MULTI-ZONE ACTUATION SYSTEM USING WELLBORE PROJECTILES AND FLAPPER VALVES

BACKGROUND

The present disclosure relates generally to wellbore operations and, more particularly, to a multi-zone actuation system that detects wellbore projectiles in carrying out multiple-interval stimulation of a wellbore.

In the oil and gas industry, subterranean formations penetrated by a wellbore are often fractured or otherwise stimulated in order to enhance hydrocarbon production. Fracturing and stimulation operations are typically carried out by strategically isolating various zones of interest (or intervals within a zone of interest) in the wellbore using packers and the like, and then subjecting the isolated zones to a variety of treatment fluids at increased pressures. In a typical fracturing operation for a cased wellbore, the casing cemented within the wellbore is first perforated to allow conduits for hydrocarbons within the surrounding subterranean formation to flow into the wellbore. Prior to producing the hydrocarbons, however, treatment fluids are pumped into the wellbore and the surrounding formation via the perforations, which has the effect of opening and/or enlarging drainage channels in the formation, and thereby enhancing the producing capabilities of the well.

Today, it is possible to stimulate multiple zones during a single stimulation operation by using onsite stimulation fluid pumping equipment. In such applications, several packers are introduced into the wellbore and each packer is strategically located at predetermined intervals configured to isolate adjacent zones of interest. Each zone may include a sliding sleeve that is moved to permit zonal stimulation by diverting flow through one or more tubing ports occluded by the sliding sleeve. Once the packers are appropriately deployed, the sliding sleeves may be selectively shifted open using, for instance, a ball and baffle system. A ball and baffle system involves sequentially dropping wellbore projectiles from a surface location into the wellbore. The wellbore projectiles, commonly referred to as “frac balls,” are of predetermined sizes configured to seal against correspondingly sized baffles or seats disposed within the wellbore at corresponding zones of interest. The smaller frac balls are introduced into the wellbore prior to the larger frac balls, where the smallest frac ball is designed to land on the baffle furthest from the wellhead, and the largest frac ball is designed to land on the baffle closest to the wellhead. Accordingly, the frac balls isolate the target sliding sleeves, from the bottom-most sleeve moving uphole. Applying hydraulic pressure from the surface serves to shift the target sliding sleeve to its open position.

Thus, a ball and baffle system acts as an actuation mechanism for shifting the sliding sleeves to their open position downhole. When the fracturing operation is complete, the balls can be either hydraulically returned to the surface or drilled up along with the baffles in order to return the casing string to a full bore inner diameter. As can be appreciated, at least one shortcoming of the ball and baffle system is that there is a limit to the maximum number of zones that may be fractured owing to the fact that the baffles are of graduated sizes.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, without departing from the scope of this disclosure.

FIG. 1 illustrates an exemplary well system that can embody or otherwise employ one or more principles of the present disclosure, according to one or more embodiments.

FIGS. 2A and 2B illustrate an exemplary wellbore projectile in the form of a wellbore dart, according to one or more embodiments of the present disclosure.

FIGS. 3A and 3B illustrate isometric views of another exemplary wellbore projectile in the form of a frac ball, according to one or more embodiments of the present disclosure.

FIGS. 4A-4C illustrate progressive cross-sectional side views of an exemplary sliding sleeve assembly, according to one or more embodiments.

FIG. 5 illustrates an exemplary flapper valve that may be used in the assembly of FIGS. 4A-4C, according to one or more embodiments.

FIGS. 6A and 6B illustrate enlarged cross-sectional side views of the assembly of FIGS. 4A-4C, according to one or more embodiments.

DETAILED DESCRIPTION

The embodiments described herein disclose sliding sleeve assemblies that are able to detect wellbore projectiles and actuate a sliding sleeve upon detecting a predetermined number of wellbore projectiles. Once the predetermined number of wellbore projectiles has been detected, an actuation sleeve may be actuated to release a flapper valve, which seats against and sealingly engages the sliding sleeve. Upon applying fluid pressure uphole from the flapper valve, the sliding sleeve may be moved to an open position where ports become exposed and facilitate fluid communication into a surrounding subterranean environment for wellbore stimulation operations. The presently disclosed embodiments, therefore, provide interventionless wellbore stimulation methods and systems.

Referring to FIG. 1, illustrated is an exemplary well system 100 which can embody or otherwise employ one or more principles of the present disclosure, according to one or more embodiments. As illustrated, the well system 100 may include an oil and gas rig 102 arranged at the Earth's surface 104 and a wellbore 106 extending therefrom and penetrating a subterranean earth formation 108. Even though FIG. 1 depicts a land-based oil and gas rig 102, it will be appreciated that the embodiments of the present disclosure are equally well suited for use in other types of rigs, such as offshore platforms, or rigs used in any other geographical location. In other embodiments, the rig 102 may be replaced with a wellhead installation, without departing from the scope of the disclosure.

The rig 102 may include a derrick 110 and a rig floor 112. The derrick 110 may support or otherwise help manipulate the axial position of a work string 114 extended within the wellbore 106 from the rig floor 112. As used herein, the term “work string” refers to one or more types of connected lengths of tubulars or pipe such as drill pipe, drill string, casing, landing string, production tubing, coiled tubing combinations thereof, or the like. The work string 114 may be utilized in drilling, stimulating, completing, or otherwise servicing the wellbore 106, or various combinations thereof.

As illustrated, the wellbore 106 may extend vertically away from the surface 104 over a vertical wellbore portion. In other embodiments, the wellbore 106 may otherwise deviate at any angle from the surface 104 over a deviated or horizontal wellbore portion. In other applications, portions or substantially all of the wellbore 106 may be vertical, deviated, horizontal, and/or curved. Moreover, use of directional terms such as above, below, upper, lower, upward, downward, uphole, downhole, and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the heel or surface of the well and the downhole direction being toward the toe or bottom of the well.

In an embodiment, the wellbore 106 may be at least partially cased with a casing string 116 or may otherwise remain at least partially uncased. The casing string 116 may be secured within the wellbore 106 using, for example, cement 118. In other embodiments, the casing string 116 may be only partially cemented within the wellbore 106 or, alternatively, the casing string 116 may be omitted from the well system 100, without departing from the scope of the disclosure. The work string 114 may be coupled to a completion assembly 120 that extends into a branch or lateral portion 122 of the wellbore 106. As illustrated, the lateral portion 122 may be an uncased or “open hole” section of the wellbore 106.

It is noted that although FIG. 1 depicts the completion assembly 120 as being arranged within the lateral portion 122 of the wellbore 106, the principles of the apparatus, systems, and methods disclosed herein may be similarly applicable to or otherwise suitable for use in wholly vertical wellbore configurations. Consequently, the horizontal or vertical nature of the wellbore 106 should not be construed as limiting the present disclosure to any particular wellbore 106 configuration.

The completion assembly 120 may be arranged or otherwise deployed within the lateral portion 122 of the wellbore 106 using one or more packers 124 or other wellbore isolation devices known to those skilled in the art. The packers 124 may be configured to seal off an annulus 126 defined between the completion assembly 120 and the inner wall of the wellbore 106. As a result, the subterranean formation 108 may be effectively divided into multiple intervals or “pay zones” 128 (shown as intervals 128a, 128b, and 128c) which may be stimulated and/or produced independently via isolated portions of the annulus 126 defined between adjacent pairs of packers 124. While only three intervals 128a-c are shown in FIG. 1, those skilled in the art will readily recognize that any number of intervals 128a-c may be defined or otherwise used in the well system 100, including a single interval, without departing from the scope of the disclosure.

The completion assembly 120 may include one or more sliding sleeve assemblies 130 (shown as sliding sleeve assemblies 130a, 130b, and 130c) arranged in, coupled to, or otherwise forming integral parts of the work string 114. As illustrated, at least one sliding sleeve assembly 130a-c may be arranged in each interval 128a-c, but those skilled in the art will readily appreciate that more than one sliding sleeve assembly 130a-c may be arranged within each interval 128a-c, without departing from the scope of the disclosure. It should be noted that, while the sliding sleeve assemblies 130a-c are shown in FIG. 1 as being deployed in an open hole section of the wellbore 106, the principles of the present disclosure are equally applicable to completed or cased sections of the wellbore 106. In such embodiments, a cased wellbore 106 may be perforated at predetermined locations in each interval 128a-c using any known methods (e.g., explosives, hydrajetting, etc.) in the art. Such perforations serve to facilitate fluid conductivity between the interior of the work string 114 and the surrounding intervals 128a-c of the formation 108.

Each sliding sleeve assembly 130a-c may be actuated in order to provide fluid communication between the interior of the work string 114 and the annulus 126 adjacent each corresponding interval 128a-c and, therefore, provide fluid communication to the corresponding intervals 128a-c. As depicted, each sliding sleeve assembly 130a-c may include a sliding sleeve 132 that is axially movable within the work string 114 to expose one or more ports 134 defined in the work string 114. Once exposed, the ports 134 may facilitate fluid communication between the annulus 126 and the interior of the work string 114 such that stimulation and/or production operations may be undertaken in each corresponding interval 128a-c of the formation 108.

According to the present disclosure, in order to move the sliding sleeve 132 of a given sliding sleeve assembly 130a-c to its open position, and thereby expose the corresponding ports 134, one or more wellbore projectiles 136 (shown in FIG. 1 as wellbore projectiles 136a and 136b) may be introduced into the work string 114 and conveyed downhole toward the sliding sleeve assemblies 130a-c. The wellbore projectiles 136 may include, but are not limited to balls (also known as “frac” balls), darts, wipers, plugs, or any combination thereof. The wellbore projectiles 136 may be conveyed through the work string 114 and to the completion assembly 120 by any known technique. For example, the wellbore projectiles 136 can be dropped through the work string 114 from the surface 104, pumped by flowing fluid through the interior of the work string 114, self-propelled, conveyed by wireline, slickline, coiled tubing, etc.

Each wellbore projectile 136 may be detectable by one or more sensors 138 (shown as sensors 138a, 138b, and 138c) associated with each sliding sleeve assembly 130a-c. In some embodiments, for instance, the wellbore projectiles 136 may exhibit known magnetic properties, and/or produce a known magnetic field, pattern, or combination of magnetic fields, which is/are detectable by the sensors 138a-c. In such cases, each sensor 138a-c may be capable of detecting the presence of the magnetic field(s) produced by the wellbore projectiles 136 and/or one or more other magnetic properties of the wellbore projectiles 136.

Suitable magnetic sensors 138a-c can include, but are not limited to, magneto-resistive sensors, Hall-effect sensors, conductive coils, combinations thereof, and the like. In some embodiments, permanent magnets can be combined with one or more of the sensors 138a-c in order to create a magnetic field that is disturbed by the wellbore projectiles 136, and a detected change in the magnetic field can be an indication of the presence of the wellbore projectiles 136. p Moreover, in some embodiments, a barrier (not shown) may be positioned between each sensor 138a-c and the wellbore projectiles 136. The barrier may comprise a relatively low magnetic permeability material and may be configured to allow magnetic signals to pass therethrough and isolate pressure between the sensors 138a-c and the wellbore projectiles 136. Additional information on such a barrier as used in magnetic detection can be found in U.S. Patent Pub. No. 2013/0264051. In other embodiments, a magnetic shield (not shown) may be either positioned on the wellbore projectiles 136 or near the sensors 138a-c to “short circuit” magnetic fields emitted by the wellbore projectiles 136 and thereby reduce the amount of remnant magnetic fields that may be detectable by the sensors 138a-c. In such embodiments, the magnetic field may be pulled toward materials that have a high magnetic permeability, which effectively shields the sensors 138a-c from the remnant magnetic fields.

In other embodiments, one or more of the sensors 138a-c may be capable of detecting radio frequencies emitted by the wellbore projectiles 136. In such embodiments, the sensors 138a-c may be radio frequency (RF) sensors or readers capable of detecting a radio frequency identification (RFID) tag secured to or otherwise forming part of the wellbore projectiles 136. The RF sensors 138a-c may be configured to sense the RFID tags as the wellbore projectiles 136 traverse the work string 114 and encounter the RF sensors 138a-c. In at least one embodiment, the RF sensors 138a-c may be micro-electromechanical systems (MEMS) or devices capable of sensing radio frequencies. In such cases, the MEMS sensors may include or otherwise encompass an RF coil and thereby be used as the sensors 138a-c. The RF sensor 138a-c may alternatively be a near-field communication (NFC) sensor capable of establishing radio communication with a corresponding dummy tag arranged on the wellbore projectiles 136. When the dummy tags come into proximity of the RF sensors 138a-c, the RF sensors 138a-c may register the presence of the wellbore projectiles 136.

In yet other embodiments, the sensors 138a-c may be a type of mechanical switch or the like that may be mechanically manipulated through physical contact with the wellbore projectiles 136 as they traverse the work string 114. In some cases, for instance, the mechanical sensors 138a-c may be ratcheting or mechanical counting devices or switches disposed near each sleeve 132. Upon physically contacting and otherwise interacting with the wellbore projectiles 136, the mechanical sensors 138a-c may be configured to generate and send corresponding signals indicative of the same to an adjacent actuation device (not shown in FIG. 1), as will be described below. In some embodiments, the mechanical sensors 138a-c may be spring loaded or otherwise configured such that after the wellbore projectile 136 has passed (or following a certain time period thereafter) the switch may autonomously reset itself. As will be appreciated, such a resettable embodiment may allow the mechanical sensors 138a-c to physically interact with multiple wellbore projectiles 136.

Each sensor 138a-c may be connected to associated electronic circuitry (not shown in FIG. 1) configured to determine whether the associated sensor 138a-c has positively detected a wellbore projectile 136. For instance, in the case where the sensors 138a-c are magnetic sensors, the sensors 138a-c may detect a particular or predetermined magnetic field, or pattern or combination of magnetic fields, or other magnetic properties of the wellbore projectiles 136, and the associated electronic circuitry may have the predetermined magnetic field(s) or other magnetic properties programmed into non-volatile memory for comparison. Similarly, in the case where the sensors 138a-c are RF sensors, the sensors 138a-c may detect a particular RF signal from the wellbore projectiles 136, and the associated electronic circuitry may either count the RF signals or compare the RF signals with RF signals programmed into its non-volatile memory.

Once a wellbore projectile 136 is positively detected by the sensors 138a-c, the associated electronic circuitry may acknowledge and count the detection instance and, if appropriate, trigger actuation of the corresponding sliding sleeve assembly 130a-c using one or more associated actuation devices (not shown in FIG. 1). In some embodiments, for example, actuation of the associated sliding sleeve assembly 130a-c may not be triggered until a predetermined number or combination of wellbore projectiles 136 has been detected by the given sensors 138a-c. Accordingly, each sensor 138a-c records and counts the passing of each wellbore projectile 136 and, once a predetermined number of wellbore projectiles 136 is detected by a given sensor 138a-c, the corresponding sliding sleeve assembly 130a-c may then be actuated in response thereto.

Referring now to FIGS. 2A and 2B, with continued reference to FIG. 1, illustrated are isometric and cross-sectional side views, respectively, of an exemplary wellbore projectile 200, according to one or more embodiments of the present disclosure. The wellbore projectile 200 may be similar in some respects to the wellbore projectiles 136 of FIG. 1, and therefore may be configured to be introduced downhole to interact with the sensors 138a-c of the sliding sleeve assemblies 130a-c. As illustrated, the wellbore projectile 200 is in the general form of a wellbore dart and may include a generally cylindrical body 202 with a plurality of collet fingers 204 either forming part of the body 202 or extending longitudinally therefrom. In some embodiments, the collet fingers 204 may be omitted and the body 202 may instead extend longitudinally. In at least one embodiment, the collet fingers 204 may be flexible, axial extensions of the body 202 that are separated by elongate channels 206. In some embodiments, a dart profile 208 may be defined on the outer radial surface of the collet fingers 204 and may allow the wellbore projectile 200 to mate with a pre-selected or desired sliding sleeve (not shown).

The body 202 may be made of a variety of materials including, but not limited to, iron and iron alloys, steel and steel alloys, aluminum and aluminum alloys, copper and copper alloys, plastics, composite materials, and any combination thereof. In other embodiments, as described in greater detail below, all or a portion of the body 202 may be made of a degradable and/or dissolvable material, without departing from the scope of the disclosure.

In some embodiments, the wellbore projectile 200 may further include a dynamic seal 210 arranged about the exterior or outer surface of the body 202 at or near its downhole end 212. As used herein, the term “dynamic seal” is used to indicate a seal that provides pressure and/or fluid isolation between members that have relative displacement therebetween, for example, a seal that seals against a displacing surface, or a seal carried on one member and sealing against the other member. In some embodiments, the dynamic seal 210 may be arranged within a groove 214 defined on the outer surface of the body 202. The dynamic seal 210 may be made of a material selected from the following: elastomeric materials, non-elastomeric materials, metals, composites, rubbers, ceramics, derivatives thereof, and any combination thereof. In some embodiments, the dynamic seal 210 may be an 0-ring or the like, as illustrated. In other embodiments, however, the dynamic seal 210 may be a set of v-rings or CHEVRON® packing rings, or other appropriate seal configurations (e.g., seals that are round, v-shaped, u-shaped, square, oval, t-shaped, etc.), as generally known to those skilled in the art, or any combination thereof.

The wellbore projectile 200 may further include or otherwise encompass one or more sensor components 216. As used herein, the term “sensor component” refers to any element, mechanism, device, or substance that is able to interact with the sensors 138a-c of the sliding sleeve assemblies 130a-c of FIG. 1 and thereby confirm that the wellbore projectile 200 has come into proximity of the given sensor 138a-c. For example, in some embodiments, the sensor components 216 may be magnets configured to interact with magnetic sensors 138a-c, as described above. In other embodiments, however, the sensor components 216 may be RFID tags (active or passive) configured to be read by a corresponding RFID reader associated with or otherwise encompassing the sensors 138a-c.

In some embodiments, the sensor components 216 may be arranged about the circumference of the wellbore projectile 200, such as being positioned on one or more of the collet fingers 204. As best seen in FIG. 2B, the sensor components 216 may seated or otherwise secured within corresponding recesses 218 (FIG. 2B) defined in the collet fingers 204. In other embodiments, however, the sensor components 216 may be secured to the outer radial surface of the collet fingers 204. In yet other embodiments, the sensor components 216 may be positioned on the body 202 at or near the downhole end 212 or a combination of the body 202 and the collet fingers 204. In even further embodiments, the wellbore projectile 200 itself may be or otherwise encompass the sensor component 216. In other words, in some embodiments, the wellbore projectile 200 itself may be made of a material (i.e., magnets) or otherwise comprise an element, mechanism, device (i.e., RFID tag), or substance that is able to interact with the sensors 138a-c of the sliding sleeve assemblies 130a-c of FIG. 1 and thereby confirm that the wellbore projectile 200 has come into proximity of the given sensor 138a-c.

FIGS. 3A and 3B illustrate isometric views of another exemplary wellbore projectile 300, according to one or more embodiments of the present disclosure. The wellbore projectile 300 may be similar in some respects to the wellbore projectiles 136 of FIG. 1, and therefore may be configured to be introduced downhole to interact with the sensors 138a-c of the sliding sleeve assemblies 130a-c. As illustrated, the wellbore projectile 300 is in the general shape of a sphere 302, and may be referred to as a “frac” ball. In some embodiments, the wellbore projectile 300 may define or otherwise provide one or more recesses 304 in the outer surface of the sphere 302. Similar to the recesses 218 of FIG. 2B, each recess 304 may be designed to receive and otherwise secure therein a corresponding sensor component (not shown), such as one of the sensor components 216 of FIGS. 2A-2B.

Accordingly, the recesses 304 may receive and seat sensor components 216 in the form of magnets and/or RF tags. In other embodiments, however, the sensor components 216 of the wellbore projectile 300 may be positioned entirely within the center of the sphere 302 or secured to its outer surface, without departing from the scope of the disclosure. In yet other embodiments, the wellbore projectile 300 itself may be the sensor component 216.

In other words, in some embodiments, the wellbore projectile 300 may be made of a material (i.e., magnets) or otherwise comprise an element, mechanism, device (i.e., RFID tag), or substance that is able to interact with the sensors 138a-c of the sliding sleeve assemblies 130a-c of FIG. 1 and thereby confirm that the wellbore projectile 300 has come into proximity of the given sensor 138a-c.

Referring now to FIGS. 4A-4C, illustrated are progressive cross-sectional side views of an exemplary sliding sleeve assembly 400, according to one or more embodiments. The sliding sleeve assembly 400 (hereafter “the assembly 400”) may be similar in some respects to any of the sliding sleeve assemblies 130a-c of FIG. 1. As illustrated, the sliding sleeve assembly 400 may include an elongate body 402 that defines an inner flow passageway 404. The body 402 may have a first end 406a coupled to an upper sub 408a and a second end 406b coupled to a lower sub 408b. The assembly 400 may form part of a downhole completion, such as the completion 120 of FIG. 1. Accordingly, the upper and lower subs 408a,b may be used to couple the body 402 to corresponding upper and lower portions of the completion assembly 120 and/or the work string 114 (FIG. 1).

In some embodiments, the body 402 may include an electronics sub 410 and a ported sub 412. The electronics sub 410 may be threaded or otherwise mechanically fastened to the ported sub 412 so that the body 402 forms a continuous, elongate, and cylindrical structure. In other embodiments, the electronics sub 410 and the ported sub 412 may be integrally formed as a monolithic structure, without departing from the scope of the disclosure.

The electronics sub 410 may define or otherwise provide an electronics cavity 414 that houses electronic circuitry 416, one or more sensors 418, one or more batteries 420 (two shown), and an actuator 422. The batteries 420 may provide power to operate the electronic circuitry 416, the sensor(s) 418, and the actuator 422. The sensor(s) 418 may be similar to the sensors 138a-c of FIG. 1, and therefore may be capable of detecting a wellbore projectile (not shown) that traverses the assembly 400 via the inner flow passageway 404. The actuator 422 may be any mechanical, electro-mechanical, hydraulic, or pneumatic actuation device capable of manipulating the configuration or position of a sliding sleeve. In at least one embodiment, as will be described in more detail below, the actuator 422 may be an electro-hydraulic piston lock similar to that disclosed in U.S. Patent App. Ser. No. 13/219,790. The electronic circuitry 416 may be communicably coupled to the sensor(s) 418 and the actuator 422 such that when the sensor(s) 418 detect a wellbore projectile, or a predetermined number of wellbore projectiles, the electronic circuitry 416 may send an actuation signal to the actuator 422.

The ported sub 412 may include a sliding sleeve 424, one or more ports 426, an actuation sleeve 428, and a flapper valve 430. The sliding sleeve 424 may be similar to the sliding sleeves 132 of FIG. 1 and may be movably arranged within the ported sub 412. The ports 426 may be similar to the ports 134 of FIG. 1 and may be defined through the ported sub 412 to enable fluid communication between the inner flow passageway 404 and a surrounding subterranean formation (e.g., the formation 108 of FIG. 1). In FIG. 4A, the sliding sleeve 424 is depicted in a closed position, where the sliding sleeve 424 generally occludes the ports 426 and thereby prevents fluid communication therethrough. In FIG. 4C, the sliding sleeve is moved to an open position, where the sliding sleeve 424 has moved axially within the ported sub 412 to expose the ports 426 and thereby facilitate fluid communication through the ports 426.

In some embodiments, the sliding sleeve 424 may be secured in the closed position with one or more shearable devices 432 (one shown). In the illustrated embodiment, the shearable device 432 may include one or more shear pins that extend from the ported sub 412 (i.e., the body 402) and into corresponding blind bores (not labeled) defined on the outer surface of the sliding sleeve 424. In other embodiments, the shearable device 432 may be a shear ring or any other device or mechanism configured to shear or otherwise fail upon assuming a predetermined shear load applied to the sliding sleeve 424.

The sliding sleeve 424 may further include one or more dynamic seals 433 (two shown) arranged between the outer surface of the sliding sleeve 424 and the inner surface of the ported sub 412. The dynamic seals 433 may be configured to provide fluid isolation between the sliding sleeve 424 and the ported sub 412 and thereby prevent fluid migration through the ports 426 and into the ported sub 412 when the sliding sleeve 424 is in the closed position. Similar to the dynamic seal 210 of FIGS. 2A-2B, the dynamic seals 433 may be made of a variety of materials including, but not limited to, elastomers, metals, composites, rubbers, ceramics, derivatives thereof, and any combination thereof. Moreover, one or both of the dynamic seals 433 may be an 0-ring, as illustrated, but may alternatively be a set of v-rings or CHEVRON® packing rings, or other appropriate seal configurations (e.g., seals that are round, v-shaped, u-shaped, square, oval, t-shaped, etc.), as generally known to those skilled in the art, or any combination thereof.

The actuation sleeve 428 may also be movably arranged within the ported sub 412 between a run-in configuration, as shown in FIG. 4A, and an actuated configuration, as shown in FIGS. 4B and 4C. In some embodiments, a hydraulic cavity 434 may be defined between the actuation sleeve 428 and the ported sub 412 (e.g., the body 402) and sealed at each end with appropriate sealing devices 436. In such embodiments, the hydraulic cavity 434 may be fluidly coupled to the electronics cavity 414 via one or more hydraulic conduits 438. The hydraulic cavity 434 may be filled with a hydraulic fluid, such as silicone oil, and maintained at an increased pressure with respect to the electronics cavity 414, which may be at ambient pressure. As described below, the pressurized hydraulic fluid may be maintained in the hydraulic cavity 434 until a pressure member or burst disk (not shown) is penetrated by the actuator 422, thereby facilitating fluid communication between the electronics and hydraulic cavities 414, 434 and allowing the hydraulic fluid to escape into the electronics cavity 414 via the hydraulic conduit 438 in seeking pressure equilibrium.

The flapper valve 430 may be movably coupled to the sliding sleeve 424 and otherwise movable between an open configuration, as shown in FIG. 4A, and a closed configuration, as shown in FIGS. 4B (in phantom) and 4C. The flapper valve 430 may be maintained in the open configuration with the actuation sleeve 428 while the actuation sleeve 428 is in the run-in configuration. More particularly, the flapper valve 430 may be positioned between the actuation sleeve 428 and the body 402 (i.e., the ported sub 412) when in the open configuration. Once the actuation sleeve 428 is displaced or otherwise moves to the actuated configuration, however, the flapper valve 430 may be free from engagement with the actuation sleeve 428 and therefore free to move to its closed configuration. The flapper valve 430 may include a torsion spring 440 that urges the flapper valve 430 to the closed configuration. In the closed configuration, the flapper valve 430 may engage and otherwise seat against a flapper seat 442 defined on or otherwise provided by the sliding sleeve 424. Moreover, in the closed configuration, the flapper valve 430 may form a fluid tight seal as seated against the flapper seat 442, and thereby prevent fluid migration in the downhole direction (i.e., to the right in FIGS. 4A-4C).

Referring briefly to FIG. 5, with continued reference to FIGS. 4A-4C, illustrated is an exemplary flapper valve 500 movably coupled to the sliding sleeve 424. The flapper valve 500 may be the same as or similar to the flapper valve 430 and, therefore, may be configured to move between an open configuration (as shown), and a closed configuration, where the flapper valve 500 seats against the flapper seat 442 defined on or otherwise provided by the sliding sleeve 424. In the illustrated embodiment, the flapper valve 500 is depicted as having a curved profile. As will be appreciated by those skilled in the art, the curved profile of the flapper 500 may allow the flapper valve 500 to exhibit a shorter geometry. In other embodiments, however, the flapper valve 500 may alternatively exhibit a planar profile, without departing from the scope of the disclosure.

Referring again to FIGS. 4A-4C, exemplary operation of the assembly 400 is now provided. It will be appreciated that operation of the assembly 400 may be equally descriptive of operation of any of the sliding sleeve assemblies 130a-c of FIG. 1. In FIG. 4A, the assembly 400 is depicted in a “run-in” or closed configuration, where the sliding sleeve 424 generally occludes the ports 426 defined in the body 402 of the assembly 400. A wellbore projectile 444 (shown in dashed lines) is depicted in FIG. 4A within the inner flow passageway 404 downhole from the sensor 418 and proceeding in a downhole direction (e.g., to the right in FIG. 4A). While generally depicted as a frac ball, the wellbore projectile 444 may be similar to either of the wellbore projectiles 200 and 300 of FIGS. 2A-2B and 3A-3B, respectively, or any other type of wellbore projectile (i.e., a plug, a wiper, etc.).

As the wellbore projectile 444 passes by the sensor 418, or comes into close proximity therewith, the sensor 418 may detect the presence of the wellbore projectile 444 and send a detection signal to the electronic circuitry 416 indicating the same. The electronic circuitry 416, in turn, may register a “count” of the wellbore projectile 444 and a total running count of how many wellbore projectiles (including the wellbore projectile 444) have bypassed the assembly 400. When a predetermined number of wellbore projectiles (including the wellbore projectile 444) have been counted, the electronic circuitry 416 may be programmed to actuate the assembly 400. More particularly, when the predetermined number of wellbore projectiles has been detected and otherwise registered, the electronic circuitry 416 may send an actuation signal to the actuator 422, which operates to move the actuation sleeve 428 from the run-in configuration, as shown in FIG. 4A, to the actuated configuration, as shown in FIGS. 4B and 4C.

In some embodiments, as mentioned above, the actuator 422 may be any mechanical, electro-mechanical, hydraulic, or pneumatic actuation device capable of displacing the actuation sleeve 428 from the run-in configuration to the actuated configuration. In at least one embodiment, however, the actuator 422 may be an electro-hydraulic piston lock that includes a piercing member (not shown) configured to pierce an adjacent pressure barrier (not shown), such as a burst disk. The pressure barrier may be arranged in the assembly 400 such that it initially isolates the electronics cavity 414 from the hydraulic cavity 434. Once the actuation signal from the electronic circuitry 416 is received by the actuator 422, a chemical charge in the piercing member is triggered and the piercing member is thrust into and penetrates the pressure barrier. Penetrating the pressure barrier allows the pressurized hydraulic fluid in the hydraulic cavity 434 to seek pressure equilibrium by escaping into the lower pressure electronics cavity 414 via the hydraulic conduit 438. As the hydraulic fluid escapes the hydraulic cavity 434, a pressure differential may be generated across the actuation sleeve 428 that urges the actuation sleeve 428 to move to the actuation configuration.

Referring to FIG. 4B, as the actuation sleeve 428 moves to the actuation configuration, the flapper valve 430 gradually becomes exposed to the inner flow passageway 404 and is therefore eventually able to move to its closed configuration (as shown in dashed lines in FIG. 4B). More particularly, once the flapper valve 430 is no longer secured in the open configuration between the actuation sleeve 428 and the body 402 (i.e., the ported sub 412), the torsion spring 440 may pivot the flapper valve 430 to the closed configuration where it engages and seats against the flapper seat 442 provided on the sliding sleeve 424. In the closed configuration, the flapper valve 430 may form a fluid tight seal in the inner flow passageway 404 and thereby prevent fluid migration in the downhole direction (i.e., to the right in FIGS. 4A-4C) and otherwise past that point within the work string 114 (FIG. 1).

Referring to FIG. 4C, with the flapper valve 430 in the closed configuration, the work string 114 (FIG. 1) may then be pressurized uphole from the flapper valve 430, and thereby correspondingly pressurize the inner flow passageway 404. Pressurizing the work string 114 (and the inner flow passageway 404) may generate a pressure differential across the flapper valve 430, which may transfer an axial load to the sliding sleeve 424. Upon assuming a predetermined axial load, the shearable device(s) may fail or otherwise shear, thereby releasing the sliding sleeve 424 from engagement with the body 402 (i.e., the ported sub 412) and urging the sliding sleeve 424 to move from the closed position to the open position. In the open position, the ports 426 are exposed and therefore able to facilitate fluid communication into and out of the work string 114. Moreover, with the ports 426 exposed, a treatment fluid, such as a fracturing or stimulation fluid, may be introduced into the work string 114 and injected into the surrounding subterranean formation 108 (FIG. 1) via the ports 426.

Referring now to FIGS. 6A and 6B, with continued reference to FIGS. 4A-4C, illustrated are enlarged cross-sectional side views of the assembly 400, according to one or more embodiments. More particularly, FIGS. 6A and 6B depict enlarged views of the sliding sleeve 424 and the flapper valve 430. Following the fracturing or stimulation operations discussed above, the fluid pressure within the work string 114 (FIG. 1) may be released and ambient fluid pressure from the subterranean formation 108 (FIG. 1) may allow formation fluids to flow toward the surface 140 (FIG. 1) within the inner flow passageway 404 in the direction A (i.e., the uphole direction). As the formation fluids flow in the direction A, the spring force of the torsion spring 440 may be overcome by the flowing formation fluids and the flapper valve 430 may therefore become unseated from the flapper seat 442, as shown in FIG. 6A. Unseating the flapper valve 430 from the flapper seat 442 may allow the formation fluids to flow past the flapper valve 430 and uphole within the inner flow passageway 404.

In some embodiments, the formation fluids flowing in the direction A may also urge the wellbore projectile 444 to flow back toward the surface 104 in the direction A, as shown in FIG. 6B. While flowing in the direction A within the inner flow passageway 404, the wellbore projectile 444 will eventually locate and engage the flapper valve 430 from the downhole direction. Upon engaging the flapper valve 430, the wellbore projectile 444 may overcome the spring force of the torsion spring 440 and unseat the flapper valve 430 from the flapper seat 442. The wellbore projectile 444 may then be able to bypass the flapper valve 430 in the direction A and, in some cases, may flow back to the surface 104 (FIG. 1) to be recovered.

Referring again to FIG. 1, with continued reference to the prior figures, the completion 120 may include as many sliding sleeve assemblies 130a-c as required to undertake a desired fracturing or stimulation operation in the subterranean formation 108. The electronic circuitry (e.g., the electronic circuitry 416 of FIGS. 4A-4C) of each sliding sleeve assembly 130a-c may be programmed with a predetermined wellbore projectile 136 “count.” Upon reaching or otherwise registering the predetermined wellbore projectile 136 count, each sliding sleeve assembly 130a-c may then be actuated. More particularly, the electronic circuitry associated with the third sliding sleeve assembly 130c may require the detection and counting of one wellbore projectile 136 before actuating the third sliding sleeve assembly 130c; the electronic circuitry associated with the second sliding sleeve assembly 130b may require the detection and counting of two wellbore projectiles 136 before actuating the third sliding sleeve assembly 130b; and the electronic circuitry associated with the first sliding sleeve assembly 130a may require the detection and counting of one wellbore projectile 136 before actuating the first sliding sleeve assembly 130a.

In the illustrated embodiment, the first wellbore projectile 136a has been introduced into the work string 114 and conveyed past each of the sensors 138a-c such that each sensor 138a-c is able to detect the wellbore projectile 136a and increase its wellbore projectile “count” by one. Since the electronic circuitry associated with the third sliding sleeve assembly 130c is pre-programmed with a predetermined “count” of one wellbore projectile, upon detecting the first wellbore projectile 136a, the sliding sleeve 132 of the third sliding sleeve assembly 130c may be actuated to the open position. Upon conveying the second wellbore projectile 136b into the work string 114, the first and second sensors 138a,b are able to detect the second wellbore projectile 136b and increase their respective wellbore projectile “counts” to two. Since the electronic circuitry associated with the second sliding sleeve assembly 130b is pre-programmed with a predetermined “count” of two wellbore projectiles, upon detecting the second wellbore projectile 136b, the sliding sleeve 132 of the second sliding sleeve assembly 130b may be actuated to the open position. Upon conveying a third wellbore projectile (not shown) into the work string 114, the first sensor 138a is able to detect the third wellbore projectile and increase its wellbore projectile “count” to three. Since the electronic circuitry associated with the third sliding sleeve assembly 130a is pre-programmed with a predetermined “count” of three wellbore projectiles, upon detecting the third wellbore projectile, the sliding sleeve 132 of the first sliding sleeve assembly 130a may be actuated to the open position.

In some embodiments, the wellbore projectiles 136 may be substantially the same size. In embodiments where the wellbore projectiles 136 are frac balls, as described herein, the wellbore projectiles 136 may each exhibit a diameter that is no more than 0.1 inches different from each other.

As discussed above, following stimulation operations, the wellbore projectiles 136 may be returned to the surface under pressure by flowing within the work string 114 with formation fluids. In other embodiments, it may be necessary to introduce a drill bit or mill into the wellbore 106 to drill out the various wellbore projectiles 136, and thereby facilitate fluid communication back to the surface 104 for production operations. In such embodiments, the flapper valves (i.e., the flapper valve 430 of FIGS. 4A-4C) may be made of an easily millable material, such as cast iron, aluminum, or a composite material so that the flapper valves may also be milled.

Those skilled in the art will readily recognize that milling out wellbore projectiles requires valuable time and resources. According to the present disclosure, however, the wellbore projectiles 136 (including the wellbore projectiles 200 and 300 of FIGS. 2A-2B and 3A-3C, respectively) may be at least partially made of a dissolvable and/or degradable material to obviate the time-consuming requirement of drilling out the wellbore projectiles 136. As used herein, the term “degradable material” refers to any material or substance that is capable of or otherwise configured to degrade or dissolve following the passage of a predetermined amount of time or after interaction with a particular downhole environment (e.g., temperature, pressure, downhole fluid, etc.), treatment fluid, etc.

Referring again to FIG. 2B, for example, in some embodiments, the entire wellbore projectile 200 may be made of a degradable material. In other embodiments, only a portion of the wellbore projectile 200 may be made of the degradable material. For instance, in some embodiments, all or a portion of the downhole end 212 of the body 202 may be made of the degradable material. As illustrated, for example, the body 202 may further include a tip 220 that forms an integral part of the body 202 or is otherwise coupled thereto. In the illustrated embodiment, the tip 220 may be threadably coupled to the body 202. In other embodiments, however, the tip 220 may alternatively be welded, brazed, adhered, or mechanically fastened to the body 202, without departing from the scope of the disclosure. After stimulation operations have completed, the degradable material may be configured to dissolve or degrade, thereby leaving a full-bore inner diameter through the sliding sleeve assemblies 130a-c (FIG. 1) without the need to mill or drill out.

Suitable degradable materials that may be used in accordance with the embodiments of the present disclosure include borate glasses, polyglycolic acid and polylactic acid. Polyglycolic acid and polylactic acid tend to degrade by hydrolysis as the temperature increase. Other suitable degradable materials include oil-degradable polymers, which may be either natural or synthetic polymers and include, but are not limited to, polyacrylics, polyamides, and polyolefins such as polyethylene, polypropylene, polyisobutylene, and polystyrene. Other suitable oil-degradable polymers include those that have a melting point that is such that it will dissolve at the temperature of the subterranean formation in which it is placed.

In addition to oil-degradable polymers, other degradable materials that may be used in conjunction with the embodiments of the present disclosure include, but are not limited to, degradable polymers, dehydrated salts, and/or mixtures of the two. As for degradable polymers, a polymer is considered to be “degradable” if the degradation is due to, in situ, a chemical and/or radical process such as hydrolysis, oxidation, or UV radiation. Suitable examples of degradable polymers that may be used in accordance with the embodiments of the present invention include polysaccharides such as dextran or cellulose; chitins; chitosans; proteins; aliphatic polyesters; poly(lactides); poly(glycolides); poly(ε-caprolactones); poly(hydroxybutyrates); poly(anhydrides); aliphatic or aromatic polycarbonates; poly(orthoesters); poly(amino acids); poly(ethylene oxides); and polyphosphazenes. Of these suitable polymers, as mentioned above, polyglycolic acid and polylactic acid may be preferred.

Polyanhydrides are another type of particularly suitable degradable polymer useful in the embodiments of the present invention. Polyanhydride hydrolysis proceeds, in situ, via free carboxylic acid chain-ends to yield carboxylic acids as final degradation products. The erosion time can be varied over a broad range of changes in the polymer backbone. Examples of suitable polyanhydrides include poly(adipic anhydride), poly(suberic anhydride), poly(sebacic anhydride), and poly(dodecanedioic anhydride). Other suitable examples include, but are not limited to, poly(maleic anhydride) and poly(benzoic anhydride).

Blends of certain degradable materials may also be suitable. One example of a suitable blend of materials is a mixture of polylactic acid and sodium borate where the mixing of an acid and base could result in a neutral solution where this is desirable. Another example would include a blend of poly(lactic acid) and boric oxide. The choice of degradable material also can depend, at least in part, on the conditions of the well, e.g., wellbore temperature. For instance, lactides have been found to be suitable for lower temperature wells, including those within the range of 60° F. to 150° F., and polylactides have been found to be suitable for well bore temperatures above this range. Also, poly(lactic acid) may be suitable for higher temperature wells. Some stereoisomers of poly(lactide) or mixtures of such stereoisomers may be suitable for even higher temperature applications. Dehydrated salts may also be suitable for higher temperature wells.

In other embodiments, the degradable material may be a galvanically corrodible metal or material configured to degrade via an electrochemical process in which the galvanically corrodible metal corrodes in the presence of an electrolyte (e.g., brine or other salt fluids in a wellbore). Suitable galvanically-corrodible metals include, but are not limited to, gold, gold-platinum alloys, silver, nickel, nickel-copper alloys, nickel-chromium alloys, copper, copper alloys (e.g., brass, bronze, etc.), chromium, tin, aluminum, iron, zinc, magnesium, and beryllium.

In some embodiments, all or a portion of the flapper valve 430 may also be made of a degradable material, such as the degradable materials mentioned above. More particularly, and with reference again to FIGS. 4A-4C, when the flapper valve 430 is maintained in the open configuration with the actuation sleeve 428, the flapper valve 430 may be isolated from wellbore fluids within the inner flow passageway 404. Once the actuation sleeve 428 is displaced and moves to the actuated configuration, the flapper valve 430 may be exposed to the wellbore fluids and also free to move to its closed configuration. Upon contacting the wellbore fluids, portions of the flapper valve 430 that are made of a degradable material may begin to degrade and otherwise dissolve. The degradation process for the flapper valve 430 may require between about two days to about fifty days, depending on the degradable material and the wellbore fluids.

Embodiments disclosed herein include:

A. A sliding sleeve assembly that includes a body that defines an inner flow passageway and one or more ports that enable fluid communication between the inner flow passageway and an exterior of the body, one or more sensors positioned on the body to detect wellbore projectiles that traverse the inner flow passageway, a sliding sleeve arranged within the body and movable between a closed position, where the sliding sleeve occludes the one or more ports, and an open position, where the sliding sleeve has moved to expose the one or more ports, a flapper valve arranged within the body and movable between an open configuration, where the flapper valve allows fluid flow through the inner flow passageway in a downhole direction, and a closed configuration, where the flapper valve seats against a flapper seat defined on the sliding sleeve and prevents fluid flow through the inner flow passageway in the downhole direction, and an actuation sleeve arranged within the body and movable between a run-in configuration, where the actuation sleeve secures the flapper valve in the open configuration, and an actuated configuration, where the actuation sleeve has moved to allow the flapper valve to move to the closed configuration.

B. A method that includes introducing one or more wellbore projectiles into a work string extended within a wellbore, the work string providing a sliding sleeve assembly that includes a body defining an inner flow passageway and one or more ports that enable fluid communication between the inner flow passageway and an exterior of the body, the sliding sleeve assembly further including a sliding sleeve movably arranged within the body to occlude or expose the one or more ports, detecting the one or more wellbore projectiles with one or more sensors positioned on the body, actuating an actuation sleeve arranged within the body when the one or more sensors detects a predetermined number of the one or more wellbore projectiles, moving a flapper valve arranged within the body from an open configuration to a closed configuration upon actuation of the actuation sleeve, wherein, when in the closed configuration, the flapper valve seats against a flapper seat defined on the sliding sleeve and prevents fluid flow through the inner flow passageway in a downhole direction, increasing a fluid pressure within the work string uphole from the flapper valve, and moving the sliding sleeve from a closed position, where the sliding sleeve occludes the one or more ports, to an open position, where the one or more ports are exposed.

Each of embodiments A and B may have one or more of the following additional elements in any combination: Element 1: further comprising electronic circuitry communicably coupled to the one or more sensors, and an actuator communicably coupled to the electronic circuitry, wherein, when the one or more sensors detect a predetermined number of the wellbore projectiles, the electronic circuitry sends an actuation signal to the actuator to actuate the actuation sleeve to the actuated configuration. Element 2: wherein the actuator is selected from the group consisting of a mechanical actuator, an electro-mechanical actuator, a hydraulic actuator, a pneumatic actuator, an electro-hydraulic piston lock, and any combination thereof. Element 3: wherein the flapper valve exhibits a curved profile. Element 4: wherein the wellbore projectiles are selected from the group consisting of a frac ball, a wellbore dart, a wiper, and a plug. Element 5: wherein the wellbore projectiles are frac balls that exhibit substantially the diameter. Element 6: wherein the wellbore projectiles exhibit known magnetic properties detectable by the one or more sensors. Element 7: wherein the wellbore projectiles emit a radio frequency detectable by the one or more sensors. Element 8: wherein the one or more sensors are mechanical switches that are mechanically manipulated through physical contact with the wellbore projectiles as the wellbore projectiles traverse the inner flow passageway. Element 9: wherein at least a portion of the wellbore projectiles is made of a degradable material selected from the group consisting of a borate glass, a galvanically-corrodible metal, polyglycolic acid, polylactic acid, and any combination thereof. Element 10: wherein the flapper valve comprises a material selected from the group consisting of cast iron, aluminum, and a composite material. Element 11: wherein, when in the open configuration, the flapper valve is isolated from wellbore fluids, and wherein, when in the closed configuration, the flapper valve is exposed to the wellbore fluid. Element 12: wherein at least a portion of the flapper valve is made of a degradable material selected from the group consisting of a borate glass, a galvanically-corrodible metal, polyglycolic acid, polylactic acid, and any combination thereof.

Element 13: wherein the sliding sleeve assembly further includes electronic circuitry communicably coupled to the one or more sensors, and wherein detecting the one or more wellbore projectiles with the one or more sensors comprises sending a detection signal to the electronic circuitry with the one or more sensors when one of the one or more wellbore projectiles is detected, and counting with the electronic circuitry how many of the one or more wellbore projectiles have been detected by the one or more sensors based on the detection signal. Element 14: wherein the sliding sleeve assembly further includes an actuator communicably coupled to the electronic circuitry, and wherein actuating the actuation sleeve further comprises sending an actuation signal to the actuator with the electronic circuitry when the one or more sensors detects the predetermined number of the one or more wellbore projectiles, and actuating the actuation sleeve with the actuator to an actuated configuration, wherein, when in the actuated configuration, the flapper valve is able to move to the closed configuration. Element 15: wherein detecting the one or more wellbore projectiles with the one or more sensors comprises detecting a known magnetic property exhibited by the one or more wellbore projectiles. Element 16: wherein detecting the one or more wellbore projectiles with the one or more sensors comprises detecting a radio frequency emitted by the one or more wellbore projectiles. Element 17: wherein the one or more sensors are mechanical switches, and wherein detecting the one or more wellbore projectiles with the one or more sensors comprises physically contacting the one or more sensors with the one or more wellbore projectiles as the one or more wellbore projectiles traverse the inner flow passageway. Element 18: wherein at least a portion of the one or more wellbore projectiles is made of a degradable material selected from the group consisting of a borate glass, a galvanically-corrodible metal, polyglycolic acid, polylactic acid, and any combination thereof, the method further comprising allowing the degradable material to degrade. Element 19: wherein increasing the fluid pressure within the work string uphole from the flapper valve further comprises generating a pressure differential across the flapper valve and thereby transferring an axial load to the sliding sleeve and one or more shearable devices securing the sliding sleeve in the closed position, and assuming a predetermined axial load with the one or more shearable devices such that the one or more shearable devices fail and thereby allow the sliding sleeve to move to the open position. Element 20: further comprising introducing a treatment fluid into the work string, injecting the treatment fluid into a surrounding subterranean formation via the one or more ports, releasing the fluid pressure within the work string, and allowing formation fluid to flow uphole through the flapper valve. Element 21: further comprising flowing the one or more wellbore projectiles uphole through the flapper valve with the formation fluid. Element 22: wherein the flapper valve comprises a material selected from the group consisting of cast iron, aluminum, and a composite material, and the method further comprises milling out the flapper valve. Element 23: wherein at least a portion of the flapper valve is made of a degradable material selected from the group consisting of a borate glass, a galvanically-corrodible metal, polyglycolic acid, polylactic acid, and any combination thereof, the method further comprising allowing the degradable material to degrade.

By way of non-limiting example, exemplary combinations applicable to A and C include: Element 1 with Element 2, Element 13 with Element 14, Element 3 with Element 10, Element 3 with Element 12, Element 4 with Element 5, Element 4 with Element 6, Element 4 with Element 7, Element 15 with Element 18, Element 16 with Element 18, and Element 17 with Element 18.

Therefore, the disclosed systems and methods are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the teachings of the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present disclosure. The systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

As used herein, the phrase “at least one of” preceding a series of items, with the terms “and” or “or” to separate any of the items, modifies the list as a whole, rather than each member of the list (i.e., each item). The phrase “at least one of” allows a meaning that includes at least one of any one of the items, and/or at least one of any combination of the items, and/or at least one of each of the items. By way of example, the phrases “at least one of A, B, and C” or “at least one of A, B, or C” each refer to only A, only B, or only C; any combination of A, B, and C; and/or at least one of each of A, B, and C.

MULTI-ZONE ACTUATION SYSTEM USING WELLBORE PROJECTILES AND FLAPPER VALVES

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