of the BHA and fracturing operation to respond to changes in downhole conditions as they arise in real-time, or near real-time. 
     Real-time tools have been applied in drilling operations and the like. Downhole parameters related to the downhole drilling environment and parameters are not directly ascertainable at surface. As such, the operator is typically only provided with surface feedback, such as torque and string weight variation to estimate downhole performance. Absent direct downhole data, which may be located thousands of meters distant from surface, too much or too little string weight can be applied at surface, resulting in downhole tool damage or ineffective rate of penetration. Accordingly, coiled-tubing conveyed BHAs capable of acquiring direct, real-time downhole data and delivering said data to surface may be used, such as that disclosed in published international application WO 2018/137027 to Timberstone Tools Inc, Canada, incorporated herein in its entirety. An electrically enabled coiled tubing, such as coiled tubing having wireline running therethrough or fixed to the inner or outer walls thereof, forms a non-rotating conveyance string and can conduct data readings uphole during drilling. The BHA is fit with a variety of sensors, including those capable of measuring pressure and acceleration, for gathering downhole parameters relating to the drilling interface. Such real-time communication systems between surface and drilling BHAs are robust in part due to the fixed arrangement of the coiled tubing, which has no moving parts. However, repetitive movement of the coiled tubing and wireline can result in fatigue connection issues. Thus, these applications are suitable for use with fixed assemblies of components which are not subject to repeated movement, and no relative movement therealong, such as with telescoping of a portion of the BHA. 
     In hydraulic fracturing operations, the sleeve shifting tool of a BHA is subject to repeated, relative axial movement to set the packer and cycle the J-mechanism, and is subject to high fluid rates of abrasive, proppant loaded fluids flowing therethrough and thereby in the annulus between the BHA and wellbore. Such operating conditions are unsuitable for the implementation of real-time instrumentation subs, such as those used for drilling operations, due to fatigue issues caused by the repeated relative axial movement of the shifting tool. It is particularly difficult to locate sensors on the BHA below the shifting tool, as the telescoping and/or rotational movement of portions of the shifting tool relative to the coiled tubing presents a significant obstacle to electrically connecting sensors below the shifting tool to an instrumentation sub or other electrical components thereabove. 
     Additionally, present instrumentation subs for drilling have restricted inner bore diameters due to the space requirements for housing and sealing circuits and other electronic components therein. Flow is also restricted at the cable head assembly of the instrumentation sub, where the electrical connections in a wireline cable terminate and are connected to contacts of the instrumentation sub. Such restricted bore diameters result in relatively lower fluid flow rates therethrough that are not conducive to fracturing operations, which typically require flow rates of 1 m 3 /min or greater. In fracturing operations, it is preferable to have unrestricted flow capacity throughout the CT, and not be restricted at any point, such as at the instrumentation sub of the BHA. Such flow restriction at the BHA can also result in severe erosion, due to the high flow rates required for fracturing operations, and the fact that fracturing fluid is often sand-laden and quite erosive. As clean fluid is typically used in drilling operations, and flow rates are lower, conventional instrumentation subs for drilling operations are not designed to account for the flow and erosion considerations of fracturing operations and are therefore unsuitable for use in such operations 
     Further, conventional instrumentation subs for drilling do not have means for communicating with components below the BHA, such as additional sensors. Information acquired by such sensors may be useful in fracturing operations. For example, downhole pressure data above and below the packer of the BHA can be used to determine whether the packer was successfully set before fracturing fluid is pumped into the wellbore. 
     There is interest in the industry to improve access to operational data at the downhole tool for improving reliability and effectiveness of hydraulic fracturing. 
     SUMMARY 
     Embodiments of a bottom hole assembly (BHA) are provided herein for obtaining data regarding downhole conditions and BHA operation during fracturing operations, and transmitting said data in real-time from the BHA to surface. Some embodiments also permit bi-directional communication between the BHA and surface, such that instructions can be sent from surface or remotely to the BHA. The BHA is connected to the downhole or distal end of coiled tubing (CT) or a similar tubular string. 
     The monitoring of pressure uphole and downhole of a BHA during fracturing operations provides data 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 time as recovered from machine-readable memory located on the BHA, downhole data is transmitted to surface in real-time or near real-time. 
     In one embodiment, real-time downhole data collection and transmission is effected, including on mechanical BHA tools, using an electronics interface sub located on the conveyance string. 
     In some embodiments, a short-hop wireless transmission system can be implemented to permit communication between components uphole and downhole from the mechanical BHA tool. 
     In another embodiment, real-time or near real-time downhole data collection and transmission is effected uphole and downhole of an electronically-actuated BHA tool, the uphole and downhole being axially fixed. 
     In embodiments, abrasive fracturing fluid is delivered through the annulus for minimizing erosive effects on the electronics interface sub. The annulus provides a large cross-sectional area suitable for the high fluid rates required for hydraulic fracturing. Fracturing fluid can also be communicated downhole via the bore of the CT. The electronics interface sub can be configured to provide an axial bore that permits flow rates suitable for fracturing operations, and avoid flow bore restrictions that would result in accelerated erosion due to fracturing fluid flowing therethrough. Further, when treatment fluid is delivered to the formation through one of the annulus and the CT, the other can act as a “dead leg”. For example, when the treatment fluid is delivered through the annulus, a minimal, constant amount of a deadhead fluid can be delivered through the tubing string to act as the “dead leg” for maintaining pressure within the CT. The pressure required to maintain the constant fluid delivery is monitored from surface and can be used for calculating fracture extension pressure and formation breakdown pressure, as well as fracture closure pressure. 
     In conventional completion operations, a “dead leg” is used not only to prevent collapse of the CT under pressure from fluids in the annulus, but also to permit calculation of pressure to determine reaction of the formation to the fracturing operation. 
     However, in embodiments where the CT is electronically enabled coil having a wireline running therethrough, and the bore of CT is fluidly coupled with the annulus, such as through ports at the BHA, flow of abrasive fluid downhole or uphole through the CT is discouraged due to potential erosion of the electronic interface sub, and the wireline itself. There is the possibility of reverse flow into the CT, by pressure imbalance or through operator directed purposeful reverse circulation to clear sands from the packer area and the like. 
     As introduced above, mechanical fracturing tools incorporate axially telescoping components, such as to compress a packer, complicating electrical connections uphole to downhole of the packer. 
     As discussed in Applicant&#39;s international application WO/2013/159237, published Oct. 31, 2013, and incorporated herein in its entirety, electrically-enabled CT was implemented for bidirectional communication of signals between a BHA and surface. Power can be provided to the BHA components which can be electrically-actuated. The disclosed BHA comprised an electrically-actuated, variable diameter packer located below fracturing treatment ports. The electrically-enabled BHA obviates the need for axially movable components and includes electrical circuitry extending below the packer to arrays of perforating guns therebelow. 
     Herein, a downhole fracturing tool is provided comprising electrically enabled coiled tubing, an interface sub and a mechanically-actuated BHA. 
     In a general aspect, a bottom hole assembly (BHA) adapted for connection to coiled tubing extending from surface into a wellbore is provided, the coiled tubing having a tubing bore, the BHA comprising: an instrumentation sub in electrical communication with the surface and having a data processor, an axial bore in communication with the tubing bore, and an electrical conduit permitting electrical power and signals to pass from a first end of the instrumentation sub to a second end of the instrumentation sub downhole of the first end; one or more sensors electrically connected to the instrumentation sub; and a mechanical shifting tool downhole of the instrumentation sub and adapted for actuating sleeve valves located along the wellbore; wherein the data processor is adapted to receive data from the one or more sensors and communicate the data to the surface; and wherein the axial bore is sized to permit a fluid flow rate conducive to hydraulic fracturing operations. 
     In an embodiment, the one or more sensors comprise at least one of a 3D directional sensor, a sensor adapted to determine axial movement, a sensor adapted to determine rotational movement, an axial force sensor, an accelerometer, a positional sensor, a pressure sensor, a temperature sensor, or a combination thereof. 
     In an embodiment, the BHA further comprises a receiver located uphole of the shifting tool and a transmitter located downhole of the shifting tool, wherein the transmitter is electrically connected to one or more electrical components located downhole of the shifting tool and the receiver is electrically connected to the data processor, and wherein the transmitter is adapted to communicate data to the receiver. 
     In an embodiment, the receiver is a first transceiver, and the transmitter is a second transceiver. 
     In an embodiment, at least one of the one or more sensors is located downhole of the shifting tool and electrically connected to the transmitter. 
     In an embodiment, at least a first pressure sensor is located uphole of the shifting tool and at least a second pressure sensor is located downhole of the shifting tool and electrically connected to the transmitter. 
     In an embodiment, the BHA further comprises a check valve located in-line with the axial bore and adapted to prevent fluid from flowing uphole therethrough. 
     In an embodiment, the fluid flow rate is about 1 m3/min or greater. 
     In an embodiment, the BHA further comprises a power source and memory module located on the instrumentation sub and electrically connected to the one or more sensors. 
     In an embodiment, the shifting tool is configured to actuate between various operational modes via an axial telescopic movement of a mandrel of the shifting tool relative to a housing of the shifting tool. 
     In an embodiment, the BHA further comprises a disconnect located between the instrumentation sub and the shifting tool. 
     In an embodiment, the disconnect is configured to sever an electrical and mechanical connection between the instrumentation sub and shifting tool in response to an electrical signal. 
     In an embodiment, the disconnect is configured to sever an electrical and mechanical connection between the instrumentation sub and shifting tool in response to an actuating member engaging the disconnect. 
     In an embodiment, the diameter of the axial bore is substantially uniform. 
     In an embodiment, the BHA further comprises a drilling tool adapted to be interchangeable with the shifting tool. 
     In a general embodiment, a method for performing fracturing operations in a wellbore having one or more sleeve valves positioned therealong comprises: running a bottom hole assembly (BHA) located on a tubing string to a position adjacent a sleeve valve of interest of the one or more sleeve valves; pulling uphole on the BHA to locate the sleeve valve of interest using a mechanical shifting tool of the BHA; acquiring data regarding one or more parameters of the BHA and wellbore using one or more sensors electrically connected to an instrumentation sub of the BHA; confirming the successful locating of the sleeve valve of interest using the acquired data; actuating the sleeve valve of interest to an open position with the shifting tool; isolating the wellbore below the sleeve valve of interest with a packer of the BHA; and introducing fluid into the wellbore to fracture a zone of interest of the wellbore adjacent the sleeve valve of interest. 
     In an embodiment, the method further comprises confirming the successful actuation of the sleeve valve of interest to the open position using the acquired data, and wherein the acquired data comprises at least one of accelerometer data and axial load data. 
     In an embodiment, the method further comprises confirming the successful isolation of the wellbore below the sleeve valve of interest using the acquired data, and wherein the acquired data comprises at least data regarding a first pressure uphole of the shifting tool and data regarding a second pressure downhole of the shifting tool. 
     In an embodiment, the step of acquiring data further comprises acquiring the second pressure using a pressure sensor downhole of the shifting tool, receiving the data regarding the second pressure at a transmitter downhole of the shifting tool, and sending the data regarding the second pressure to a receiver uphole of the shifting tool. 
     In an embodiment, the acquired data comprises data regarding pressure within an axial bore of the BHA and pressure within an annulus defined between the BHA and the wellbore, and the step of introducing fluid further comprises monitoring the pressure in the axial bore and the pressure in the annulus. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a representative illustration of a downhole fracturing operation incorporating an instrumentation sub in a bottom hole assembly for communicating data regarding various downhole parameters to surface; 
         FIG. 2A  is a representative illustration of an embodiment of a bottom hole assembly having an instrumentation sub incorporated therein for acquiring data regarding various downhole parameters; 
         FIG. 2B  is a representative illustration of another embodiment of a bottom hole assembly having an instrumentation sub; 
         FIG. 3A  is a cross-sectional depiction of another embodiment of a bottom hole assembly incorporating an instrumentation sub, according to an embodiment of the disclosure; 
         FIG. 3B  is a cross-sectional depiction of the bottom hole assembly of  FIG. 3A  in use for shifting a sleeve located along a wellbore and fracturing a zone of interest outside and adjacent to the sleeve; 
         FIG. 4A  is an elevation view of an embodiment of an instrumentation sub for use with a bottom hole assembly for fracturing operations; and 
         FIG. 4B  is a cross-sectional view of the instrumentation sub of  FIG. 4A . 
     
    
    
     DETAILED DESCRIPTION 
     Embodiments are described herein in the context of fracturing operations. However, as one of skill in the art will understand, systems and methods disclosed herein are also applicable to other completion and stimulation operations. 
     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 and “uphole” indicating being toward a proximal end or surface of the wellbore. 
     With reference to  FIG. 1 , embodiments described herein utilize an electronic instrumentation sub and electronic sensing components incorporated into a bottom-hole assembly (BHA) having a mechanically-actuated fracturing/sleeve shifting tool. The BHA can be run into a wellbore on a tubing string, such as coiled tubing (CT), for completion of multiple zones of interest of a hydrocarbon formation adjacent to the wellbore. The electronic instrumentation sub can be connected to monitoring equipment at surface, such as via a wireline running through, fixed to, or embedded in coiled tubing for communicating data collected by the sensing components regarding various wellbore parameters to surface. The CT and wireline can be provided on a spool connected to a motor. Moreover, a bore of the instrumentation sub is configured to accommodate the flow requirements of fracturing operations and be suitable for use with the flow rates and erosive fluids often utilized in such operations. Incorporation of the instrumentation sub and electronic sensing equipment in conjunction with a mechanical fracturing tool enables operators to be aware of downhole conditions and make adjustments to completion operations in real-time or near real-time, thus permitting flexibility heretofore unavailable in conventional completion operations using mechanically-actuated fracturing/shifting tools alone. A pump at surface is configured to pump fracturing fluid, such as a sand-laden fluid, downhole via the bore of the CT or the annulus formed between the CT and wellbore casing. 
     Embodiments described herein are useful for treating or fracturing new wellbores that are drilled, but have not yet been completed. The wellbores can be cased and have ported sliding sleeve subs installed therein, the sleeve subs having sliding sleeves actuable between a closed position, wherein the sleeves cover fracturing ports of the sleeve sub, and an open position, wherein the fracturing ports are exposed to establish fluid communication between the wellbore and the formation. At the beginning of fracturing operations, the sleeves are typically in the closed position, having not yet been actuated to expose the fracturing ports. In embodiments, the sliding sleeves may also be selectively closable to stop communication between the formation and the wellbore therethrough. The sliding sleeves can have an inner profile adapted to be engaged by the fracturing tool of the BHA such that the sleeves can be shifted axially between the open and closed positions by manipulation of the CT after being engaged by the fracturing tool. 
     General BHA Construction 
     In embodiments, with reference to  FIGS. 2A and 2B , a BHA is shown located at a distal end of a CT string for deployment into a wellbore for completion operations, such as fracturing operations. The BHA comprises an instrumentation sub, a mechanically actuated fracturing/sleeve shifting tool, and one or more sensors electrically connected to the instrumentation sub and capable of measuring various parameters of the BHA and wellbore. The sensors can be configured to measure parameters such as circulation pressure inside the CT, wellbore pressure in the annulus surrounding the CT and BHA, differential pressure across select components (e.g. across a packer of the fracturing tool), relative axial force on the CT (e.g. tension and compression), BHA vibration or shock (e.g. total RMS vibration), torque, BHA inclination, axial and/or rotational movement of the BHA, and 3D direction of the BHA. In the depicted embodiments, the mechanical fracturing tool is located downhole from the instrumentation sub. In alternative embodiments, the fracturing tool can be located uphole from the instrumentation sub. 
     When the BHA is deployed into the wellbore, an annulus is formed between the CT/BHA and the wellbore casing. Fluid can be conducted from surface downhole through a tubing bore of the CT, or through the annulus. The BHA can also have an axial bore for allowing the communication of fluid therethrough. Bi-directional electrical communication between surface and the BHA is enabled via wireline. The wireline is connected at a proximal end thereof to electrical equipment at surface, such as a controller and a display device, and terminates at a distal end thereof at a cable head assembly of the instrumentation sub. As one of skill in the art will understand, any wireline or other electrical connection that provides sufficient electrical capability to permit transmission of power and communication of data between the BHA and surface would be suitable for use in embodiments described herein. In embodiments, fiber optics incorporated into the wireline may be used to communicate data between surface and the BHA. 
     In embodiments, a release sub or disconnect can be located between the instrumentation sub and the fracturing tool, such that the instrumentation sub can be disconnected from the fracturing tool and retrieved to surface in the event the fracturing tool becomes stuck in the wellbore. The disconnect can be mechanically actuated, such as via a ball or other actuating member dropped into the CT from surface to engage the disconnect, or electrically connected to the instrumentation sub and electrically actuated to decouple the fracturing tool from the components thereabove. In other embodiments, the disconnect can be configured to separate if a predetermined tensile load is experienced. 
     The BHA is fluidly connected to a distal end of the CT, and the instrumentation sub has an axial bore having a cross-sectional flow area that permits fluid flow rates suitable for fracturing operations while avoiding fluid velocities that would result in severe erosion of the axial bore due to fracturing fluid flowing therethrough. Additionally, the cable head assembly of the instrumentation sub is configured such that it does not restrict the size of the axial bore of the sub, further enabling fluid flow rates required for fracturing operations, and mitigating erosion of components in the instrumentation sub. Such an enlarged flow area is advantageous over prior art instrumentation subs, which have restricted axial bores in order to accommodate electronic components in a bulkhead of the sub. 
     In embodiments, the axial bore of the instrumentation sub is deviated to accommodate the electronic components of the instrumentation sub. The location at which the axial bore deviates is particularly susceptible to erosion. To mitigate such erosive effects, the angle at which the axial bore is deviated can be reduced. 
     At least one radially-extending fracturing port can be formed in the housing of the BHA and be configured to selectively permit fluid communication between the axial bore and annulus such that fracturing fluid can be delivered to the formation via the tubing bore and axial bore in coiled-tubing fracturing operations. In the embodiment depicted in  FIGS. 2A and 2B , the fracturing ports are located downhole from the instrumentation sub, between the disconnect and the fracturing tool. 
     In embodiments, the instrumentation sub can have a power storage means, such as a battery or capacitor, and a memory module configured to store data acquired by sensors, and be capable of operating in a memory mode in which data collected by the sensors is stored in the memory module for later retrieval. In embodiments, the instrumentation sub can operate in the memory mode while transmitting downhole data to surface, such that a backup of the data is stored in the event real-time data transmission to surface is interrupted or otherwise unavailable. 
     Fracturing Tool 
     In embodiments, the fracturing tool is a mechanical sleeve shifting tool such as that shown in  FIGS. 2A-3B , comprising a packer, a plurality of dogs, and a J-slot mechanism that enables the tool to be actuated between various operating modes, including a running position (RIH), a sleeve locating position (LOCATE), a set or sleeve engaged position (SET), and a pull-out-of-hole position (POOH). The dogs have uphole and downhole interfaces configured to engage with the sleeve profiles of the sleeve valves located along the wellbore casing. In the running position RIH and pull-out-of-hole position POOH, the plurality of dogs are in a radially inwardly retracted position such that the dogs do not contact or engage the wellbore casing or sleeves as the tool is being run-in-hole RIH or pulled-out-of-hole POOH. In the sleeve locating position LOCATE, the dogs are biased radially outwards into contact with the wellbore casing and the sleeve valves, such that the dogs will engage the sleeve profiles of the sleeve valves as the BHA is axially manipulated thereby. In the sleeve engaged position SET, the dogs are locked in the radially outward position in engagement with the sleeve profile of a sleeve, such as by a cone, such that the tool can be RIH or POOH to open or close the sleeve valve. Further, in the SET position, the packer of the fracturing tool is energized and engaged with the wellbore to isolate the portion of the wellbore above the fracturing tool from the portion of the wellbore therebelow. In embodiments, a bypass valve of the fracturing tool is also closed to prevent fluid from flowing downhole of the fracturing tool through the axial bore of the BHA. 
     A best shown in  FIGS. 3A and 3B , the dogs can be secured to a housing of the fractural tool while the packer and cone can be secured to a fracturing tool mandrel. Mandrel is telescopically connected to the fracturing tool housing such that axial manipulation of the CT telescopically actuates the mandrel relative to the fracturing tool housing. A drag sub or drag block can be connected to the housing to provide axial resistance and facilitate the telescoping action of the mandrel. The various operating modes of the BHA are delimited by the J-slot mechanism and are correlated to the axial position of the mandrel relative to the fracturing tool housing. For example, the dogs can be located at the distal ends of arms having cams formed thereon, the cams having a radially varying profile. An actuating ring or spider secured to, and movable with, the mandrel is configured to engage the cams of the arms and retract the arms and dogs radially inwardly or permit the arms and dogs to extend radially outwardly, depending on the axial position of the mandrel relative to the housing. Axial stroking of the mandrel relative to the housing cycles the J-slot mechanism and actuates the fracturing tool through its operating modes. As discussed above, such axial telescoping makes it difficult to locate sensors and other electrical components downhole of the fracturing tool, as providing an electrical connection between the uphole and downhole ends of the fracturing tool is challenging due to the varying axial distance therebetween. 
     An example of a suitable fracturing/shifting tool for use with the BHA is the tool disclosed in Applicant&#39;s U.S. Pat. No. 10,472,928, incorporated herein in its entirety. One of skill in the art would understand that other fracturing tools may be used depending on factors such as the type of sleeve or zone isolation mechanism used in the wellbore. 
     Short Hop System 
     In embodiments, with reference again to  FIGS. 2A and 2B , a receiver can be located uphole from the fracturing tool, such as inside the instrumentation sub or in a separate receiver sub electrically connected to the instrumentation sub, and a transmitter can be located downhole from the fracturing tool, such as on a transmitter sub. The transmitter can be connected to sensors configured to take measurements of various parameters downhole of the fracturing tool, such as annular pressure, temperature, tension/compression, and torque, and wirelessly send said measurements or other data to the receiver for subsequent transmission to surface in real-time or near real-time. Such a “short hop” system for bridging communication of data above and below the fracturing tool is desirable. For example, sensors can be used to obtain pressure data above and below packers or other isolation elements of the fracturing tool in order to confirm whether the packer was successfully engaged against the casing to isolate the zone of interest from the rest of the wellbore before fracturing. In embodiments, first and second transceivers can be used in place of the receiver and transmitter, such that data can be communicated bi-directionally between components uphole and downhole of the fracturing tool. 
     Currently, data regarding the uphole and downhole ends of the fracturing tool is collected by sensors and stored in memory modules onboard the BHA to be analyzed at surface when the BHA is retrieved. Real-time communication of such data to surface has been heretofore unavailable due to the difficulty of establishing a physical electrical connection between equipment uphole and downhole of the mechanical fracturing tool as a result of the axially reciprocating and rotational functions of the tool. 
     The transmitter/transceiver downhole of the fracturing tool can be powered by an on-board power source located on the BHA downhole of the fracturing tool, such as a battery or a capacitor, such that it is unnecessary to have any electrical connection between the uphole and downhole ends of the fracturing tool. 
     Electrical Throughput 
     The instrumentation sub can have an electrical throughput to permit additional electrical tools to be located below the instrumentation sub. Electrical connection between the instrumentation sub and components therebelow can be accomplished in a number of ways including, but not limited to, conductors extending therebetween through the axial bore of the BHA, or conductors extending therebetween through an electrical race formed about a periphery of the BHA&#39;s components. 
     Check Valve 
     In embodiments, a check valve is located in the axial bore of the BHA to prevent fluids from flowing from the wellbore up the CT and potentially damaging the wireline. The check valve can comprise a mechanical check valve or an electrically-actuated valve, such as a solenoid valve. As best seen in  FIGS. 2A, 2B , and  4 B, the check valve is located in the axial bore of the BHA downhole from the instrumentation sub, such that fluid cannot flow uphole from the wellbore to the tubing bore of the CT through the instrumentation sub and potentially damage the components or connections therein. An issue with check valves currently employed in BHAs is that they have relatively restricted bore dimensions, resulting in reduced flow rates therethrough that may not be conducive to fracturing operations, and suffering damage as the erosive wellbore fluids flow therethrough. The check valve of the present application has a bore sized to permit fluid flow rates suitable for fracturing operations. For example, the check valve bore can be sized to permit a flow rate of at least 1 m 3 /min therethrough. 
     Sensors &amp; Controller 
     As discussed above, the sleeve shifting/fracturing tool of the BHA is used to open and close sleeves by actuating the shifting tool to engage the sleeve profile of the sleeve sub of the zone of interest and pulling the CT uphole or running it downhole to axially shift the sleeve. Currently, mechanical shifting tools do not have means to confirm whether the shifting tool has successfully engaged with the sleeve profile of the desired sleeve, whether the sleeve was successfully shifted, and whether the packer of the BHA has successfully sealed with the wellbore casing in preparation for fracturing operations. 
     To provide such downhole measurement capabilities, the BHA can be fit with one or more sensors to measure parameters of interest during fracturing operations. The one or more sensors can be electrically connected to the instrumentation sub, which is configured to receive the data measured by the sensors and communicate it to surface in real-time or near real-time via the wireline. 
     A terminal can be located at surface to receive the data transmitted by the instrumentation sub. The terminal can have or otherwise be connected to a display device and be configured to display the received data on the display device. In embodiments, the terminal can also act as a controller capable of sending commands to the BHA and configured to manage various fracturing operation parameters, such as a rate of injection of fluid into the wellbore, axial or rotational force applied to the CT string, whether to open or close the electronic check valve or release the electronic disconnect, and other parameters. In embodiments, as shown in  FIG. 1 , the terminal can further be configured to compile the data into charts or tables, or process the data into other forms for further analysis. 
     In embodiments, the terminal can have a wireless communications module to enable the data received from the instrumentation sub to be transmitted over a wireless network, such as the Internet, a cellular network, and the like. Instructions to the BHA can also be sent over the wireless network to the terminal to be relayed to the BHA. 
     In embodiments described herein, and having reference again to  FIGS. 2A and 2B , the instrumentation sub of the BHA and the sensors connected thereto permit direct measurement of parameters such as pressure, temperature, strain, vibration and the like, and the transmission of the acquired data to surface in real-time or near real-time. 
     One or more of the sensors can be a strain sensor configured to measure axial loading of the CT string and/or the BHA to assist the operator to understand if the CT string or BHA is under tension or compression, which can be useful in determining whether the fracturing tool has engaged a sleeve profile while in the sleeve locating position, or whether the packer of the fracturing tool has successfully engaged with the casing. In embodiments, the strain sensor is located in the instrumentation sub above the fracturing tool. As one of skill in the art will appreciate, the strain gauges or sensors provide data to surface to assist with determining the status of the fracturing tool and whether an operator can proceed to the next stage of the fracturing operation. 
     In an embodiment, one or more strain sensors can also be located downhole from the fracturing tool and connected to the short hop transmitter/transceiver for measuring tension and compression below the tool and transmitting the measured data to surface. In such embodiments, the strain sensor(s) are preferably located uphole from the drag sub of the BHA so as to obtain accurate strain measurements. 
     The sensors can also comprise position sensors, such as accelerometers or MEMS sensors, which are capable of measuring and providing data regarding the orientation of each of the sensors. The data from the sensors are then mathematically manipulated with respect to the orientation of the sensors to determine the position, orientation, and bearing of the BHA, as is understood in the art. The accelerometers can be placed on multiple axes to determine movement, direction, and orientation of the BHA as well as to detect vibration and shocks to the BHA, for example when the dogs of the fracturing tool engaged the sleeve profile of a sleeve and movement of the BHA stops abruptly. 
     Temperature sensors can also be located on the BHA to measure fluid and wellbore temperatures. 
     Pressure sensors can also be used in the BHA at different locations to determine the differential pressure, for example on either side of the packer of the fracturing tool when it is deployed. Such differential pressure measurements can be used to determine whether the packer successfully has engaged the casing to isolate the zone of interest for fracturing. Pressure sensors can also be located inside and outside the CT for determining pressures in the annulus and/or CT tubing bore, as well as the differential pressure therebetween. As will be appreciated by those of skill in the art, pressure P 1  above the packer of the fracturing tool is indicative of how the formation is reacting to the fracturing operation while pressure P 2  below the packer may be indicative of the integrity of the packer element the packer and the formation between adjacent zones. Further, after cessation of pumping of the fracture fluid into the wellbore, fracture closure pressures can also be monitored. The ability to measure pressure may be particularly advantageous when high rate foam fracturing is performed as measuring pressure enables understanding of the quality of the foam at the perforations. As discussed above, the implementation of short-hop subs above and below the fracturing tool permit the use of pressure sensors above and below the fracturing tool for measuring P 1  and P 2 , and the transmission of data acquired therewith to surface in real-time, while avoiding the problems associated with electrically connecting the uphole and downhole ends of the telescoping fracturing tool. 
     Movement sensors such as accelerometers can also be provided on the BHA for measuring axial or rotational movement thereof. Such sensors can have a resolution sufficient to measure small axial movements, such that axial movement of the BHA when shifting a sleeve between the open and closed positions can be detected by the sensors to confirm successful shifting of the sleeve. 
     The inclusion of sensors capable of providing 3D survey and inclination data is also advantageous, at it permits the BHA to be quickly reconfigured for drilling and fracturing operations. For example, a drilling tool can be attached to the BHA, such as at the disconnect, and used to drill a wellbore. The positioning sensors on the instrumentation sub are used to provide real-time data regarding the drilling operation. Once drilling is complete, the BHA can be retrieved to surface, and the drilling tool can be removed therefrom. A fracturing tool can then be connected to the BHA, for example at the disconnect, and the BHA used for fracturing operations. 
     Additionally, the one of more sensors can also comprise 3D directional sensors, which could be used in embodiments where the BHA is used to directionally drill a wellbore. 
     In embodiments, sensors specific to the drilling operation can be located on or downhole of the drilling tool, and sensors specific to the fracturing operation can be located on or downhole of the fracturing/shifting tool. 
     As one of skill in the art would understand, additional sensors for measuring other parameters of the BHA and wellbore can be provided on the BHA in order to provide additional data during fracturing operations. 
     Use in New Cased or Lined Wellbores 
     In use, as shown in  FIG. 1 , the BHA is connected to the distal end of a CT string and is run into the wellbore. The wellbore has a plurality of sleeve subs positioned adjacent various zones of interest of the wellbore. The instrumentation sub of the BHA is electrically connected to the distal end of a wireline. A proximal or surface end of the wireline is connected to the terminal and other equipment at surface configured to receive data from the instrumentation sub and send instructions to the BHA and surface equipment for controlling various aspects of the fracturing operation. Typically, the BHA is first run to the toe of the wellbore as fracturing is performed at intervals or zones of interest from the toe of the wellbore toward a heel of the wellbore. 
     The fracturing tool of the BHA can first be set to the running position and run-in-hole to the toe of the wellbore. After reaching the toe, the fracturing tool can then be actuated to the sleeve locating position LOCATE and pulled uphole until it reaches the first zone of interest and engages the sleeve profile of a corresponding sleeve valve of interest. Arrival of the BHA at the first zone of interest can be confirmed by data received from the various sensors of the BHA, as described above. For example, confirmation that the fracturing tool successfully has engaged the sleeve profile of the sleeve sub of the first zone of interest can be obtained from data acquired by the strain gauges and accelerometers, which would respectively show increased tension along the CT string and a sudden deceleration. 
     Once engagement with the sleeve profile by the fracturing tool is confirmed, the tool can be actuated to the sleeve engaged position SET to lock the dogs of the fracturing tool in engagement with the sleeve profile, and the BHA can be lowered downhole to shift the sleeve to the open position and expose the fracturing ports of the sleeve sub, thereby establishing communication between the wellbore and the zone of interest via the fracturing ports. Data from the movement sensors can be used to confirm that the sleeve was indeed shifted to the open position i.e. a sudden downhole acceleration and deceleration of the BHA. 
     With reference to  FIG. 3B , after confirming that the sleeve has been opened, the packer of the fracturing tool can be set below the fracturing ports of the sleeve sub to isolate the portion of the wellbore above the fracturing tool from the portion of the wellbore therebelow, and fracturing fluid can be introduced into the wellbore to fracture the formation at the zone of interest. Fracturing fluid can be introduced into the wellbore either through the CT or the annulus, or both, to stimulate the zone of interest. In CT frac operations, fracturing fluid flows through the tubing bore and out of the ports of the BHA and the fracturing ports of the corresponding sleeve valve to reach the zone of interest. In annular frac operations, fracturing fluid flows through the annulus and out of the fracturing ports of the corresponding sleeve valve to reach the zone of interest. The fluid is prevented from flowing further down the annulus by deploying the packer of the fracturing tool below the fracturing ports of the sleeve valve. In embodiments, a bypass valve of the fracturing tool is also closed to prevent fluid from flowing downhole of the fracturing tool through the axial bore of the BHA. The sensors of the BHA can be used to confirm successful isolation of the wellbore, for example by comparing the measurements of a first pressure sensor uphole of the fracturing tool with the measurements of a second pressure sensor downhole of the fracturing tool. Pressure sensors located in the tubing bore and annulus can be used during the pumping of fluid into the wellbore to evaluate the status of the frac. For example, an increase in annular or tubing pressure may indicate a screenout, and a rising differential pressure between the tubing bore and annulus may indicate a need to adjust fluid flow. 
     Once the zone of interest has been fractured, injection of fracturing fluid can cease. In embodiments, for annular fracturing operations, clean fluid can be reverse circulated, that is, injected into the CT to flow out of the flow ports of the BHA and back to surface through the annulus to remove debris. Such reverse circulation can be done in the case of CT fracturing operations as well if the check valve is not present in the BHA, or if the check valve can be actuated to an open position to permit fluid to flow up the CT through the instrumentation sub. In the case of reverse circulation in CT fracturing operations, care must be taken to avoid screenout of the instrumentation sub due to sand and debris entrained in the circulating fluid. 
     The BHA is then repositioned by actuating the fracturing tool to the pull-out-of-hole position POOH and pulling on the CT to position the BHA adjacent the next sleeve valve of interest, uphole from the previously completed zone. Once again, the mechanical fracturing tool can be actuated to the sleeve locating position LOC and the BHA moved axially uphole until the sleeve valve corresponding to the new zone of interest is located. Once again, the sensors of the BHA can be used to provide information with respect to whether the fracturing tool has successfully located a sleeve. Once successful location of the sleeve has been confirmed, the fracturing tool can be actuated to the sleeve engaging position SET and the BHA moved downhole to shift the sleeve to the open position. 
     In embodiments, the BHA can also be used to close sleeve valves by locating sleeve valves of interest in the manner described above, and using the BHA to shift the sleeves of said sleeve valves to the closed position. The sensors of the BHA can be used to confirm successful location and actuation of the sleeve valves to the closed position, for example by detecting the sudden acceleration and deceleration of the BHA, or a change in axial load on the CT and BHA.