RELATED APPLICATIONS

[0001] The present disclosure claims priority to U.S. Provisional Patent Application No. 63/354,987, filed June 23, 2022, and U.S. Provisional Patent Application No. 63/465,646, filed May 11 , 2023, the entire contents of which are herein incorporated by reference.

TECHNICAL FIELD

[0002] The present disclosure relates to downhole tool operations. More particularly, the present disclosure relates to sleeve assemblies and related completion systems and methods for selectively actuating downhole tools in different sections of a wellbore.

BACKGROUND

[0003] In staged horizontal wellbore completion operations, a wellbore is drilled into a subterranean formation and different zones of the formation are treated (e.g. stimulated and/or fractured) sequentially at different points along the wellbore.

[0004] Multiple technologies have been developed for multi-stage horizontal well stimulation. One such technology is a plug-and-perforation (“plug-and-perf”) system that uses wireline services and/or coiled tubing (CT) services to run-in-hole (RIH) a select-fire perforating gun with one or more bridge plugs so as to plug and perforate sections of cased horizontal wells for subsequent stimulation operations. Plug-and-perf systems are typically implemented on “pads” where multiple wells are drilled from one surface location, primarily because wirelines services can be managed without downtime to fracturing operations. Plug-and-perf systems are not commonly used with single wells due to fracturing equipment cost inefficiencies. [0005] Plug-and-perf systems typically require the bridge plugs to be milled out after the well is completed. Dissolvable bridge plugs (DBPs) have been investigated but commercially available DBPs have challenges with reliability and have not been widely accepted. DBPs often cannot withstand the high-pressure fracturing environment and/or are designed with such rigid material that the DBP does not dissolve effectively. Due to these dissolvability issues, the DBPs may still need to be milled out after the well is completed.

[0006] Non-dissolvable bridge plugs are often used in combination with a dissolvable or non-dissolvable ball to achieve more reliable isolation. The ball may be run with the bridge plug setting tool (“ball in place”) or not (“ball not in place”). Plug- and-perf applications using “ball in place” or “ball not in place” typically do not remove the bridge plug barrel, resulting in a permanent inner diameter (ID) restriction unless the bridge plug barrels are milled out during a workover.

[0007] Other completion systems use flow control valves such as sleeve assemblies to selectively establish fluid communication between a bore of the completion string and the formation. Conventional sleeve assemblies comprise a tubular housing with a plurality of flow ports and an inner sleeve configured to slide axially with respect to the tubular housing to open and close the flow ports. Multiple sleeve assemblies are typically spaced along the casing string to establish fluid communication with different zones of interest along the wellbore.

[0008] Sleeve assemblies may be actuated by dropping actuating objects (e.g. balls) into the wellbore to seat and shift the sleeve. Ball drop technologies can be used on both pad wells and single wells. However, ball drop systems are limited in terms of stages and the fracturing pump rate. Moreover, the ball seat is typically milled out after the stage is completed to avoid the wellbore being left with inner diameter (ID) restrictions.

[0009] An alternative to ball drop technologies are conveyance strings, such as coiled tubing, fit with mechanical shifting tools. Conveyed shifting tools may be configured for both opening and closing of sleeves for various purposes. However, shifting tool-based techniques typically require ID-restricting conveyance coiled tubing. In addition, the infrastructure and time for running the shifting tool in and out of the wellbore each time a sleeve is to be shifted may be costly.

[0010] More complex actuation tools, such as active darts or cage systems, can be used instead of balls or conveyed shifting tools. However, these systems may result in wellbore ID restrictions and may not have full “certainty” if the sleeve being actuated is at the correct stage.

[0011 ] Dart-based systems typically involve an electronic dart device that senses an “activation sleeve” just above the target sleeve that the dart is intended to actuate. Once the dart passes the activation sleeve, it will typically activate a seal and locator collet to land in a shoulder of the target sleeve. However, the seal and locator collet may have reliability issues, leading to unreliable isolation of the target sleeve. Dissolvable darts have been developed but dissolvability also tends to be unreliable. In addition, such darts typically require a large shoulder in the sleeve to engage the locator collet, which reduces the ID of the finished wellbore after the dart dissolves. As an alternative to a fully dissolvable dart, some darts are made of aluminum or steel and have a dissolvable ball in the center like a DBP. However, this design may lead to similar well construction issues post-fracturing as DBPs, including a permanent wellbore ID restriction that can only be removed by milling the dart out.

SUMMARY

[0012] In one aspect, there is provided a sleeve assembly for a wellbore, comprising: a tubular housing; an actuatable inner sleeve received within the tubular housing, the inner sleeve axially movable with respect to the tubular housing between a first position and a second position, wherein the tubular housing and the inner sleeve together define an axial flow passage through the sleeve assembly; an engagement mechanism for engaging a fluid blocking element, the engagement mechanism being activatable between; an inactive state in which the engagement mechanism is approximately aligned with the inner sleeve; and an active state in which the engagement mechanism extends radially inward into the axial flow passage to form an annular shoulder, the annular shoulder being engageable with the fluid blocking element; wherein axial movement of the inner sleeve from the first position to the second position activates the engagement mechanism from the inactive state to the active state.

[0013] In some embodiments, the engagement mechanism comprises a swagable portion of the inner sleeve, and wherein axial movement of the inner sleeve swages the swagable portion to form the annular shoulder.

[0014] In some embodiments, the tubular housing comprises an angled inner ridge and wherein the swagable portion is swaged against the angled inner ridge such that the annular shoulder curves inward into the axial flow passage.

[0015] In some embodiments, the engagement mechanism comprises a compressible annular sealing member, and wherein axial movement of the inner sleeve compresses the annular sealing member to form the annular shoulder.

[0016] In some embodiments, the sleeve assembly further comprises a control system, the control system comprising: an actuator that actuates axial movement of the inner sleeve; a sensor that senses a control signal sent through the wellbore from surface; and at least one processor that activates the actuator responsive to the sensor sensing the control signal.

[0017] In some embodiments, the actuator comprises at least one energetic material and an initiator, and wherein the actuator is discharged, via the initiator, to generate a force to move the inner sleeve axially with respect to the tubular housing.

[0018] In some embodiments, the at least one energetic material comprises a first energetic material that is discharged via the initiator and a second energetic material that is discharged via shock waves generated by discharge of the first energetic material. [0019] In some embodiments, the at least one processor is configured to: increase a control signal count in response to the sensor sensing the control signal; and activate the initiator when the control signal count reaches a pre-determined threshold.

[0020] In some embodiments, the control signal comprises a pressure pulse pattern, and wherein the sensor comprises a strain gauge or a pressure sensor.

[0021 ] In some embodiments, the tubular housing has an inner surface and an outer surface, the tubular housing defining a plurality of flow ports extending from the inner surface to the outer surface; and wherein the inner sleeve is actuatable between a closed position in which the flow ports are blocked and an open position in which the flow ports are exposed.

[0022] In another aspect, there is provided a system for a wellbore, comprising: a first sleeve assembly comprising: a first tubular housing having an inner surface and an outer surface, the first tubular housing defining a plurality of flow ports extending from the inner surface to the outer surface; a first actuatable inner sleeve received within the first tubular housing and axially movable with respect to the first tubular housing between a closed position in which the flow ports are blocked and an open position in which the flow ports are exposed; and a second sleeve assembly comprising: a second tubular housing; a second actuatable inner sleeve received within the second tubular housing, the second inner sleeve axially movable with respect to the second tubular housing between a first position and a second position, wherein the second tubular housing and the second inner sleeve together define an axial flow passage through the second sleeve assembly; an engagement mechanism for engaging a fluid blocking element, the engagement mechanism being activatable between: an inactive state in which the engagement mechanism is approximately aligned with the second inner sleeve; and an active state in which the engagement mechanism extends radially inward into the axial flow passage to form an annular shoulder, the annular shoulder being engageable with the fluid blocking element; wherein axial movement of the second inner sleeve from the first position to the second position activates the engagement mechanism from the inactive state to the active state.

[0023] In some embodiments, the engagement mechanism comprises a swagable portion of the inner sleeve, and wherein axial movement of the inner sleeve swages the swagable portion to form the annular shoulder.

[0024] In some embodiments, the first and second sleeve assemblies each comprise a respective control system, each control system comprising: an actuator that actuates axial movement of the inner sleeve; a sensor that senses a control signal sent through the wellbore from surface; and at least one processor that activates the actuator responsive to the sensor sensing the control signal.

[0025] In some embodiments, the respective at least one processor of the first sleeve assembly and the second sleeve assembly activates the respective actuators in response to the respective sensors sensing same control signal.

[0026] In another aspect, there is provided a method for the system disclosed herein, comprising: actuating the first inner sleeve from the closed position to the open position to expose the plurality of flow ports; actuating the second inner sleeve from the first position to the second position to activate the engagement mechanism; and introducing a fluid blocking element into the system to engage the annular shoulder of the engagement mechanism and block fluid flow through the axial flow passage.

[0027] In some embodiments, the first inner sleeve and the second inner sleeve are actuated simultaneously.

[0028] In some embodiments, the second inner sleeve is actuated after the first inner sleeve. [0029] In some embodiments, the method further comprises performing a pressure test of the wellbore after the fluid blocking element has engaged the annular shoulder and blocked fluid flow.

[0030] In another aspect, there is provided a sleeve assembly for a wellbore comprising: a tubular housing; an actuatable inner sleeve received within the tubular housing, the inner sleeve being axially movable with respect to the tubular housing, wherein the tubular housing and the inner sleeve together define an axial flow passage through the sleeve assembly; a control system comprising: an actuator that actuates axial movement of the inner sleeve, the actuator comprising at least one energetic material and an initiator for the at least one energetic material; a sensor that senses a control signal sent through the wellbore from surface; and at least one processor configured to: increase a control signal count in response to the sensor sensing the control signal; and activate the initiator when the control signal count reaches a pre-determined threshold.

[0031 ] In some embodiments, the tubular housing has an inner surface and an outer surface, the tubular housing defining a plurality of flow ports extending from the inner surface to the outer surface; and wherein the inner sleeve is actuatable between a closed position in which the flow ports are blocked and an open position in which the flow ports are exposed.

[0032] In some embodiments, the sleeve assembly further comprises an engagement mechanism for engaging a fluid blocking element, the engagement mechanism being actuatable between: an inactive state in which the engagement mechanism is approximately aligned with the inner sleeve; and an active state in which the engagement mechanism extends radially inward into the axial flow passage to form an annular shoulder, the annular shoulder being engageable with the fluid blocking element; wherein axial movement of the inner sleeve activates the engagement mechanism from the inactive state to the active state. [0033] In some embodiments, the control signal comprises a pressure pulse pattern, and wherein the sensor comprises a strain gauge or a pressure sensor.

[0034] In some embodiments, the at least one energetic material comprises a first propellent that is discharged via the initiator and a second energetic material that is discharged via shock waves generated by discharge of the first energetic material.

[0035] In another aspect, there is provided a system for a tubing string of a wellbore, comprising: an embodiment of the sleeve assembly disclosed herein; and a wireline bottom hole assembly (BHA) apparatus comprising: a housing having an outer surface; and an actuatable isolation element disposed on the outer surface of the housing, the isolation element being actuatable between an inactive state an active state, wherein the isolation element expands in the active state to form a seal with an inner surface of the tubing string.

[0036] In some embodiments, the system further comprises a location sensor within the housing that senses the location of the sleeve assembly.

[0037] Other aspects and features of the present disclosure will become apparent, to those ordinarily skilled in the art, upon review of the following description of the specific embodiments of the disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

[0038] Some aspects of the disclosure will be described in greater detail with reference to the accompanying drawings. In the drawings:

[0039] Figure 1 is a side view of an example sleeve assembly, according to some embodiments;

[0040] Figures 2A and 2B are cross-sectional views of the sleeve assembly of Figure 1 , shown in a closed configuration and an open configuration, respectively; [0041 ] Figure 3 is a functional block diagram of a control system of the sleeve assembly of Figure 1 ;

[0042] Figure 4 is a schematic of an example pressure pulse pattern that may be sensed by the control system of Figure 3, according to some embodiments;

[0043] Figure 5A is a perspective view of an inner sleeve of the sleeve assembly of Figure 1 ;

[0044] Figure 5B is a partial perspective view of the inner sleeve of Figure 5A, showing the opposite side of the inner sleeve;

[0045] Figure 6 is a perspective view of an alternative actuator for the sleeve assembly of Figure 1 ;

[0046] Figure 7A is a side, cross-sectional view of another example sleeve assembly, according to some embodiments, shown in an inactive configuration;

[0047] Figure 7B is a side, cross-sectional view of the sleeve assembly of Figure 7A, shown in an active configuration;

[0048] Figure 7C is a side, cross-sectional view of the sleeve assembly of Figure 7A, shown in an active configuration and engaging a ball;

[0049] Figure 8A is a side, cross-sectional view of an example system including the sleeve assembly of Figures 1 -6 and the sleeve assembly of Figures 7A- 7C, shown in an inactive configuration;

[0050] Figure 8B is a side, cross-sectional view of the system of Figure 8A, shown in an active configuration;

[0051 ] Figures 9A to 9D are side, cross-sectional views of another example system, according to some embodiments, shown at various stages in a completion process; [0052] Figure 10 is a partial, side, cross-sectional view of an example system comprising a cluster frac sleeve configuration, according to some embodiments;

[0053] Figures 11A and 11 B are side, cross-sectional views of an alternative sleeve assembly, according to some embodiments, shown in an inactive and active configuration, respectively;

[0054] Figures 12A and 12B are enlarged views of an engagement mechanism of the sleeve assembly of Figures 11A and 11 B, shown in an inactive state and an active state, respectively;

[0055] Figure 13 is an enlarged view of the engagement mechanism of Figures 12A and 12B, shown in the active state and engaging a ball;

[0056] Figure 14A is a side, cross-sectional view of an example system including the sleeve assembly of Figures 1-2B and the sleeve assembly of Figures 11 A-11 B, shown in an inactive configuration;

[0057] Figure 14B is a side, cross-sectional view of the system of Figure 14A, shown in an active configuration;

[0058] Figures 15A to 15D are side, cross-sectional views of another example system, according to some embodiments, shown at various stages in a completion process;

[0059] Figure 16 is a flowchart of an example method according to some embodiments;

[0060] Figure 17 is a side view of a wireline bottom hole assembly (BHA) apparatus, according to some embodiments;

[0061 ] Figure 18 is a functional block diagram of an example control system of the wireline BHA apparatus of Figure 17; and [0062] Figure 19 is a side, cross-sectional view of an example system including the wireline BHA apparatus of Figure 17 and the sleeve assembly of Figures 1 -6.

DETAILED DESCRIPTION

[0063] Generally, the present disclosure provides sleeve assemblies for well completions. The sleeve assembly may comprise an inner sleeve actuatable via an integrated control system in response to control signals sent from surface. In some embodiments, the sleeve assembly comprises an engagement mechanism for a fluid blocking element, such as a ball, that is activated by movement of the inner sleeve. Related completion systems including two or more sleeve assemblies are also provided as well as related methods for such systems.

[0064] As used herein and in the appended claims, the singular forms of “a”, “an” and “the” include plural referents unless the context clearly dictates otherwise.

[0065] In this disclosure, the “uphole” direction refers to the direction toward the surface in a wellbore. The “downhole” direction refers to the direction toward the bottom of the wellbore (i.e. opposite to the uphole direction). The terms “upward” and “downward”, “upper” and “lower” and the like may be used to refer to the “uphole” and “downhole” directions, respectively, unless the context dictates otherwise. Use of any one or more of the foregoing terms does not necessarily denote positions along a vertical axis, since the wellbore and drill string may not be vertical. Unless otherwise indicated, the drawings appended hereto are presented with the uphole end at the left side of the drawing and the downhole end at the right side.

[0066] The sleeve assemblies and systems herein are positionable in a tubing string in a wellbore extending through multiple zones of a subterranean formation. Each zone may be stimulated/fractured with a treatment fluid (“frac treatment”) pumped through the tubing string. The terms “tubing” and “casing” are used interchangeably herein to refer to any series of tubes or pipes run downhole in a wellbore. [0067] In some embodiments, the wellbore is a horizontal wellbore. The term “horizontal wellbore” refers to a wellbore that has a first section extending substantially vertically downward from the surface followed by a substantially horizontal section. The horizontal section may extend approximately parallel to the surface. The “heel” of a horizontal wellbore refers to the transition between the vertical section and the horizontal section and the “toe” refers to the end of the horizontal section, opposite the heel. It will be understood that the first and horizontal sections of the wellbore may not be perfectly vertical or horizontal and deviations may occur along the length of the well.

[0068] As used herein, a “stage” or a “frac stage” may each be used to refer to a stage in a multi-stage completion process in which a particular formation zone is stimulated/fractured.

[0069] An example sleeve assembly 100 will be discussed with reference to Figures 1 to 2B. The sleeve assembly 100 may be incorporated into a tubing/casing string in a wellbore (not shown). The sleeve assembly 100 may be used as a “frac sleeve” to allow treatment fluid to be pumped into the wellbore at a desired stage of a multi-stage completion operation.

[0070] The sleeve assembly 100 may comprise a tubular housing 102 and an inner sleeve 104 (not visible in Figure 1 ). The sleeve assembly 100 has a closed configuration (Figure 2A) and an open configuration (Figure 2B).

[0071 ] Referring to Figures 2A and 2B, the tubular housing 102 has a first (uphole) end 101 and a second (downhole) end 103 and a longitudinal axis 105. The tubular housing 102 also has an inner surface 106 and an outer surface 108. The inner surface 106 defines an axial bore 110 extending through the tubular housing 102 along the longitudinal axis 105. The tubular housing 102 may comprise a single tubular body or two or more tubular bodies coupled together, with the axial bore 110 extending therethrough. A plurality of flow ports 112 extend radially from the inner surface 106 to the outer surface 108 for providing fluid communication between the axial bore 110 and the wellbore.

[0072] The inner sleeve 104 is received within the housing 102. The inner sleeve 104 has an inner surface 114 and an outer surface 116. The inner surface 114 defines an axial sleeve bore 118 therethrough. The inner sleeve 104 is slightly recessed into the housing 102 such that the sleeve bore 118 has approximately the same inner diameter as the remainder of the axial bore 110 in the housing 102. The combination of the axial bore 110 and the sleeve bore 118 form an axial flow passage 115 through the sleeve assembly 100 having a substantially equal inner diameter throughout. For greater clarity, the axial flow passage 115 extends axially (i.e. longitudinally) through the sleeve assembly 100 and does not include the flow ports 112, which extend radially through the housing 102 but not the inner sleeve 104.

[0073] The inner sleeve 104 is axially movable between first (closed) position (Figure 2A) position and a second (open) position (Figure 2B). The position of the inner sleeve 104 determines the configuration of the sleeve assembly 100. When the inner sleeve 104 is in the first position, the sleeve assembly 100 is in the closed configuration. In the closed configuration, the inner sleeve 104 blocks the flow ports 112 such that fluid in the axial bore 110 cannot exit through the flow ports 112 and into the wellbore. When the inner sleeve 104 is in the second position, the sleeve assembly 100 is in the open configuration. In the open configuration, the inner sleeve 104 is displaced from the flow ports 112, thus establishing fluid communication between the axial flow passage 115 and the wellbore and allowing fluid to exit the assembly 100 via the flow ports 112.

[0074] In this embodiment, the flow ports 112 are proximate the downhole end 103 of the tubular housing 102 and the inner sleeve 104 moves axially in the uphole direction from the first position to the second position. In other embodiments, the flow ports 112 may be disposed at the uphole end 101 of the tubular housing 102 and the inner sleeve 104 may move in the opposite direction. [0075] The sleeve assembly 100 may further comprise a control system 120. Figure 3 is a functional block diagram of the control system 120. The control system 120 in this embodiment comprises a controller 122, a power supply 124, an actuator 126, and a sensor 128.

[0076] The controller 122 may comprise at least one processor 130 and a memory 132. The memory 132 is operatively connected to the processor 130. The memory 132 stores processor-executable instructions therein that, when executed, cause the processor to implement one or more functions described herein. The memory 132 may also store control signal settings 134 and a control signal count 136, discussed in more detail below.

[0077] In some embodiments, the controller 122 further comprises a timing mechanism 138. The timing mechanism 138 may comprise a timer, an electronic clock, or any other suitable timing mechanism.

[0078] In some embodiments, the controller 122 further comprises a transceiver 140. The transceiver 140 is operatively connected to the processor 130. In some embodiments, the transceiver 140 comprises both a transmitter and a receiver sharing common circuitry. In other embodiments, the transceiver 140 comprises a separate transmitter and receiver. The transceiver 140 may be configured to send and receive communications over a communication network. The communication network may be a wired or wireless network. In other embodiments, the transceiver 140 may be omitted.

[0079] In some embodiments, the power supply 124 comprises one or more batteries, such as lithium-ion batteries. In some embodiments, the batteries are button batteries as discussed below with respect to Figures 5A and 5B. In other embodiments, the power supply 124 may comprise any other suitable batteries or any other suitable power source.

[0080] The actuator 126 may comprise at least one energetic material 123 and an initiator 125. The energetic material 123 may comprise an explosive material that can be discharged to generate a force to move the inner sleeve 104 axially within the housing 102. Discharging the energetic material 123 may generate a gas that provides pressure to push the inner sleeve 104 axially through the housing 102. The energetic material 123 may be a pyrotechnic material, a propellant, and/or any other suitable energetic material or combination of energetic materials. The energetic material be a low temperature energetic material (e.g. operating temperature of about 60°C) or a high temperature energetic material (e.g. operating temperature of about 175°C). In some embodiments, a single energetic material 123 may be employed. As one non-limiting example, the energetic material 123 may comprise boron potassium nitrate (BKNO3). In other embodiments, a combination of two energetic materials may be used, as discussed in more details with reference to Figure 6.

[0081 ] The initiator 125 is configured to initiate the discharge of the energetic material 123. For example, the initiator 125 may be configured to ignite the energetic material 123 by exposure to an elevated temperature. In some embodiments, the initiator 125 comprises an electronic initiator that is electrically coupled to the power supply 124 and operatively connected to the processor 130. In these embodiments, the processor 130 may selectively power the initiator 125 to cause the initiator 135 to heat up and ignite the energetic material 123. In some embodiments, the initiator 125 comprises a bridgewire. In these embodiments, the processor 130 draws power from the power supply 124, charging a capacitor bank (not shown). High current is released from the capacitor bank through the bridgewire, causing it to overheat and ignite the energetic material 123. In other embodiments, the initiator 125 may be any other suitable initiator that can cause the energetic material 123 to discharge.

[0082] In other embodiments, the actuator 126 may be any other suitable actuator that moves the inner sleeve 104 axially within the housing 102.

[0083] The sensor 128 is configured to sense a control signal sent from surface. The control signal may be sent as a particular pattern or code. In this embodiment, the control signal comprises a pressure pulse pattern. The pressure pulse pattern may be generated from surface via a small volume of fluid pumped into the wellbore by a pump (e.g. a frac and/or treatment pump). For example, adjusting the horsepower of the pump will result in a pressure pulse. The wellbore pressure may then be bled off at surface, such as to a location storage tank, resulting in a pressure bleed down ramp. A specific combination of pressure-up sequences and bleed down ramps within a set period of time constitutes a single pressure pulse pattern/code. The period of time may be, for example, between about 30 seconds and 5 minutes.

[0084] An example of a pressure pulse pattern 150 is shown in Figure 4. The pattern 150 has two pressure-up sequences with two bleed down ramps over a sliding time window of 1 minute, 30 seconds.

[0085] Referring again to Figure 3, the sensor 128 in this embodiment is configured to sense pressure pulses of fluid flowing through the axial flow passage 115 of the sleeve assembly 100. In some embodiments, the sensor comprises a strain gauge. Strain gauges have a number of advantages including high level of accuracy (for example, +/- 1 psi), reliability, cost-effectiveness as well as the ability to measure pressure without direct contact with the wellbore fluids. However, embodiments are not limited to strain gauges and, in other embodiments, the sensor 128 may comprise a pressure sensor or any other suitable type of sensor.

[0086] The processor 130 is operatively connected to the sensor 128 and may be configured to selectively power the sensor 128 via the power supply 124. In some embodiments, the processor 130 powers the sensor 128 for a set period of time to sense pressure pulses sent from surface and then deactivates the sensor 128 thereafter to conserve power.

[0087] The processor 130 is configured to receive the sensed pressure pulses from the sensor 128. The processor 130 may then determine if the sensed pressure pulses correspond to a pre-determined pressure pulse pattern (stored in the control signal settings 134 of the memory 132). Because the pressure pulse pattern is distinctive and generated within a short time period, it is very unlikely to be replicated by any other operation in the well and, thus, the processor 130 may not misconstrue other pressure variations in the wellbore as the pressure pulse pattern.

[0088] In some embodiments, if the sensed pressure pulses correspond to the pre-determined pattern, the processor 130 will count the number of pressure pulse patterns. The processor 130 may then increase a control signal count 136 after each correct pressure pulse pattern is sensed. The processor 130 may then determine if the control signal count 136 has reached a pre-determined count threshold (also stored in the control signal settings 134). In this manner, multiple sleeve assemblies may be installed within the same wellbore (such as the example systems 500 and 600 described below) responsive to the same pressure pulse pattern, with the respective control signal settings 134 of each sleeve assembly configured with a different count threshold. In some embodiments, a given sleeve assembly 100 may be programmed with two or more different pressure pulse patterns and/or two or more count thresholds, to allow the sleeve assembly 100 to be actuated at different stages of the wellbore completion.

[0089] The processor 130 may be configured to activate the actuator 126, via the initiator 125, responsive to the sensor 128 sensing the control signal. In some embodiments, the processor 130 activates the initiator 125 when the sensed pressure pulses from the sensor 128 are determined to correspond to the pre-determined pressure pulse pattern. In other embodiments, the processor 130 activates the initiator 125 when the count of pressure pulse patterns reaches the pre-determined threshold. The processor 130 may activate the initiator 125 by selectively powering the initiator 125 or by any other suitable means.

[0090] In some embodiments, the processor 130 activates the initiator 125 immediately after the pressure pulse pattern is received or the pre-determined count threshold has been met. In other embodiments, the timing mechanism 138 may be programmed with a time delay and the processor 130 may only activate the initiator 125 after a pre-determined period of time has passed. For example, the time delay may allow time for confirmation that a preceding sleeve assembly has been actuated to the open configuration, before actuating the next sleeve assembly in a planned sequence.

[0091 ] In some embodiments, the controller 122 transmits a confirmation signal, via the transceiver 140, to confirm that the correct pressure pulse pattern/code was received. The confirmation signal may be transmitted to a computing device at surface (not shown) including, but not limited to, a laptop, smart phone, or tablet. Alternatively, the controller 122 may transmit a signal that an incorrect pattern/code was received. In some embodiments, the surface computing device outputs an indication that the correct or incorrect pattern was received. The indication may be a visual indication or an audio indication. In some embodiments, the indication may by a colour change in the displayed code appearance on the computing device. For example, the displayed pressure pulse pattern/code may turn green if it is detectable downhole or red if it is not. As another example, an audible alert may be generated if the correct pattern is not detectable downhole.

[0092] In some embodiments, the controller 122 may be configured to receive, via the transceiver 140, instructions from a computing device at surface to reprogram the control signal settings 134. For example, a sleeve assembly 100 proximate the toe of the wellbore may initially be programmed as “sleeve 1” with a pre-determined count threshold of 1 and each sleeve assembly 100 in the uphole direction is programmed with an increasing sleeve number e.g. “sleeve 2”, “sleeve 3”, etc. After the first completion stage has been isolated, the next sleeve assembly 100 uphole of the isolation location may be reprogrammed as the new “sleeve 1” and subsequent uphole sleeve assemblies 100 renumbered accordingly so as to respond to the correct pulse pressure pattern/code.

[0093] Alternatively, or additionally, the control system 120 may be operable to communicate with a surface computing device via a monitoring or control cable, as discussed in more detail below. [0094] In some embodiments, the control system 120 may be designed with extra or redundant components to act as back-ups in the event that one or more components fail in the downhole environment. For example, the power supply 124 may comprise one or more back-up battery packs. As another example, the actuator 126 may comprise one or more back-up energetic materials 123.

[0095] In some embodiments, redundancy may be used with respect to the control system 120 itself to help ensure that the inner sleeve 104 is actuated at the correct time. For example, the sleeve assembly 100 may comprise two control systems 120 and each control system 120 may be configured to actuate the inner sleeve 104 in response to the same control signal or threshold. Thus, if the pattern/threshold is missed by one control system 120, the other control system 120 may still actuate the inner sleeve 104 at the proper time. As another example, the sleeve assembly 100 may comprise three control systems 120, which may be used to prevent premature actuation by requiring at last two of the controls systems 120 to receive the control signal (or reach the threshold) to activate the inner sleeve 104.

[0096] As another form of risk mitigation, the control system 120 may be configured to actuate the inner sleeve 104 in response to a separate and unique “back-up” control signal, such as a separate and unique pressure pulse pattern. The back-up control signal may be used to actuate the inner sleeve 104 in cases where the original control signal was missed and the inner sleeve 104 was not actuated at the proper time. In these embodiments, the back-up control signal may be specific to the sleeve assembly (or assemblies) 100 that did not actuate at the proper time and may be ignored by other sleeve assemblies.

[0097] Figures 5A and 5B are perspective views of the inner sleeve 104 of the sleeve assembly 100 showing one possible arrangement of the control system 120. In this embodiment, the control system 120 is positioned on the outer surface 116 of the inner sleeve 104, between the inner sleeve 104 and the housing 102. In other embodiments, the control system 120 may be at any other suitable position. [0098] The controller 122 may be in the form of a printed circuit board (PCB) in some embodiments. The controller 122 may be relatively compact with relatively low power consumption. In this embodiment, the power supply 124 comprises six button batteries 129, such as, for example, lithium-ion batteries. The batteries 129 may be rated for standard oil and gas temperatures (e.g. 200°C). At higher temperatures, more batteries 129 may be added to maintain time endurance. In other embodiments, the power supply 124 may comprise any other suitable number or type of batteries. The sensor 128 is positioned on the outer surface 116 of the inner sleeve 104 proximate the controller 122.

[0099] In this embodiment, the actuator 126 comprises a single energetic material 123. The energetic material 123 is arranged in a ring-shaped enclosure 127 extending at least partially around the circumference of the inner sleeve 104. The enclosure 127 may be disposed within a chamber 121 (visible in Figures 2A and 2B) between the inner sleeve 104 and the housing 102. The initiator 125 is not visible in Figures 5A and 5B but is operatively connected to the energetic material 123. When the energetic material 123 is discharged, gas may enter the chamber 121 to generate pressure to move the inner sleeve 104 axially within the housing 102.

[0100] An alternative embodiment of an actuator 200 is shown in Figure 6. The actuator 200 comprises a metal ring-shaped enclosure 202 enclosing an initiator 204, a primary energetic material 206, and a secondary (pressure producing) energetic material 210. In this embodiment, the primary energetic material 206 is positioned on either side of the initiator 204 and the secondary energetic material 210 is disposed on either side of the primary energetic material 206.

[0101 ] The enclosure 202 is configured to extend circumferentially around the outer surface 116 of the inner sleeve 104 and may be disposed within the chamber 121 (visible in Figures 2A and 2B) between the inner sleeve 104 and the housing 102. The geometry of the enclosure 202 and chamber 121 may be specifically selected to ensure the primary energetic material 206 and the secondary energetic material 210 are properly discharged such that sufficient pressure is generated to move the inner sleeve 104 uphole.

[0102] The primary energetic material 206 is an explosive material that can be discharged by being ignited by an exposure to high temperature. The primary energetic material 206 and the secondary energetic material 210 may be the same or different explosive materials. The material(s) of the secondary energetic material 210 may be configured to be discharged by a shock wave and not by ignition.

[0103] The initiator 204 is electrically connected via a cable 212 to a controller (not shown), such as the controller 122 of Figures 5A and 5B. In this example, the initiator 204 is a bridgewire that ignites the primary energetic material 206 by the mechanism discussed above, causing the primary energetic material 206 to explode. The primary energetic material 206 generates shock waves that in turn detonate the secondary energetic material 210. Gas from the discharge of the primary energetic material 206 and the secondary energetic material 210 exits the enclosure 202 via an outlet 214, thereby generating pressure to push the inner sleeve 104 axially in the uphole direction and into its uphole position.

[0104] Thus, embodiments of the sleeve assembly 100 may be actuated without requiring an actuation device (e.g. balls, darts) or a conveyed shifting tool. The sleeve assembly 100 may therefore be fully remotely operated, allowing the inner sleeve 104 to be actuated in response to control signals sent from surface such as pressure pulses. Moreover, the sleeve assembly 100 has no inner diameter (ID) restrictions, such as a ball or dart seat, and may thus maintain the full ID of the tubing string bore without requiring any milling out procedure.

[0105] Another example sleeve assembly 300 will be discussed with reference to Figures 7A to 70. The sleeve assembly 300 is configured to be installed as part of a tubing string within a wellbore (not shown). The sleeve assembly 300 may be used as an “isolation sleeve” to isolate a completion stage from subsequent stages uphole. The isolation sleeve assembly 300 has an inactive configuration (shown in Figure 7A) and an active configuration (shown in Figures 7B and 7C). In Figure 7C, the isolation sleeve assembly 300 is shown engaging a ball 350.

[0106] The sleeve assembly 300 in this embodiment comprises a tubular housing 302, an inner sleeve 304, a control system 320, and an engagement mechanism 330. The housing 302 has a first (uphole) end 301 , a second (downhole) end 303, and a longitudinal axis 305 (visible in Figure 7A). The housing 302 comprises an inner surface 306 and an outer surface 308. The inner surface 306 defines an axial bore 310 extending through the housing 302.

[0107] The inner sleeve 304 is received within the housing 302. The inner sleeve 304 is axially movable within the housing 302 between a first (uphole) position (Figure 7A) and a second (downhole) position (Figures 7B and 7C).

[0108] The inner sleeve 304 has an uphole end 307 and a downhole end 309. The inner sleeve 304 also has an inner surface 314 and an outer surface 316. The inner surface 314 defines an axial sleeve bore 318 therethrough. The inner sleeve 304 may be made of stainless steel or any other suitable material. The inner sleeve 304 is recessed into the housing 302 such that the sleeve bore 318 has the same inner diameter as the remainder of the axial bore 310 in the housing 302. The combination of the sleeve bore 318 and the axial bore 310 form an axial flow passage 315 through the sleeve assembly 300 having a substantially equal inner diameter throughout. The axial flow passage 315 also has approximately the same inner diameter as the bore of adjacent sections of the tubing string (not shown).

[0109] The control system 320 may be similar to the control system 120 of the sleeve assembly 100 as discussed above and may be disposed between the inner sleeve 104 and the housing 102. The control system 320 may comprise an actuator 326, a power supply (not shown), a sensor such as a strain gauge or pressure sensor (not shown), and a controller 322. The controller 322 may comprise a processor and a memory and may optionally comprise a timing mechanism and/or a transceiver (not shown). The controller 322 may activate the actuator 326 to axially shift the inner sleeve 304 to its downhole position in response to a control signal sent from surface. In some embodiments, the control signal is a pressure pulse pattern sensed by the sensor and the controller 322 may activate the actuator 326 when a count of pressure pulse patterns reaches a pre-determined threshold, as described above for the control system 120.

[0110] The engagement mechanism 330 is operatively connected to the inner sleeve 104 and configured to engage a fluid blocking element to block fluid flow through the axial flow passage 315. The term “fluid blocking element” in this context is used to refer to any structure or device that can block fluid flow through the axial flow passage 315. The fluid blocking element may also be referred to as an “isolation element”. In this embodiment, the fluid blocking element is a ball 350 (visible in Figure 7C). The ball 350 may be dissolvable or non-dissolvable. In other embodiments, the fluid blocking element may be a dart, collet, or any other suitable structure or device.

[0111 ] In this embodiment, the engagement mechanism 330 comprises a swagable portion 332 at the downhole end 309 of the inner sleeve 304. As used herein, “swagable” refers to the ability to bend or deform upon application of pressure or compressive force. The swagable portion 332 may be a thin section of metal that swages when pressed against another surface. In some embodiments, the swagable portion 332 is integral with the inner sleeve 304 itself. In other embodiments, the swagable portion 332 may a separate ring coupled to the inner sleeve 304 by any suitable means. In yet other embodiments, the swagable portion 332 may be a separate ring that abuts the inner sleeve 304 at its downhole end 309 but is not coupled thereto. The swagable portion 332 may be made of the same material as the rest of the inner sleeve 304 (e.g. stainless steel) or may be made of a different material (e.g. a different metal). In some embodiments, the swagable portion 332 may be coated with rubber or another resilient material to facilitate a tight seal with the ball 350.

[0112] The engagement mechanism 330 has an inactive state (shown in Figure 7A) and an active state (shown in Figures 7B and 7C). When the engagement mechanism 330 is in its inactive state, the swagable portion 332 is approximately axially aligned (i.e. collinear) with the rest of the inner sleeve 304. When the engagement mechanism 330 is in its active state, the swagable portion 332 is bent (swaged) radially inwards into the axial flow passage 315 to form an annular shoulder 333. The shoulder 333 may also be referred to as a “ball seat”. The shoulder 333 may only project slightly into the axial flow passage 315 (e.g., 1/8 of an inch) so as not to restrict the inner diameter of the inner sleeve 304.

[0113] The engagement mechanism 330 is actuated from the inactive state to the active state by the axial movement of the inner sleeve 304. When the inner sleeve 1304 moves in the downhole direction, the swagable portion 332 may be pushed against an angled inner ridge 331 of the housing 302. The pressure of the inner sleeve 304 against the inner ridge 331 bends (i.e. swages) the swagable section 332 inwards to form the shoulder 333. The axial movement of the inner sleeve 304 may be much smaller than that of the inner sleeve 104 of the sleeve assembly 100 as only a slight shift may be used to bend the thin, swagable section 332.

[0114] The shoulder 333 (i.e. the active swagable section 332) in this embodiment is curved, which may allow the shoulder 333 to securely engage the ball 350 (as shown in Figure 7C). The curve of the shoulder 333 may be a gentle curve so as to engage the ball 350 at its widest (or close to widest) section. The shoulder 333 thereby forms a large contact area with the ball 350. This contact area is much larger than the contact between a ball and a ball seat in a conventional ball drop system, which is typically only a line contact. The shoulder 333 may thereby allow formation of a seal with the ball 350, including in cases where the ball 350 may be damaged.

[0115] In the embodiment shown in Figure 7C, the ball 350 securely locks into place with the shoulder 333 of the inner sleeve 1304. This configuration may be particularly useful in high-pressure applications in which the ball 350 is dissolvable. In these embodiments, compression of the dissolvable material of the ball 350 may give the ball 350 greater strength to withstand high-pressure frac operations or screenouts.

[0116] In other embodiments, the ball 350 may not lock in place with the shoulder 333 of the inner sleeve 304. This configuration may be particularly useful in low-pressure applications with a dissolvable ball 350 or high-pressure applications with a non-dissolvable ball 350 in which the formation has the ability to flow the ball 350 back to surface quickly without the requirement for dissolving.

[0117] Other variations of the engagement mechanism 330 are also possible for engaging a ball or any other suitable fluid blocking element. For example, the engagement mechanism may comprise a thin inner sleeve that is deformed (e.g. bent or crumpled) to form a shoulder or seat to engage a ball, a dart, or another suitable device. In some embodiments, a wedge or ring may be provided behind the sleeve to support the shoulder/seat. In yet other embodiments, the engagement mechanism may comprise a collapsible ring, such as a spiral ring or C-ring. Another example of an alternative engagement mechanism will be discussed below with reference to the sleeve assembly 700 of Figures 11A-13.

[0118] Thus, when the sleeve assembly 300 is in the inactive configuration, the sleeve assembly 300 has no ID restrictions. When it is desired to isolate a given stage of the wellbore, the sleeve assembly 300 may be remotely actuated to form a shoulder 333 for a fluid blocking element. As the shoulder 333 only projects slightly into the axial flow passage 315 (e.g., 1/8 of an inch), there is minimal ID restriction and the sleeve assembly 300 therefore maintains what is considered to be full bore access according to industry standards. Thus, the shoulder 333 may not need to be milled out prior to production. In addition, the slight projection of the shoulder 333 may also allow frac flow to be less turbulent compared to systems with conventional ball seats, which may help to protect the shoulder 333 from erosion. Further potential advantages are discussed in more detail below. [0119] Figures 8A and 8B are cross-sectional views of an example system 400 including the sleeve assembly 100 of Figures 1 -2B and the sleeve assembly 300 of Figures 7A-7C. The system 400 may also be referred to as the “sleeve assembly pair” 400. The system 400 may be incorporated into a tubing string within a wellbore (not shown) at the location of a particular zone of the formation. In some embodiments, the wellbore is a horizontal wellbore. The system 400 may be arranged in series with other systems having the same or a similar structure (such as in the system 500 described below). The system 400 has an inactive configuration (Figure 8A) and an active configuration (Figure 8B).

[0120] In this embodiment, the sleeve assembly 100 is positioned downhole of the sleeve assembly 300. The sleeve assembly 100 functions as a “frac sleeve” to allow treatment fluid to be pumped into the wellbore (via flow ports 112) at a desired stage of a multi-stage completion operation. The sleeve assembly 300 functions as an “isolation sleeve” to isolate that stage from subsequent stages uphole.

[0121 ] The sleeve assemblies 100 and 300 in this embodiment are directly coupled to one another. In other embodiments, the sleeve assemblies 100 and 300 may be interconnected by one or more tubing sections of the tubing string. The axial flow passages 115 and 315 of the sleeve assemblies 100 and 300 are aligned and form a combined flow passage 515. As the sleeve assemblies 100 and 300 have no (or minimal) ID restrictions, the axial flow passage 515 has approximately the same inner diameter as the overall axial bore of the tubing string.

[0122] Referring to Figure 8A, when the system 400 is in the inactive configuration, the flow ports 112 of the sleeve assembly 100 are blocked by the inner sleeve 104 and the engagement mechanism 330 of the inner sleeve 304 is in its inactive (unswaged) state. Treatment fluid may thereby be pumped through the full diameter of the flow passage 515 to another system or sleeve assembly downhole (not shown). When it is desired to stimulate/fracture the formation zone around the system 400, a pressure pulse pattern is sent from surface, which is sensed by the sensors of the sleeve assemblies 100, 300. The respective controllers 122, 322 of the sleeve assemblies 100, 300 may then determine if the pressure pulse pattern corresponds to the pre-determined pattern and if the count of patterns has reached the pre-determined count threshold. In some embodiments, the sleeve assemblies 100, 300 are configured to respond to the same pressure pulse pattern/threshold. In other embodiments, the sleeve assemblies 100, 300 may be responsive to individual pulse patterns or the same pattern but different thresholds.

[0123] If the patterns match and/or the count threshold has been reached, the respective controllers 122, 322 will actuate the inner sleeve 104 to its uphole (open) position and the inner sleeve 304 to its downhole position, thereby exposing/opening the flow ports 112 of the sleeve assembly 100 and activating the engagement mechanism 330 of the sleeve assembly 300 to form the shoulder 333. The system 400 is thereby in its active configuration, as shown in Figure 8B.

[0124] With the flow ports 112 of the sleeve assembly 100 open, treatment fluid may be pumped into the wellbore via the flow ports 112. After the stimulation/fracturing at this stage is completed, a ball (not shown) may be sent downhole and the ball may engage the shoulder 333 of the engagement mechanism 330 of the sleeve assembly 300. The ball blocks fluid from flowing downhole through the assembly 300 and into the assembly 100 (i.e. through the axial flow passage 315). This completion stage is now fully pressure isolated from subsequent stages uphole.

[0125] In some embodiments, the inner sleeves 104, 304 are actuated simultaneously. In other embodiments, there may be a time delay between actuation of the inner sleeve 104 of the frac sleeve assembly 100 and the inner sleeve 304 of the isolation sleeve assembly 300. This time delay may be programmed into the timing mechanism of the controller 322. In some embodiments, the time delay is based on the frac pump time. For example, if the planned frac time at this stage is 90 minutes (i.e. 90 minutes of pumping frac sand, before transitioning to pumping displacement fluid), the actuation of the inner sleeve 304 (and thus the activation of the engagement mechanism 330) may be delayed by around 90 minutes or more such that the formed shoulder 333 is not exposed to frac sand, only clean displacement fluid.

[0126] By only activating the engagement mechanism 330 of the “isolation sleeve” 400 at the same time, or shortly after, the “frac sleeve” 100 is opened to allow stimulation/fracturing of the surrounding formation zone, the shoulder 333 may only be exposed to fluid flow at one stage in the completion process. The shoulder 333 may also only be exposed to one full bore pressure, and the pressure cycling of one frac stage only, with no other pressure cycling exposures. Thus, potential erosion or other damage to the shoulder 333 may be mitigated and the shoulder 333 can still function even if the system 400 is at one of the last frac stages.

[0127] Once the wellbore has been fully completed, the ball may be dissolved or flowed back to surface, thereby allowing fluid to again flow through the system 400. As discussed above, as the shoulder 333 of the engagement mechanism 330 only slightly projects into the axial flow passage 315, the tubing string maintains substantially its full inner diameter. Thus, unlike conventional ball and dart systems, there are no ball/dart seats that need to be milled or drilled out before commencing production.

[0128] The system 400 in this embodiment is only automatically actuatable from the inactive configuration to the active configuration. However, the sleeve assemblies 100 and 300 of the system 400 may be manually shifted back to their original configurations by coiled tubing/service rig operations using a mechanical shifting tool. In other embodiments, the sleeve assembly 100 and/or 300 may be designed to be automatically actuatable back to their original configurations.

[0129] Optionally, the system 400 may further comprise a monitoring or control cable 402, indicated by a dashed line in Figures 8A and 8B. The monitoring/control cable 402 may run alongside the liner/casing of the wellbore (not shown) or may be integrated into the system 400. The cable 402 may comprise fiber optic cable only, such as, for example, a fiber optic distributed temperature sensing (DTS) system or a fiber optic distributed acoustic sensing (DAS) system. Alternatively, the cable may comprise a combination of fiber optics and electrical cable(s).

[0130] The cable 402 may be used to monitor the sleeve assemblies 100, 300 of the system 400. In some embodiments, the cable 402 may be used to detect the actuation of the inner sleeves 104 and/or 304 of the sleeve assemblies 100, 300. For example, the acoustic signature from detonation of the propellent of the actuators 126, 326 may be detected by a DAS system or any other suitable form of acoustic monitoring system. Alternatively, the controllers 122, 322 may each comprise a piezoelectric “clicker” to communicate an acoustic code from the sleeve assemblies 100, 300 to the DAS system. The acoustic code may indicate the pressure from the sensors (e.g. strain gauges) of the sleeve assembly 100 or 300.

[0131] In other embodiments, where the cable 402 comprises a DTS system, the cable 402 may be used to determine flow paths of the treatment fluid, which is colder than the surrounding formation.

[0132] Alternatively, or additionally, the cable 402 may be used to communicate control signals to the sleeve assemblies 100, 300 of the system 400. For example, the cable 402 may be manufactured with “nodes” spaced to be positioned at each sleeve assembly 100, 300 to electrically send commands to the sleeve assemblies 100, 300. In this example, one option would be to incorporate shock sensors into the control systems 120, 320 of the sleeve assemblies 100, 300 and communicate control signals from the cable 402 via a reverse piezoelectric “clicker”. The cable 402 may communicate control signals to the sleeve assemblies 100, 300 as an alternative to the pressure pulse patterns described above or the cable 402 may be a back-up in the event that one of the sleeve assemblies 100,300 fails to respond to the pressure pulse pattern (e.g. if a sensor is faulty).

[0133] Figures 9A-9D show another example system 500 at various steps in a completion process. The system 500 may be incorporated into a tubing string installed in a wellbore (not shown). In some embodiments, the wellbore is a horizontal wellbore.

[0134] The system 500 comprises a series of sleeve assembly pairs, with each sleeve assembly pair comprising a sleeve assembly 100 (i.e. a “frac sleeve”) and a sleeve assembly 300 (i.e. an “isolation sleeve”). Each sleeve assembly pair is therefore equivalent to the system 400 of Figures 8A and 8B.

[0135] In Figures 9A-9D, the system 500 comprises two sleeve assembly pairs: a first sleeve assembly pair 502A, and a second sleeve assembly pair 502B. Although the sleeve assembly pairs 502A are 502B are shown adjacent to one another, it will be understood that, in operation, they would be connected by a portion of the tubing string therebetween. It will also be understood that the system 500 may comprise additional sleeve assembly pairs (not shown) extending in the uphole direction towards the heel of the wellbore.

[0136] In some embodiments, the first sleeve assembly pair 502A is positioned proximate the toe of the well above the cement completion equipment (not shown) such as a float shoe/collar, etc. In these embodiments, the sleeve assembly 100 of the first sleeve assembly pair 502 may function as a “toe sleeve” or “toe sub”. In other embodiments, the first assembly pair 502A may be at any other suitable position along the wellbore.

[0137] Referring to Figure 9A, the system 500 may be initially run into the wellbore with the sleeve assembly pairs 502A and 502B in their inactive configurations. In the inactive configuration, the flow ports 112 (not visible in Figure 9A) of the sleeve assembly 100 are blocked by the inner sleeve 104 and the engagement mechanism 330 of the sleeve assembly 300 is in its inactive state. The wellbore may be completely pressure isolated at this stage, for example, by cement float equipment at the toe of the well (not shown). The wellbore may therefore be pressure tested to 100% of its pressure capacity to confirm the integrity of the wellbore. [0138] A first control signal is then sent through the wellbore from surface. In this embodiment, the control signal is a pressure pulse pattern such as the pressure pulse pattern 150 shown in Figure 4. In this embodiment, the sleeve assembly pairs 502A and 502B are programmed with the same pre-determined pressure pulse pattern, but different count thresholds. Thus, when the first pressure pulse pattern is sent through the wellbore, the respective controllers of the sleeve assembly pairs 502A, 502B will count this pattern as “1”. In other embodiments, different pressure pulse patterns may be used for different sections of the well or an individual pressure pulse pattern may be used for each individual sleeve assembly pair in the system 500.

[0139] The first sleeve assembly pair 502A is configured with a count threshold of “1” and will therefore be actuated in response to the first pressure pulse pattern. As shown in Figure 9B, the first sleeve assembly pair 502A is now in the active configuration, with the flow ports 112 opened. The engagement mechanism 330 is also activated such that the shoulder 333 is available to engage a ball or another fluid blocking element. A first frac treatment is then pumped through the flow ports 112 of the first sleeve assembly pair 502A (indicated by the dashed arrows in Figure 9B). The frac treatment may then be displaced by pumping a displacement fluid through the wellbore.

[0140] Referring now to Figure 9C, a first dissolvable ball 550A may be pumped from surface, for example, in the displacement fluid. The ball 550A engages the shoulder 333 of the first sleeve assembly pair 502A. The portion of the well uphole of the first sleeve assembly pair 502A may now be pressure isolated. Further, once the ball 550A is engaged with the shoulder 333, a full wellbore capacity pressure test (e.g., a straight line pressure test) may be conducted. Of note, this type of testing is not available for other conventional systems including ball and dart systems and-plug and-perf technologies without well intervention later to remove the stage isolation devices. The pressure test may confirm that there are no leaks between the ball 550A the shoulder 333 and, thus, that the well is isolated above the first sleeve assembly pair 502A. The displacement volume may also be used to confirm from surface that the ball 550A is seated in the first sleeve assembly pair 502A and not in other sleeve assemblies positioned uphole in the wellbore.

[0141 ] The pressure isolation of the wellbore at the first sleeve assembly pair 502A also allows a second pressure pulse pattern to now be sent through the wellbore. The second pressure pulse pattern may be counted by the second sleeve assembly pair 502B as “2” and the second sleeve assembly pair 502B may then be actuated to its active configuration, with the flow ports 112 of the sleeve assembly 100 opened and the shoulder 333 formed in the sleeve assembly 300. A second frac treatment may then be pumped through the flow ports 112 of the second sleeve assembly pair 502B (indicated by the dashed arrows in Figure 9C). The frac treatment may then be displaced by pumping a displacement fluid through the wellbore.

[0142] Referring now to Figure 9D, a second dissolvable ball 550B may then be pumped from surface in the displacement fluid to engage the shoulder 333 of the second sleeve assembly pair 502B. The well uphole of the second sleeve assembly pair 502B may now be pressure isolated, allowing another full wellbore capacity pressure test to be conducted before initiating the next frac stage and a third pressure pulse pattern to be sent through the wellbore from surface.

[0143] This process may then be repeated in the same manner for additional sleeve assembly pairs, extending uphole in the wellbore towards the heel. A full wellbore pressure test may be performed at each stage to confirm pressure isolation and the isolation location before proceeding with the next stage. As noted above, such confirmation is not possible with conventional ball/dart systems or plug-and-perf systems.

[0144] In some embodiments, a single isolation sleeve 300 is paired with a single frac sleeve 100. In other embodiments, one or more isolation sleeves 300 may each be paired with a group/cluster of two or more frac sleeves 100. The two or more frac sleeves 100 may allow treatment fluid to be pumped into the wellbore (via flow ports 112) at several locations within a desired stage of a multi-stage completion operation. As each isolation sleeve 300 may provide complete wellbore isolation, each cluster 602 can include any number of frac sleeves 100.

[0145] A non-limiting exemplary embodiment of a system 600 having a group/cluster configuration is shown in Figure 10. In this embodiment, a first frac sleeve 100A is positioned proximal the toe of the well thereby acting as a toe sub and a first isolation sleeve 300A is positioned uphole of the first frac sleeve 100A. A cluster 602 of three frac sleeves 100B, 100C, and 100D is positioned uphole of the first isolation sleeve 300A, followed by a second isolation sleeve 300B. This pattern may be repeated in the uphole direction with additional clusters of frac sleeves 100 positioned between respective isolation sleeves 300. The individual frac sleeves 100 in each cluster can be actuated concurrently or sequentially, for example, by configuring their pressure pulse pattern count threshold to be the same or different.

[0146] Therefore, embodiments of the sleeve assemblies and systems described herein may provide a number of advantages over conventional systems. Firstly, the disclosed sleeve assemblies and systems may allow for confirmation of wellbore pressure integrity (i.e. stage isolation) before each frac stage, and confirmation of stage isolation location before initiating the frac treatment, which is not possible in conventional systems. In addition, when the sleeve assembly 100 is used as a toe sub, the sleeve assembly 100 may be capable of opening below reservoir breakdown pressure or at no hydrostatic pressure differential.

[0147] Further, as discussed above, the sleeve assembly 100 has no ID restrictions and the sleeve assembly 300 has no ID restrictions in its inactive configuration. When the engagement mechanism 330 is activated, the ID reduction from the shoulder 333 is minimal such that the sleeve assembly 300 (and systems 400 and 500) may still be considered “full bore” according to industry standards. Thus, full-bore access to the entire wellbore may be obtained without requiring well interventions such as cleanout or millout pre- or post-fracturing. [0148] Maintaining full bore ID also allows for an increased (or maximum) frac rate, which in turn allows for fewer, longer horizontal wells to be drilled in a given formation. The wells may also be drilled with greater spacing therebetween. Thus, less drilling may be required overall, while still maximizing field production and drainage. Less drilling may also translate to significantly lower completion costs. In addition, an unlimited number of frac stages may be performed, with unlimited clusters of “frac sleeves” per stage. The sleeve assemblies may also be re-closable to allow for multiple frac cycles.

[0149] Moreover, the disclosed systems may also provide more reliable dissolvability of dissolvable balls (or other fluid blocking elements). In conventional systems, the seated ball/dart/col let is typically positioned downhole of the open flow ports. Thus, some of the fluid pumped through the tubing string to dissolve the ball/dart/col let will be lost through the flow ports before it reaches the ball/dart/col let. In contrast, in the systems 400 and 500, the isolation shoulder 333 (and thus the seated ball) is positioned uphole of the flow ports 112 of a given sleeve assembly pair. Thus, fluid pumped downhole is not diverted before it reaches the ball and the ball is more readily dissolved.

[0150] The sleeve assemblies and systems disclosed herein may be used as alternatives to a number of conventional systems including: plug-and-perf systems (single well per pad or multiple wells per pad), coiling tubing completions, dart-based systems, ball drop systems, collet-based systems, and mechanical toe subs. In addition, hybrid applications are also possible, including plug-and-perf or coiled tubing completions using one of the disclosed sleeve assemblies at the toe or ball drop systems using one of the disclosed sleeve assemblies at the heel. The sleeve assemblies and systems described herein may be suitable for cemented single port entry applications, cemented multiple port entry applications, open hole applications, and/or any other suitable applications.

[0151 ] An alternative sleeve assembly 700 will be discussed with reference to Figures 11A-13. [0152] Referring to Figures 11A and 11 B, the sleeve assembly 700 is shown as part of a tubing string 701 within a wellbore 703. The sleeve assembly 700 has an inactive configuration (shown in Figure 11 A) and an active configuration (shown in Figure 11 B).

[0153] The sleeve assembly 700 comprises a tubular housing 702, an inner sleeve 704, a control system 720, and an engagement mechanism 730. The housing 702 comprises an inner surface 706 and an outer surface 708. The inner surface 706 defines an axial bore 710 extending through the housing 702. In some embodiments, the housing 702 further defines a plurality of flow ports 712, similar to the flow ports 112 of the assembly 100. In other embodiments, the flow ports 712 may be omitted (such as in the embodiment of the sleeve assembly 700 in the system 800, discussed below).

[0154] The inner sleeve 704 is received within the housing 702. The inner sleeve 704 has an inner surface 714 and an outer surface 716. The inner surface 714 defines an axial sleeve bore 718 therethrough. The inner sleeve 704 is recessed into the housing 702 such that the sleeve bore 718 has the same inner diameter as the remainder of the axial bore 710 in the housing 702. The combination of the sleeve bore 718 and the axial bore 710 form an axial flow passage 715 through the sleeve assembly 700 having a substantially equal inner diameter throughout. The axial flow passage 715 also has approximately the same inner diameter as the bore of adjacent sections of the tubing string 701 .

[0155] The inner sleeve 704 is axially movable within the housing 702 between a first (downhole) position (Figure 11 A) position and a second (uphole) position (Figure 11 B). In this embodiment, when the inner sleeve is in the downhole position, the inner sleeve 704 blocks the flow ports 712. When the inner sleeve 704 is in the uphole position, the inner sleeve 704 is displaced from the flow ports 712, thus establishing fluid communication between the axial bore 710 and the wellbore and allowing fluid to flow out of the axial flow passage 715 and into the wellbore via the flow ports 712. [0156] The control system 720 may be similar to the control system 120 of the sleeve assembly 100 as discussed above. In this embodiment, the control system 720 is positioned on the outer surface 716 of the inner sleeve 704, between the inner sleeve 704 and the housing 702. The control system 720 may comprise an actuator 726, a power supply (not shown), a strain gauge or another suitable sensor (not shown), and a controller 722. The controller 722 may comprise at least one processor and at least one memory (not shown). In some embodiments, the controller 722 further comprises a timing mechanism such as an electronic clock. The controller 722 may activate the actuator 726 to axially shift the inner sleeve 704 to its uphole position in response to a pressure pulse pattern sensed by the sensor and/or when a count of pressure pulse patterns reaches a pre-determined threshold, as described above for the control system 120.

[0157] The engagement mechanism 730 will be described in more detail with reference to Figures 12A and 12B. The engagement mechanism 730 has an inactive state (Figure 11A and 12A) and active state (Figure 11 B and 12B).

[0158] The engagement mechanism 730 is configured to engage a fluid blocking element. In this embodiment, the engagement mechanism 730 is configured to engage a ball 750 (visible in Figure 13). The engagement mechanism 730 may comprise an annular sealing member 732 and a mechanical backup 734, received within the housing 702 adjacent to the inner sleeve 704.

[0159] The annular sealing member 732 is in the form of a ring and may be made of a resilient material such as rubber, polyetheretherketone (PEEK), or any other suitable material. The sealing member 732 has an inner surface 733 and an outer surface 735, the inner surface 733 defining a central opening 738 therethrough.

[0160] The annular sealing member 732 in this embodiment is compressible and has a decompressed (inactive) state (Figure 11A and 12A) and a compressed (active) state (Figure 11 B and 12B). When the sealing member 732 is decompressed, the sealing member 732 is recessed within the housing 702 such that the inner surface 733 is approximately aligned with the inner surface 714 of the inner sleeve 704 and the inner surface of the adjacent section of the tubing string 701 . The central opening 738 therefore has approximately the same inner diameter as the axial flow passage 715 as well as the bore of the adjacent section of the tubing string 701. When the sealing member 732 is compressed, the inner surface 733 projects radially inwards to form an annular shoulder 744 that can engage the ball 750. Formation of the annular shoulder 744 narrows the central opening 738 such that the central opening 738 has a smaller inner diameter than the axial flow passage 715 and the bore of the tubing string 701 .

[0161 ] The mechanical backup 734 is configured to support the annular shoulder 744 formed by the annular sealing member 732. The mechanical backup 734 in this embodiment is in the form of a collet. In other embodiments, the mechanical backup 734 may comprise any other suitable structure such as, for example, a metal shoulder formed by metal forming or swaging. In yet other embodiments, the mechanical backup 743 may be omitted.

[0162] The mechanical backup 734 has an inner surface 739 and an outer surface 741. The inner surface 739 defines a channel 742 therethrough. The mechanical backup 734 in this embodiment is collapsible and has an expanded (inactive) and a collapsed (active) state. When the mechanical backup 734 is expanded, the inner surface 739 is approximately aligned with the inner surface 733 of the annular sealing member 732 and the inner surface 714 of the inner sleeve 704. The channel 742 thereby has approximately the same inner diameter as the axial flow passage 715 and the central opening 737 of the sealing member 732. When the mechanical backup 734 is collapsed, the inner surface 739 projects radially inwards to narrow the channel 742 proximate the annular sealing member 732 (i.e. the uphole end of the mechanical backup 734). The channel 742 therefore has a smaller inner diameter than the axial flow passage, and approximately the same inner diameter as the annular sealing member 732 in its compressed state. [0163] When the annular sealing member 732 and the mechanical backup 734 are in their decompressed and expanded states, respectively (i.e. their respective inactive states), the engagement mechanism 730 is in its inactive state and the sleeve assembly 700 is in its inactive configuration. When the annular sealing member 732 and the mechanical backup 734 are in their compressed and collapsed states, respectively (i.e. their respective active states), the engagement mechanism 730 is in its active state and the sleeve assembly 700 is in its active configuration.

[0164] The axial movement of the inner sleeve 704 may activate the engagement mechanism 730 from its inactive state to its active state. When the inner sleeve 704 is in its downhole position (Figure 11A and 12A), the inner sleeve 704 is spaced axially from the engagement mechanism 730. When the inner sleeve 404 moves to its uphole position (Figure 11 B and 12B), the inner sleeve 704 abuts the pushes the mechanical backup 734 in the uphole direction. The mechanical backup 734 slides uphole into a tapered portion 746 of the housing 702 (visible in Figure 11 A and 12A), causing the mechanical backup 734 to collapse. As the mechanical backup 734 moves uphole, it pushes against the annular sealing member 732, causing the annular sealing member 732 to compress and form the annular shoulder 744. In some embodiments, the inner sleeve 704 then locks into the uphole position, thereby locking the annular sealing member 732 in its compressed state and the mechanical backup 734 in its collapsed state to maintain the annular shoulder 744.

[0165] The annular shoulder 744 may only project slightly into the axial flow passage 715 (e.g. 1/8 of an inch) which is still considered to be full bore access according to industry standards. In other embodiments, the shoulder 744 may project further radially inward. A larger shoulder 744 may be helpful in wells that pose casing deformation problems, for example.

[0166] Figure 13 shows the engagement mechanism 730 in its active state engaging a ball 750. The ball may be dissolvable or non-dissolvable. The ball 750 may be a large-diameter ball, with an outer diameter just slightly less than the inner diameter of the bore of the tubing string 701 and the axial flow passage 715 of the sleeve assembly 700.

[0167] The ball 750 engages the shoulder 744 and extends through the central opening 738 of the annular sealing member 732 and into the channel 742 of the mechanical backup 734. The annular sealing member 732 forms a seal around the ball 750 at, or close to, the widest portion of the ball 750, thereby forming a large sealing area (indicated by dashed circle “A” in Figure 13). This sealing area is much larger than the typical line contact between a ball and a ball seat in a conventional ball drop system.

[0168] As the sealing member 732 is made of rubber or another resilient material, the sealing member 732 conforms to the shape of the ball 750 to form a tight seal. This conformation of the sealing member 732 around the ball 750 may also allow the sealing member 732 to maintain a consistent seal around the ball 750, even if the ball 750 has nicks or scratches due to its travel through the tubing string 701. Thus, the ball 750 may not require a surface coating, which is often required for balls in ball drop systems.

[0169] Therefore, when the engagement mechanism is in its active state, the axial flow passage 715 of the sleeve assembly 700 is completely sealed by the engagement of the ball 750 with the engagement mechanism 730. The sleeve assembly 700 in this embodiment may therefore function as both a “frac sleeve” to allow treatment fluid to be pumped into the wellbore via the flow ports 712 and an “isolation sleeve” to isolate the wellbore at the location of the sleeve assembly 700.

[0170] Other variations are also possible and the engagement mechanism 730 may be adapted to engage other fluid blocking elements such as darts, cages, collets, etc. The fluid blocking element may be dissolvable or non-dissolvable.

[0171 ] In alternative embodiments, the annular sealing member 732 may be positioned within another actuatable inner sleeve (not shown). This second inner sleeve may be axially movable within the housing 702 between a first position in which the inner sleeve conceals the annular sealing member 732 from the fluid in the axial flow passage 715 and a second position in which the inner sleeve is displaced from the annular sealing member 732, thereby exposing the annular sealing member 732 for engagement with a ball or another fluid blocking element. In some embodiments, the mechanical backup 734 is also protected by the inner sleeve.

[0172] Figures 14A and 14B are side, cross-sectional views of an example completion system 800 including the sleeve assembly 100 of Figures 1 -2B and the sleeve assembly 700 of Figures 11A-11 B. The system 800 has an inactive configuration (Figure 14A) and an active configuration (Figure 14B). The system 800 may be incorporated into a tubing string 801 within a wellbore (not shown) at the location of a particular zone of the formation. The system 800 may be arranged in series with other systems having the same or a similar structure.

[0173] In this embodiment, the sleeve assembly 100 is positioned downhole of the sleeve assembly 700. The sleeve assembly 100 functions as a “frac sleeve” to allow treatment fluid to be pumped into the wellbore (via flow ports 112) and the sleeve assembly 700 functions as an “isolation sleeve” to isolate the wellbore at the location of the sleeve assembly 700. Of note, the sleeve assembly 700 in this exemplary embodiment does not have the flow ports 712 as in the embodiment shown in Figures 11 A-11 B.

[0174] The sleeve assemblies 100 and 700 are interconnected by a tubing section 802 of the tubing string 801 . Only a portion of the tubing section 802 is shown for illustrative purposes. The axial flow passages 115 and 715 of the sleeve assemblies 100 and 700 form part of an overall axial bore 804 extending through the tubing string 801 .

[0175] Figure 14A shows the system 800 in its inactive configuration in which the flow ports 112 of the sleeve assembly 100 are blocked by the inner sleeve 104 and the engagement mechanism 730 of the sleeve assembly 700 is in its inactive state. In this configuration, treatment fluid may be pumped through the full diameter of the axial bore 804 to another system or sleeve assembly downhole (not shown). When it is desired to stimulate/fracture the formation zone around the system 800, a pressure pulse pattern is sent from surface, which is sensed by the sensors of the first and second sleeve assemblies 100, 700. The respective controllers 122, 722 of the sleeve assemblies 100, 700 may then actuate the respective inner sleeves 104, 704 to their uphole positions, thereby transitioning the system 800 to its active configuration, as shown in Figure 14B.

[0176] As discussed above with respect to the system 400, the sleeve assemblies 100, 700 may be configured to respond to the same pressure pulse pattern/threshold or a different pressure pulse pattern/threshold.

[0177] In some embodiments, the inner sleeves 104, 704 are actuated simultaneously. In other embodiments, there may be a time delay between actuation of the inner sleeve 104 of the sleeve assembly 100 and the inner sleeve 704 of the sleeve assembly 700. By only activating the engagement mechanism 730 of the sleeve assembly 700 at the same time as (or after) the flow ports 112 of the sleeve assembly 100 are opened, the exposure of the annular shoulder 744 to frac sand, as well as to full bore pressure, may be minimized. This protection of the shoulder 744 may allow the annular sealing member 732 to be made from a variety of different materials, including materials that cannot typically be used for ball seats of conventional ball drop systems.

[0178] Referring now to Figure 14B, when the system 800 is in the active configuration, the flow ports 112 of the sleeve assembly 100 are exposed and the engagement mechanism 730 is in its active state forming the shoulder 744. In this configuration, treatment fluid may be pumped into the wellbore via the flow ports 112. After the stimulation/fracturing at this stage is completed, a dissolvable ball 850 may be sent downhole to engage the shoulder 744. The ball 850 blocks fluid from flowing downhole through the assembly 700 and into the assembly 100. The shoulder 744 may seal around the ball 750 and, thus, this stage is now fully pressure isolated from subsequent stages uphole. As discussed above, this pressure isolation allows a full wellbore capacity pressure test to be conducted before initiating the next frac stage and also allows the next pressure pulse pattern to be sent through the wellbore from surface.

[0179] Once the wellbore has been fully completed, the ball 850 may be dissolved, thereby allowing fluid to again flow through the system 800. As discussed above, as the shoulder 744 only slightly projects into the axial flow passage 715 (e.g. 1/8 inch), the tubing string 801 maintains substantially its full inner diameter.

[0180] The sleeve assemblies 100, 700 in this embodiment are only automatically actuatable from the closed configuration to open configuration, and from the inactive configuration to the active configuration, respectively. However, the sleeve assemblies 100, 700 are manually re-closable and may shifted back to their original configurations by coiled tubing/service rig operations using a mechanical shifting tool. In other embodiments, the sleeve assemblies 100 and/or 700 may be designed to be automatically actuatable back to their original configurations.

[0181 ] Figures 15A-15D show another example system 900 at various steps in a completion process. The system 900 may be installed as part of a tubing string in a horizontal wellbore (not shown).

[0182] The system 900 in this embodiment comprises a series of sleeve assemblies 700. In Figures 15A-15D, two sleeve assemblies are shown: a first sleeve assembly 700A and a second sleeve assembly 700B, with the first sleeve assembly 700A being proximate the toe of the wellbore. However, it will be understood that the system 900 may comprise additional sleeve assemblies 700 (not shown) extending in the uphole direction towards the heel of the wellbore. In this embodiment, the sleeve assemblies 700A and 700B each comprise a plurality of flow ports 712. Thus, each sleeve assembly 700 in the system 900 functions as both a “frac sleeve” and “an isolation sleeve”.

[0183] As shown in Figure 15A, the system 900 is initially run into the wellbore with the sleeve assemblies 700A and 700B in their inactive configurations. In the inactive configuration, the flow ports 712 are blocked by the inner sleeve 704 and the engagement mechanism 730 is in its inactive state. The wellbore is pressure isolated at this stage, for example, by cement float equipment at the toe of the well (not shown). The wellbore may therefore be pressure tested to 100% of its pressure capacity to confirm the integrity of the wellbore.

[0184] A first control signal may then be sent through the wellbore from surface. In this embodiment, the first control signal is a first pressure pulse pattern such as the pattern 150 shown in Figure 4. In some embodiments, the sleeve assemblies 700A and 700B are programmed with the same pre-determined pressure pulse pattern, but different count thresholds. In other embodiments, different pressure pulse patterns may be used for different sections of the well or an individual pressure pulse pattern may be used for each individual sleeve assembly.

[0185] The first sleeve assembly 700A is actuated in response to the first pressure pulse pattern to its active configuration. Figure 15B shows the first sleeve assembly 700A in the active configuration, with the flow ports 712 opened and the engagement mechanism 730 activated such that the shoulder 744 is available to engage a ball or another fluid blocking element. The first frac stage is then pumped through the flow ports 712 of the first sleeve assembly 700A (indicated by the dashed arrows in Figure 15B). The frac treatment may then be displaced by pumping a displacement fluid through the wellbore.

[0186] Referring now to Figure 15C, a first dissolvable ball 950A may be pumped from surface in the displacement fluid to engage the shoulder 744 of the first sleeve assembly 700A. The well uphole of the first sleeve assembly 700A is now pressure isolated, allowing another pressure test to be completed and a second pressure pulse pattern to be sent through the wellbore from surface.

[0187] The second sleeve assembly 700B is actuated in response to the second pressure pulse pattern to its active configuration, with the flow ports 712 opened and the engagement mechanism 730 activated. The second frac stage is then pumped through the flow ports 712 of the second sleeve assembly 700B (indicated by the dashed arrows in Figure 15C). The frac treatment may then be displaced by pumping a displacement fluid through the wellbore.

[0188] Referring now to Figure 15D, a second dissolvable ball 950B may then be pumped from surface in the displacement fluid and engages the shoulder 744 of the second sleeve assembly 700B. The well uphole of the second sleeve assembly 700B is now pressure isolated, allowing another pressure test to be completed and a third pressure pulse pattern to be sent through the wellbore from surface.

[0189] This process may then be repeated in the same manner for additional sleeve assemblies 700, extending uphole in the wellbore towards the heel.

[0190] Figure 16 is a flowchart of a method 1000 for a sleeve assembly system. The system may include a first sleeve assembly and a second sleeve assembly. The first and second sleeve assemblies may be installed on a tubing string, with the second sleeve assembly positioned uphole of the first sleeve assembly.

[0191] The first sleeve assembly comprises a first tubular housing having a plurality of flow ports and a first inner sleeve within the housing axially movable between a closed position in which the flow ports are blocked and an open position in which the flow ports are closed. In some embodiments, the first sleeve assembly is the sleeve assembly 100 of Figures 1-2B. The second sleeve assembly comprises a second tubular housing, a second actuatable inner sleeve, and an engagement mechanism for engaging a fluid blocking element (e.g. a ball). The second inner sleeve is axially movable from a first position to a second position such that movement of the second inner sleeve activates the engagement mechanism to form an annular shoulder. In some embodiments, the second sleeve assembly is the sleeve assembly 300 of Figures 7A-7C or the sleeve assembly 700 of Figures 11A- 13.

[0192] At block 1002, the first inner sleeve 104 is actuated from the closed position to the open position to expose the plurality of flow ports 112. The first inner sleeve 104 may be configured to move axially in the uphole direction or in the downhole direction to expose the plurality of flow ports 112, depending on the position of the flow ports in the housing.

[0193] The first inner sleeve may be actuated in response to a control signal sent through the wellbore, such as a pressure pulse pattern as discussed above. In some embodiments, the first inner sleeve is actuated when the number of pressure pulse patterns reaches a pre-determined threshold. The first inner sleeve may be actuated by discharging at least one energetic material that generates a force to move the first inner sleeve axially within the housing. In other embodiments, the first inner sleeve may be actuated by any other suitable mechanism.

[0194] At block 1004, the second inner sleeve is actuated from the first position to the second position to activate the engagement mechanism and form the annular shoulder. The second inner sleeve may be configured to move axially in the uphole direction or in the downhole direction depending on the type and position of the engagement mechanism.

[0195] The second inner sleeve may be actuated in response to a control signal sent through the wellbore, such as a pressure pulse pattern as discussed above. In some embodiments, the second inner sleeve is actuated when the number of pressure pulse patterns reaches a pre-determined threshold. In some embodiments, the second inner sleeve is actuated in response to the same control signal/threshold as the first inner sleeve. In other embodiments, the second inner sleeve is actuated in response to a different control signal or the same control signal but a different threshold as the first inner sleeve. The second inner sleeve may be actuated by discharging at least one energetic material. In other embodiments, the second inner sleeve may be actuated by any other suitable mechanism.

[0196] In some embodiments, the first and second inner sleeves may be actuated simultaneously. In other embodiments, the second inner sleeve may be actuated after the first inner sleeve. The second inner sleeve may be actuated shortly after the first inner sleeve or after a selected time delay. In embodiments in which there is a time delay, the method 1000 may further comprise fracturing or stimulating a first formation zone by flowing a treatment fluid through the tubing string and out of the flow ports of the first sleeve assembly.

[0197] At block 1006, a fluid blocking element is introduced into the system, via the tubing string, to engage the engagement mechanism. The fluid blocking element may be a ball or any other suitable device. The fluid blocking element may be introduced into the tubing string by pumping the element downhole in a suitable fluid such as a displacement fluid. Various options are available during the element pump-down. For example, the element may be displaced purely with clean displacement fluid or the element may be chased with limited displacement fluid, then acid for frac initiation, frac pad for frac placement, and the frac treatment itself.

[0198] The fluid blocking element may engage the annular shoulder of the engagement mechanism. Engagements of the fluid blocking element with the annular shoulder may block fluid flow through the second sleeve assembly and thereby pressure isolate the wellbore at the location of the second sleeve assembly. In some embodiments, the method 1000 may further comprise performing a pressure test of the wellbore after the fluid blocking element has engaged the annular shoulder and blocked fluid flow. The pressure test may be a full wellbore capacity pressure test.

[0199] In some embodiments, the method 1000 further comprises dissolving the fluid blocking element (e.g. ball) or flowing the element back through the tubing string to surface.

[0200] The method 1000 may then be repeated for additional systems installed along the tubing string of the wellbore.

Wireline Bottom Hole Assembly (BHA) Apparatus

[0201 ] The systems 400, 500, and 800 discussed above all combine a “frac” sleeve assembly 100 with an “isolation” sleeve assembly 300 or 700. In alternative embodiments, the sleeve assembly 100 may be used in combination with a wireline bottom hole assembly (BHA) apparatus to provide the wellbore isolation function in place of the sleeve assembly 300 or 700.

[0202] Figure 17 is a side view of an example wireline BHA apparatus 1100, according to some embodiments. The apparatus 1100 is connectable to a wireline 1104. Only a portion of the wireline 1104 is shown in Figure 17; however, it will be understood that the wireline 1104 extends to surface and may be connected at surface to a tree saver (not shown). The apparatus 1100 is positionable in a tubing string of a wellbore (not shown) and movable therethrough via the wireline 1104.

[0203] The apparatus 1100 in this embodiment comprises a tubular housing 1102, at least one actuatable isolation element 1120, a pair of actuatable back-up rings 1122, and a plurality of actuatable slips 1124.

[0204] The housing 1102 has an uphole end 1101 and a downhole end 1103 and comprises an uphole portion 1106 and a downhole portion 1108. The housing 1102 also has an inner surface (not shown) and an outer surface 1110.

[0205] The isolation element 1120 in this embodiment is ring-shaped and is positioned around the outer surface 1110 of the downhole portion 1108 of the housing 1102. The isolation element 1120 is actuatable between an inactive state (shown in Figure 17) and an active state (not shown). The isolation element 1120 may be expandable such that the isolation element 1120 expands radially outwards when activated into the active state. As one example, the isolation element 1120 may comprise an expandable packer. In other embodiments, the isolation element 1120 may be any other suitable isolation element or combination of elements. When the isolation element 1120 is in the active state, the isolation element 1120 forms a seal with the inner surface of the tubing string to pressure isolate the wellbore.

[0206] The backup rings 1122 are positioned around the outer surface 1110 of the downhole portion 1109 of the housing 1102, with one backup ring 1122 positioned on either side of the isolation element 1120. Each backup ring 1122 may be actuatable between an inactive state (Figure 17) and an active state (not shown). The backup rings 1122 may be expandable such that the backup rings 1122 expands radially outwards when activated into the active state. When the backup rings 1122 are in the active state, the backup rings 1122 may function to protect the isolation element 1120 and prevent the isolation element 1120 from inadvertently expanding when the apparatus 1100 is being moved through the tubing string. In other embodiments, the backup rings 1122 may be optional or omitted.

[0207] The slips 1124 are spaced circumferentially around the outer surface 1110 of the downhole portion 1108, proximate the downhole end 1103 of the housing 1102. The slips 1124 may be actuatable between an inactive state (Figure 17) and an active state (not shown). In this embodiment, the slips 1124 are expandable such that the slips 1124 expand radially outward when activated into the active state. When the slips 1124 are in their active state, the slips 1124 may help to set the apparatus 1100 at a desired position in the tubing string.

[0208] The wireline BHA apparatus 1100 may further comprise a control system. An example control system 1150 will be discussed with reference to Figure 18. The control system 1150 in this embodiment comprises a controller 1152, an instrumentation head 1154, an isolation element actuator 1156, a backup ring actuator 1158, and a slips actuator 1160.

[0209] The controller 1152 comprises at least one processor 1162, a memory 1164, and a transceiver 1166. The memory 1164 is operatively connected to the processor 1162. The memory 1164 stores processor-executable instructions therein that, when executed, cause the processor to implement one or more functions described herein. The transceiver 1166 is operatively connected to the processor 1162. In some embodiments, the transceiver 1166 comprises both a transmitter and a receiver sharing common circuitry. In other embodiments, the transceiver 1166 comprises a separate transmitter and receiver. The transceiver 1166 may be configured to send and receive communications over a communication network. The communication network may be a wired or wireless network. In some embodiments, the controller 1152 is operatively connected to a control system at surface (not shown) via the transceiver 1166 over the communication network. In other embodiments, the transceiver 1116 may be omitted.

[0210] The controller 1152 may further comprise a power supply (not shown). In some embodiments, a single power supply is provided for the controller 1152, the instrumentation head 1154 and the actuators 1156, 1158, and 1160. In other embodiments, one or more of the controller 1152, the instrumentation head 1154, and the actuators 1156, 1158, and 1160 may have an independent power supply. Each power supply may comprise one or more batteries or any other suitable power supply.

[0211 ] In this embodiment, the controller 1152 is housed within the downhole portion 1108 of the housing 1102. In other embodiments, the controller 1152 may be at any other suitable location within the housing 1102.

[0212] The instrumentation head 1154 may comprise a location sensor 1168 configurated to sense the location of a sleeve assembly (e.g. the sleeve assembly 100) within the tubing string. The location sensor 1168 may comprise an electric logging tool such as an CCL (casing collar locator) or any other suitable location sensor. The instrumentation head 1154 may further comprise one or more other sensors 1170. For example, the other sensors 1170 may comprise at least one pressure sensor (e.g. P1 and P2 pressure sensors), a tension/compression sensor, a temperature sensor, and/or a shock sensor. In other embodiments, the instrumentation head 1154 may comprise any other suitable type and number of sensors.

[0213] In this embodiment, the instrumentation head 1154 is operatively connected to the controller 1152. The output of the location sensor 1168 and the other sensors 1170 may be stored in the memory 1164 and/or transmitted to a control system at surface (not shown) via the transceiver 1166. In other embodiments, the instrumentation head 1154 may comprise its own controller with at least one processor, memory, and (optionally) a transceiver.

[0214] In this embodiment, the instrumentation head 1154 is housed within the uphole portion 1106 of the housing 1102. In other embodiments, the instrumentation head 1154 may be at any other suitable location within the housing 1102.

[0215] The isolation element actuator 1156, the backup rings actuator 1158, and the slips actuator 1160 are configured to actuate the isolation element 1120, the backup rings 1122, and the slips 1124, respectively, from their inactive states to their active states. For example, one or more of the actuators 1156, 1158, and 1160 may be a spring-loaded mechanism that causes the isolation element 1120, the backup rings 1122, or the slips 1124 to expand, respectively. In other embodiments, the actuators 1156, 1158, and 1160 may be any other suitable actuators. The actuators 1156, 1158, and 1160 may be housed within the downhole portion 1108 of the housing 1102, proximate the isolation element 1120, the backup rings 1122, and the slips 1124, respectively.

[0216] The actuators 1156, 1158, and 1160 are operatively connected to the processor 1162 of the controller 1152 and each actuator 1156, 1158, and 1160 is independently operatable via the processor 1162. In some embodiments, the processor 1162 is configured to receive control signals from the control system at surface (e.g. via the transceiver 1166) and activate each actuator 1156, 1158, and 1160 in response to the appropriate control signal. In some embodiments, one or more controls signals are transmitted from surface in response to the location sensor 1168 sensing a sleeve assembly (e.g. the sleeve assembly 100) as the wireline BHA apparatus 1100 moves through the wellbore. In other embodiments, the processor 1162 may automatically activate each actuator 1156, 1158, and 1160 in response to the output of the location sensor 1168 based on processor-executable instructions stored in the memory 1164. [0217] Figure 19 is a partial, side cross-sectional view of an example system 1200 including the wireline BHA apparatus 1100 of Figure 17 and the sleeve assembly 100 of Figures 1 -2B. The sleeve assembly 100 is incorporated into a tubing string 1202. The tubing string 1202 may be received within a horizontal wellbore (not shown). Although only one sleeve assembly 100 is shown in Figure 19, it will be understood that a series of sleeve assemblies 100 may be installed along the tubing string 1104. The apparatus 1100 is movable with respect to the tubing string 1202 via the wireline 1104 and is movable through the axial flow passage 115 of the sleeve assembly 100.

[0218] In operation, the wireline BHA apparatus 1100 may be lowered into the tubing string 1202 and pumped downhole via a frac pump at surface (not shown). Prior to initiating the frac pump, the controller 1152 of the apparatus 1100 may activate the backup rings 1122 to their active (expanded) state, via the backup rings actuator 1158. Activating the backup rings 1122 may help improve pump-down efficiency.

[0219] As the apparatus 1100 travels through the well, the instrumentation head 1154 may monitor real-time conditions such as pressure, temperature, etc. The location sensor 1168 may then locate a particular sleeve assembly 100 (in its closed configuration) to be actuated. The controller 1152 may then receive control signals from surface to position the apparatus 1100 downhole of that sleeve assembly 100. The controller 1152 may then receive control signals to independently actuate the isolation element 1120 to its active (expanded) state, via the isolation element actuator 1156, thereby pressure isolating the wellbore above the isolation element 1120 from the remainder of the wellbore therebelow. The slips 1124 may also be actuated via the slips actuator 1160 to set the apparatus 1100 at that location.

[0220] A pressure pulse pattern may then be sent downhole to actuate the sleeve assembly 100 to an open configuration, as described above. In this example, only one sleeve assembly 100 is actuated to the open configuration. In other embodiments, a cluster of sleeve assemblies 100 may be actuated concurrently or sequentially. Frac treatment fluid may then be pumped out of the sleeve assembly 100 via the flow ports 112. During the frac stage, real-time data can continue to be monitored via the instrumentation head 1154, including tension and pressure above and below the isolation element 1120. Once that frac stage is completed, the controller 1152 may actuate the isolation element 1120 and the slips 1124 back to their original inactive (unexpanded) states and pressure is equalized above and below the isolation element 1120. The backup rings 1122 may also be released at this stage.

[0221 ] The wireline BHA apparatus 1100 may then be pulled uphole through the sleeve assembly 100. The apparatus 1100 may be pulled uphole until the location sensor 1168 locates the next sleeve assembly 100.

[0222] Therefore, embodiments of the wireline BHA apparatus 1100 and the system 1200 may have a number of advantages including: real-time depth confirmation, real-time confirmation of sleeve assembly 100 opening and isolation element 1120 location, and real-time monitoring of the pressure differential across the isolation element 1120. The system 1200 may also allow for the actuation of multiple frac sleeves per stage and unlimited stages and sleeves per stage. In some embodiments, the apparatus 1100 may only have one pump-down trip to the downhole end (total depth) of the well and one tension trip out.

[0223] Moreover, like the systems 400, 500, 800 and 900 discussed above, the system 1200 does not introduce any ID restrictions into the tubing string 1202. As discussed above, the sleeve assembly 100 is actuatable via the integrated actuator 126 and has no ball/dart seats to reduce the ID of the axial flow passage 115. The wireline BHA apparatus 1100 is fully removed from the tubing string 1202 after the well is completed and thus does not leave any ID restrictions following its removal.

[0224] 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 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.