Patent Publication Number: US-11655689-B2

Title: Wireless activation of wellbore completion assemblies

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This Continuation application claims priority to and benefit of U.S. application Ser. No. 16/335,242, filed Mar. 20, 2019, and International application no. PCT/US2016/059641, filed Oct. 31, 2016, the disclosures of which are incorporated by reference herein in its entirety. 
    
    
     BACKGROUND 
     Hydrocarbon-producing wells are often stimulated by hydraulic fracturing operations in order to enhance the production of hydrocarbons present in subterranean formations. During a typical fracturing operation, a servicing fluid (i.e., a fracturing fluid or a perforating fluid) is introduced into a wellbore that penetrates a subterranean formation and is injected into the subterranean formation at a hydraulic pressure sufficient to create or enhance a network of fractures therein. The resulting fractures serve to increase the conductivity potential for extracting hydrocarbons from the subterranean formation. 
     In some wellbores, it may be desirable to selectively generate multiple fracture networks along the wellbore at predetermined distances apart from each other, thereby creating multiple interval “pay zones” in the subterranean formation. Each pay zone may include a corresponding fracturing assembly used to initiate and carry out the hydraulic fracturing operation. Following the hydraulic fracturing operation, the fracturing assemblies are closed and corresponding production assemblies are initiated and operated to extract hydrocarbons from the various pay zones. Extracted hydrocarbons are then conveyed to the well surface for collection. 
    
    
     
       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    is a well system that may employ the principles of the present disclosure. 
         FIGS.  2 A- 2 E  are cross-sectional side views of an example fracturing assembly. 
         FIGS.  3 A and  3 B  are individual isometric views of an example embodiment of the magnetic projectile of  FIG.  2 A . 
         FIGS.  4 A and  4 B  are cross-sectional side views of an example production assembly. 
         FIG.  5    is an isometric view of an example completion section that may form part of the completion assembly of  FIG.  1   , according to one or more embodiments. 
         FIG.  6 A  is a partial cross-sectional side view of the fracturing assembly of  FIG.  5   . 
         FIGS.  6 B and  6 C  are enlarged cross-sectional side views of the first and second frac actuators of  FIG.  6 A , respectively, as indicated by the dashed boxes in  FIG.  6 A . 
         FIGS.  6 D and  6 E  depict progressive views of the fracturing assembly of  FIG.  6 A  during example operation. 
         FIG.  7 A  is a partial cross-sectional side view of the production assembly of  FIG.  5   . 
         FIG.  7 B  is an enlarged cross-sectional side view of the production actuator of  FIG.  7 A , as indicated by the dashed box in  FIG.  7 A . 
         FIG.  7 C  is a cross-sectional side view of the production assembly of  FIG.  7 A  with the production sleeve moved to the open position. 
         FIGS.  8 A and  8 B  are cross-sectional side views of an alternate embodiment of the fracturing assembly of  FIGS.  6 A- 6 E . 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure is related to downhole completion assemblies in the oil and gas industry and, more particularly, to actuating fracturing and production assemblies using wireless communication to undertake hydraulic fracturing and production operations. 
     Embodiments disclosed herein describe the actuation (movement between open and closed positions) of fracture and production sleeves used in associated fracturing and production assemblies, respectively, through wireless means. One example, completion section for a downhole completion assembly includes a base pipe that defines a central flow passage, one or more injection ports, and one or more production ports. A fracturing assembly is included in the completion section and includes a frac sleeve positioned within the central flow passage adjacent the injection ports, a sensor that detects a wireless signal, a first frac actuator actuatable in response to the wireless signal to move the frac sleeve and expose the injection ports, and a second frac actuator actuatable based on the wireless signal to move the frac sleeve to occlude the injection ports. A production assembly is also included in the completion section and is axially offset from the fracturing assembly. The fracturing assembly includes a production sleeve positioned within the central flow passage adjacent the production ports, a filtration device arranged about the base pipe, and a production actuator actuatable based on the wireless signal or an additional wireless signal to move the production sleeve to an open position where the production ports are exposed. 
       FIG.  1    is a well system  100  that may employ the principles of the present disclosure, according to one or more embodiments of the disclosure. As depicted, the well system  100  includes a wellbore  102  that extends through various earth strata and has a substantially vertical section  104  that transitions into a substantially horizontal section  106 . The upper portion of the vertical section  104  may be lined with a string of casing  108  cemented therein to support the wellbore  102 , and the horizontal section  106  may extend through one or more hydrocarbon bearing subterranean formations  110 . In at least one embodiment, as illustrated, the horizontal section  106  may comprise an open hole section of the wellbore  102 . In other embodiments, however, the casing  108  may also extend into the horizontal section  106 , without departing from the scope of the disclosure. 
     A work string  112  is extended into the wellbore  102  from a surface location, such as the Earth&#39;s surface, and may be used to convey (“run”) a wellbore completion assembly  114  into the wellbore  102 . As illustrated, the completion assembly  114  may be coupled to the end of the work string  112  and generally arranged within the horizontal section  106 . In at least one embodiment, the completion assembly  114  divides the wellbore  102  into various production intervals or “pay zones” adjacent the subterranean formation  110 . To accomplish this, as illustrated, the completion assembly  114  includes a plurality of wellbore packers  116  axially spaced from each other along the length of the completion assembly  114 . Once set within the wellbore  102 , each wellbore packer  116  provides a corresponding fluid seal between the completion assembly  114  and the inner wall of the wellbore  102 , and thereby effectively defines discrete production intervals within the wellbore  102 . Sections of the completion assembly  114  between axially adjacent wellbore packers  116  may be referred to herein as “completion sections,” alternately referred to as production intervals. 
     It should be noted that even though  FIG.  1    depicts multiple completion sections defined by the separating wellbore packers  116 , the completion assembly  114  may provide any number of completion sections with a corresponding number of wellbore packers  116  arranged therein. In other embodiments, for example, the wellbore packers  116  may be entirely omitted from the completion assembly  114 , and the system  100  may alternatively include only a single upper wellbore packer  117  that isolates the entire completion assembly  114  from upper portions of the wellbore  102 . 
     In the illustrated embodiment, each completion section may include at least one fracturing assembly  118  and at least one production assembly  120 . In other embodiments, however, such as in embodiments where the multiple wellbore packers  116  are replaced with the upper wellbore packer  117 , the system  100  may alternatively include only one fracturing assembly  118  and one or more production assemblies  120  used to service the entire completion assembly  114 . The fracturing assembly(ies)  118  may be actuated or otherwise operated to inject a fluid into the annulus  122  defined between the completion assembly  114  and the wellbore  102 . The fluid injected by the fracturing assemblies  118  may comprise, for example, a fracturing fluid used to create a network of fractures in the surrounding formation  110 . The fluid may also or alternatively comprise a gravel slurry that fills the annulus  122  following the creation of the fracture network. In yet other applications, the fluid injected by the fracturing assemblies  118  may comprise a stimulation fluid, a treatment fluid, an acidizing fluid, a conformance fluid, or any combination of the foregoing fluids. 
     Upon closing the fracturing assembly(ies)  118 , a corresponding production assembly  120  may subsequently be actuated or otherwise operated to draw in fluids from the formation  110  to be conveyed to the surface of the well for collection. Each production assembly  120  serves the primary function of filtering particulate matter out of the production fluid stream originating from the formation  110  such that particulates and other fines are not produced to the surface. To accomplish this, the production assemblies  120  may include one or more filtration devices, such as well screens or slotted liners that allow fluids to flow therethrough but generally prevent the influx of particulate matter of a predetermined size. 
     While  FIG.  1    depicts the completion assembly  114  as being arranged in a generally horizontal section  106  of the wellbore  102 , the completion assembly  114  is equally well suited for use in other directional configurations including vertical, deviated, slanted, or any combination thereof. The use of directional terms herein such as above, below, upper, lower, upward, downward, left, right, 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 surface of the well and the downhole direction being toward the toe of the well. 
     Actuation or operation of the fracturing assemblies  118  and the production assemblies  120  is conventionally undertaken by introducing a shifting tool downhole and physically engaging and moving corresponding fracture and production sleeves between open and closed positions. According to embodiments of the present disclosure, however, actuating the corresponding fracture and production sleeves between open and closed positions may be accomplished through wireless means. In some embodiments, for instance, predetermined wireless signals may be conveyed and otherwise transmitted to one or both of the fracturing and production assemblies  118 ,  120 . Upon detection of the predetermined wireless signals, actuation of the fracturing and production assemblies  118 ,  120  may be triggered for operation. In other embodiments, however, one wireless signal may be provided and detected to operate a given fracturing assembly  118 , and a corresponding production assembly  120  may be subsequently actuated based on a timer triggered by the wireless signal. The following discussion provides several examples as to how the fracturing and production assemblies  118 ,  120  may be wirelessly operated. 
       FIGS.  2 A- 2 E  are cross-sectional side views of an example fracturing assembly  200 , according to one or more embodiments. The fracturing assembly  200  may be the same as or similar to the any of the fracturing assemblies  118  of  FIG.  1    and, therefore, may be included in the completion assembly  114  ( FIG.  1   ) and used to inject a fluid into the annulus  122  defined between the completion assembly  114  and the wellbore  102  ( FIG.  1   ).  FIGS.  2 A- 2 E  depict progressive views of the fracturing assembly  200  during example operation. 
     In  FIG.  2 A , the fracturing assembly  200  is depicted as including a base pipe  202  that defines a central flow passage  204 . The base pipe  202  may form an integral part of the completion assembly  114  ( FIG.  1   ), such as being coupled between opposing lengths of the completion assembly  114 . As a result, the central flow passage  204  may be in fluid communication with the work string  112  ( FIG.  1   ) such that fluids and objects (e.g., wellbore projectiles) conveyed into the wellbore  102  ( FIG.  1   ) via the work string  112  will communicate with (flow into) the central flow passage  204 . 
     The fracturing assembly  200  may further include a fracture sleeve  206   a  (alternately referred to as a “frac” sleeve) and a closure sleeve  206   b , each being positioned for longitudinal movement within the central flow passage  204 . One or more injection ports  208  (one shown) are defined in the wall of the base pipe  202  and are blocked (occluded) when the frac sleeve  206   a  is in a first or “closed” position, thereby preventing fluid communication between the annulus  122  and the central flow passage  204 . As described below, however, the frac sleeve  206   a  is actuatable to move (i.e., displace) to a second or “open” position where the injection ports  208  are exposed. 
     To move the frac sleeve  206   a  to the open position, a first frac actuator  210   a  is triggered based on a wireless signal received or otherwise detected by a sensor  212 . While the sensor  212  is shown located downhole from the frac sleeve  206   a , the sensor  212  could alternatively be located uphole from the frac sleeve  206   a , without departing from the scope of the disclosure. The sensor  212  may comprise a variety of types of downhole sensors configured to detect or otherwise receive a variety of wireless signals. Moreover, the wireless signal may originate from a variety of locations, devices, or otherwise provided via a variety of means. In some applications, for example, the wireless signal may be transmitted from a well surface location or from an adjacent wellbore. In other applications, the wireless signal may be transmitted via a device or means located in or conveyed through the wellbore  102  ( FIG.  1   ). In such embodiments, the device or means may comprise an untethered tool, but could alternately be attached to a conveyance, such as wireline or slickline. 
     In some embodiments, the sensor  212  may comprise a magnetic sensor configured to detect the presence of a magnetic field or property produced by a wellbore projectile conveyed through the central flow passage  204 . In such embodiments, the sensor  212  may comprise, but is not limited to, a magneto-resistive sensor, a Hall-effect sensor, a conductive coil, or any combination thereof. In some embodiments, one or more permanent magnets can be combined with the sensor  212  to create a magnetic field that is disturbed by a wellbore projectile (or the like), and a detected change in said magnetic field can be an indication of the presence of the wellbore projectile. 
     In other embodiments, however, the sensor  212  may be configured to detect other types of wireless signals such as, but not limited to, an electromagnetic signal, a pressure signal, a temperature signal, an acoustic signal (e.g., noise), a fluid flowrate signal, or any combination thereof. Consequently, the sensor  212  may alternatively comprise at least one of an antenna, a pressure sensor, a temperature sensor, an acoustic sensor, a vibration sensor, a strain sensor, an accelerometer, a flow meter, or any combination thereof. 
     The sensor  212  is communicably connected to an electronics module  214  that includes electronic circuitry configured to determine whether the sensor  212  has detected a particular or predetermined wireless signal. The electronics module  214  may include a power supply, such as one or more batteries, a fuel cell, a downhole generator, or any other source of electrical power used to power operation of one or more of the electronics module  214 , the sensor  212 , and the first frac actuator  210   a.    
     In embodiments where the sensor  212  is a magnetic sensor, the electronic circuitry may be configured to determine whether the sensor  212  has detected a predetermined magnetic field, a pattern or combination of magnetic fields, or another magnetic property of a magnetic projectile  215  (shown in dashed) introduced into the central flow passage  204 . The magnetic projectile  215  may be pumped to or past the sensor  212  in order to transmit a magnetic signal to the first frac actuator  210   a . The electronics module  214  may include a non-volatile memory having a database programmed with a predetermined magnetic field(s) or other magnetic properties for comparison against magnetic fields/properties exhibited by the magnetic projectile  215  and detected by the sensor  212 . 
     In the illustrated embodiment, the magnetic projectile  215  is depicted in the form of a sphere or ball, such as a frac ball known to those skilled in the art, but could alternatively comprise other shapes or types of wellbore projectiles, such as a dart or a plug. In other embodiments, the magnetic projectile  215  may comprise a fluid or a gel, such as a ferrofluid, a magnetorheological fluid, or another type of fluid that exhibits magnetic properties detectable by the sensor  212 . In yet other embodiments, the magnetic projectile  215  might comprise a pill or slurry of magnetic particles pumped into the central flow passage  204  to be detected by the sensor  212 . In even further embodiments, the magnetic projectile  215  may comprise a downhole tool, such as a perforating charge with a magnetic attachment added to the perforating charge. 
     In embodiments where the sensor  212  is a pressure sensor, predetermined pressure levels or sequences may be programmed into the memory of the electronics module  214  for comparison against an actual fluid pressure or a series (pattern) of pressure changes (fluctuations) detected in the central flow passage  204  by the sensor  212 . Accordingly, to actuate the first frac actuator  210   a , a well operator may selectively pressurize the central flow passage  204  to match one of the programmed pressure levels or sequences. 
     In embodiments where the sensor  212  is a temperature sensor, a predetermined temperature level or disparity (fluctuation) may be programmed into the memory of the electronics module  214  for comparison against the real-time temperature or temperature fluctuations detected in the central flow passage  204  by the sensor  212 . 
     In embodiments where the sensor  212  is an acoustic sensor, predetermined acoustic signatures or acoustic sequences may be programmed into the memory of the electronics module  214  for comparison against noises or a series (pattern) of noise changes detected by the sensor  212 . Such noises may be generated, for example, by axially translating and/or rotating a pipe string or other downhole tool within the wellbore. In other embodiments, however, the noises may comprise acoustic signals transmitted to the sensor  212  from a remote location, such as the well surface. In yet other embodiments, the noise may be generated by fluid movement. 
     If the electronics module  214  determines that the sensor  212  has affirmatively detected a predetermined or particular wireless signal, the electronic circuitry triggers actuation of the first frac actuator  210   a  to cause the frac sleeve  206   a  to move towards the open position to expose the injection ports  208 . 
     In the illustrated example, the first frac actuator  210   a  includes a piercing member  216  operable to pierce a pressure barrier  218  that initially separates a first chamber  220   a  and a second chamber  220   b  each defined in the base pipe  202 . The first frac actuator  210   a  can comprise any type of actuator (e.g., electrical, hydraulic, mechanical, explosive, chemical, a combination thereof, etc.) used to advance the piercing member  216  towards the pressure barrier  218  upon actuation. When the sensor  212  detects the predetermined wireless signal, the piercing member  216  pierces the pressure barrier  218 , and a support fluid  222  (e.g., oil) flows from the first chamber  220   a  to the second chamber  220   b , which generates a pressure differential across the frac sleeve  206   a . The generated pressure differential urges the frac sleeve  206   a  to move (displace) toward the open position (i.e., to the right in  FIG.  2 A ). 
     In some embodiments, the pressure differential generated by piercing the pressure barrier  218  may be sufficient to fully displace the frac sleeve  206   a  to its open position. In other embodiments, however, it may be required to pressurize the central flow passage  204  to move the frac sleeve  206   a  fully to its open position, as described below. 
     In  FIG.  2 B , the first frac actuator  210   a  is shown actuated as the piercing member  216  has pierced the pressure barrier  218  such that an amount of the support fluid  222  in the first chamber  220   a  is able to escape into the second chamber  220   b . The support fluid  222  entering the second chamber  220   b  generates a pressure differential across the frac sleeve  206   a  that urges the frac sleeve  206   a  to displace downward (i.e., to the right in  FIG.  2 B ) until engaging a baffle assembly  224  positioned in the central flow passage  204 . As illustrated, the baffle assembly  224  includes a retractable baffle  226  and a baffle receiving sleeve  228  secured to the base pipe  202  with one or more shear members  230 . As the frac sleeve  206   a  moves toward the open position it engages the retractable baffle  226  and forces the retractable baffle  226  against the baffle receiving sleeve  228 . Opposing angled surfaces on the retractable baffle  226  and the baffle receiving sleeve  228  allow the retractable baffle  226  to slidingly engage and ride up onto the baffle receiving sleeve  228 , and doing so radially contracts the retractable baffle  226  within the central flow passage  204  to a sealing position (i.e., a smaller inner diameter). 
     In this example, the retractable baffle  226  is in the form of an expandable ring that is contracted radially inward to its sealing position by the downward displacement of the frac sleeve  206   a . In other examples, however, the retractable baffle  226  may comprise another type of radially contractible device or mechanism, without departing from the scope of the disclosure. Moreover, in this example further axial displacement of the frac sleeve  206   a  is prevented by the baffle receiving sleeve  228 , which is secured to the base pipe  202  at the shear member  230 . 
     In  FIG.  2 C , with the retractable baffle  226  in the sealing position, the central flow passage  204  may be sealed and otherwise isolated with an isolation device  232  used to isolate the fracturing assembly  200  from downhole portions. In the illustrated embodiment, the isolation device  232  is in the form of a wellbore projectile that may be conveyed downhole to help fully move the frac sleeve  206   a  to the open position. More specifically, the isolation device  232  is conveyed to the fracturing assembly  200  and into the central flow passage  204  to be received by the retractable baffle  226 . While depicted in  FIG.  2 C  as a ball-type wellbore projectile, the isolation device  232  may alternatively comprise a dart, a wiper, a plug, or any other type of known wellbore projectile. The isolation device  232  may be conveyed to the fracturing assembly  200  by any known technique, such as by being dropped through the work string  112  ( FIG.  1   ), pumped through the central flow passage  204 , self-propelled, conveyed by wireline, slickline, coiled tubing, etc. 
     In embodiments where the differential pressure acting on the frac sleeve  206   a  is not sufficient to overcome the shear limit of the shear member  230 , the isolation device  232  may be used to seal the central flow passage  204  such that hydraulic pressure may be applied against the isolation device  232  to free the baffle receiving sleeve  228 . The isolation device  232  may be sized to locate and land on the retractable baffle  226  in its sealing position and thereby create a sealed interface. Once the isolation device  232  lands on the retractable baffle  226 , the fluid pressure in the central flow passage  204  may be increased to surpass the shear limit of the shear member  230  and thereby free the baffle receiving sleeve  228 . With the shear member  230  sheared, the remaining differential pressure across the frac sleeve  206   a  generated between the first and second chambers  220   a,b  may urge the frac sleeve  206   a  to displace the baffle receiving sleeve  228  and move to the open position. Otherwise, hydraulic pressure on the isolation device  232  may help urge the frac sleeve  206   a  to the fully open position. 
     In  FIG.  2 D , the frac sleeve  206   a  is shown moved fully to the open position and the isolation device  232  continues to provide a sealed interface against the retractable baffle  226 . A fluid  234  may then be flowed to the fracturing assembly  200  and into the central flow passage  204  at an elevated pressure to be injected into the annulus  122  via the exposed injection ports  208 . The fluid  234  may comprise, for example, a fracturing fluid used to create a network of fractures in the surrounding formation  110  ( FIG.  1   ) during a hydraulic fracturing operation. Alternatively, or in addition thereto, the fluid  234  may comprise a gravel slurry used to fill the annulus  122  during a gravel packing operation. 
     After hydraulic fracturing operations have finished, it may be desired to move the frac sleeve  206   a  back to the closed position in preparation for production operations or alternatively in preparation for hydraulic fracturing of another zone within the wellbore. To accomplish this, a second frac actuator  210   b  included in the fracturing assembly  200  may be actuated or otherwise operated to move (displace) the closure sleeve  206   b  and thereby move the frac sleeve  206   a  back to the closed position. Similar to the first frac actuator  210   a , in the illustrated example, the second frac actuator  210   b  includes a piercing member  236  configured to pierce a pressure barrier  238  that initially separates a third chamber  210   c  and a fourth chamber  210   d  each defined in the base pipe  202 . 
     In some embodiments, actuation of the second frac actuator  210   b  to move the closure sleeve  206   b  may be time delayed. More specifically, the electronic circuitry of the electronics module  214  may include a timer that may be triggered (started) upon detection of the predetermined wireless signal used to actuate the first frac actuator  210   a . In other applications, the timer may be triggered upon detection of a flow rate change through the central flow passage  204 , a temperature change from the flow, etc. The timer may be programmed with a predetermined time period for actuating the second frac actuator  206   b  and, upon expiration of the predetermined time period, the electronics module  214  may actuate (operate) the second frac actuator  210   b . The predetermined time period may be programmed to provide sufficient time to accomplish the hydraulic fracturing operations. For example, the predetermined time period may be about 6 hours, about 12 hours, about 24 hours, about 48 hours, more than 48 hours, or any time range falling therebetween. When the predetermined time period expires, the piercing member  236  is actuated to pierce the pressure barrier  238 , and a support fluid  242  (e.g., oil) flows from the third chamber  210   c  to the fourth chamber  210   d , which generates a pressure differential across the closure sleeve  206   b . The generated pressure differential urges the closure sleeve  206   b  to move (displace) uphole (i.e., to the left in  FIG.  2 D ) and toward the frac sleeve  206   a  and thereby move the frac sleeve  206   a  back to the closed position. 
     In other embodiments, however, a second or additional wireless signal may be detected by the sensor  212  to actuate the second frac actuator  210   b . In such embodiments, the sensor  212  may be positioned uphole from the frac and closure sleeves  206   a,b  and otherwise able to detect signals uphole from the isolation device  232 . The sensor  212 , however, need not be positioned uphole from the frac and closure sleeves  206   a,b  to detect the additional wireless signal. 
     In  FIG.  2 E , the frac sleeve  206   a  is shown moved back to the closed position by movement of the closure sleeve  206   b , which is caused by the piercing member  236  penetrating the pressure barrier  238  to allow the support fluid  242  to flow to the fourth chamber  210   d . As it moves in the uphole direction, the closure sleeve  206   b  axially engages the baffle receiving sleeve  228 , which places an uphole axial load on the frac sleeve  206   a  toward the closed position. In some embodiments, an axial extension  240  of the closure sleeve  206   b  may engage the retractable baffle  226  and allow the retractable baffle  226  to radially expand once more to interpose the frac sleeve  206   a  and the baffle receiving sleeve  228 . In such embodiments, the isolation device  232  ( FIG.  2 D ) may be released to flow downhole as the retractable baffle  226  radially expands, and thereby clearing the central flow passage  204  for subsequent fluid flow through the fracturing assembly  200 . 
     In other embodiments, the retractable baffle  226  may not be radially expanded as the closure sleeve  206   b  engages the retractable baffle  226  and moves the frac sleeve  206   a  back to closed position. In such embodiments, the isolation device  232  may alternatively be made of a degradable material that allows the isolation device  232  to dissolve over time and thereby clear the central flow passage  204  for subsequent fluid flow through the fracturing assembly  200 . Suitable degradable materials for the isolation device  232  include, but are not limited to, a galvanically-corrodible metal (e.g., silver and silver alloys, nickel and nickel alloys, nickel-copper alloys, nickel-chromium alloys, copper and copper alloys, chromium and chromium alloys, tin and tin alloys, aluminum and aluminum alloys, iron and iron alloys, zinc and zinc alloys, magnesium and magnesium alloys, and beryllium and beryllium alloys), micro-galvanic metals or materials (e.g., nano-structured matrix galvanic materials, such as a magnesium alloy with iron-coated inclusions), and a degradable polymer (e.g., polyglycolic acid, polylactic acid, and thiol-based plastics). 
       FIGS.  3 A and  3 B  are individual isometric views of an example embodiment of the magnetic projectile  215  of  FIG.  2 A . In the illustrated embodiment, the magnetic projectile  215  is in the general shape of a sphere  302 , such as a frac ball known to those skilled in the art. The sphere  302  may include one or more magnets (not shown in  FIGS.  3 A and  3 B ) retained in a plurality of recesses  304  defined in the outer surface of the sphere  302 . In other embodiments, however, the magnet(s) of the magnetic projectile  215  may be disposed entirely within the center of the sphere  302 , without departing from the scope of the disclosure. 
     In some embodiments, the recesses  304  may be arranged in a pattern, which, in this case, resembles that of stitching on a baseball. More particularly, the pattern shown in  FIGS.  3 A and  3 B  encompasses spaced apart positions distributed along a continuous undulating path about the sphere  302 . However, it should be clearly understood that any pattern of magnetic field-producing components may be used in the magnetic projectile  215 , in keeping with the scope of this disclosure. Indeed, the magnets may be arranged to provide a magnetic field that extends a predetermined distance from the magnetic projectile  215 , and to do so no matter the orientation of the sphere  302 . The pattern depicted in  FIGS.  3 A and  3 B  may be configured to project the produced magnetic field(s) substantially evenly around the sphere  302 . 
     The first frac actuator  210   a  ( FIGS.  2 A- 2 E ) may be actuated based on detection of the magnetic projectile  215  or a specific pattern or sequence of magnetic projectiles  215  as detected by the sensor  212  ( FIGS.  2 A- 2 E ). For example, the first frac actuator  210   a  may be actuated when a first magnetic projectile  215  is displaced into the fracturing assembly  200 , or when a predetermined number of magnetic projectiles  215  are detected by the sensor  212 . As another example, the first frac actuator  210   a  may be actuated in response to passage of a predetermined amount of time following detection of the particular magnetic projectile  215 , a predetermined spacing in time of two or more magnetic projectiles  215 , or a predetermined spacing of time between predetermined numbers of magnetic projectiles  215 . Thus, conveying a pattern of magnetic projectiles  215  into the fracturing assembly  200  can be used to transmit a corresponding magnetic signal to the first frac actuator  210   a.    
       FIGS.  4 A and  4 B  are cross-sectional side views of an example production assembly  400 , according to one or more embodiments. The production assembly  400  may be the same as or similar to the any of the production assemblies  120  of  FIG.  1    and, therefore, may be included in the completion assembly  114  and used to produce fluids from the annulus  122  and originating from the surrounding subterranean formation  110  ( FIG.  1   ). Moreover, the production assembly  400  may be used in conjunction with the above-described fracturing assembly  200  of  FIGS.  2 A- 2 E , such as being arranged in a common completion section of the completion assembly  114 .  FIGS.  4 A- 4 B  depict progressive views of the production assembly  400  during example operation. 
     In  FIG.  4 A , the production assembly  400  is depicted as including a base pipe  402  that defines a central flow passage  404  and one or more production ports  406  that facilitate fluid communication between the central flow passage  404  and the annulus  122 . The base pipe  402  may be the same as or an axial extension of the base pipe  202  of the fracturing assembly  200  of  FIGS.  2 A- 2 E . Accordingly, the central flow passage  404  may fluidly communicate with the central flow passage  204  ( FIGS.  2 A- 2 E ) of the fracturing assembly  200  and any fluids drawn into the base pipe  402  may be conveyed into the work string  112  ( FIG.  1   ) and transported to a surface location for collection. A filtration device  408  is arranged about the base pipe  402  and, in one embodiment, may extend from an end ring  410  arranged about the base pipe  402  to provide a mechanical interface between the base pipe  402  and the filtration device  408 . In other embodiments, however, the end ring  410  may be omitted and the filtration device  408  may alternatively be coupled directly to the base pipe  402 . 
     The filtration device  408  serves as a filter medium designed to allow fluids derived from the formation  110  ( FIG.  1   ) to flow therethrough but substantially prevent the influx of particulate matter of a predetermined size. In some embodiments, as illustrated, the filtration device  408  may comprise one or more well screens  412  arranged about the base pipe  402 . As illustrated, the well screen(s)  412  may be radially offset a short distance from the base pipe  402  and thereby define a production annulus  414  therebetween. In other embodiments, however, the well screen(s)  412  may be replaced with a slotted liner, or the like, without departing from the scope of the disclosure. 
     The well screen(s)  412  may be fluid-porous, particulate restricting devices made from of a plurality of layers of a wire mesh that are diffusion bonded or sintered together to form a fluid porous wire mesh screen. The well screen(s)  412  may alternatively include multiple layers of a weave mesh wire material having a uniform pore structure and a controlled pore size that is determined based upon the properties of the formation  110  ( FIG.  1   ). In other applications, however, the well screen(s)  412  may comprise a single layer of wire mesh, multiple layers of wire mesh that are not bonded together, a single layer of wire wrap, multiple layers of wire wrap or the like, that may or may not operate with a drainage layer. 
     The production assembly  400  may further include a production sleeve  416  positioned for longitudinal movement within the central flow passage  404 . The production ports  406  (one shown) are blocked (occluded) when the production sleeve  416  is in a first or “closed” position, thereby preventing fluid communication between the annulus  122  and the central flow passage  404 . As described below, however, the production sleeve  416  is actuatable to move (i.e., displace) to a second or “open” position where the production ports  406  are exposed. 
     To move the production sleeve  416  to the open position, a production actuator  418  is triggered based on a wireless signal received or otherwise detected by a production sensor  420 . The production sensor  420  may be similar to the sensor  212  of  FIG.  2 A  and, therefore, may comprise at least one of a magnetic sensor, an antenna, a pressure sensor, a temperature sensor, an acoustic sensor, a vibration sensor, a strain sensor, an accelerometer, a flow meter, or any combination thereof. Moreover, the production sensor  420  is communicably connected to an electronics module  422  similar to the electronics module  214  of  FIGS.  2 A- 2 D . Accordingly, the electronics module  422  may include electronic circuitry configured to determine whether the production sensor  420  has detected a particular wireless signal, and may also include a power supply used to power operation of one or more of the electronics module  422 , the production sensor  420 , and the production actuator  418 . 
     In embodiments where the production sensor  420  is a magnetic sensor, the electronic circuitry may be configured to determine whether the production sensor  420  has detected a predetermined magnetic field, a pattern or combination of magnetic fields, or another magnetic property of the magnetic projectile  215  introduced into the central flow passage  404 . The magnetic projectile  215  may be pumped to or past the production sensor  420  in order to transmit a magnetic signal to the first frac actuator  210   a . Similar to the electronics module  214  of  FIGS.  2 A- 2 D , the electronics module  422  may include a non-volatile memory having a database programmed with a predetermined magnetic field(s) or other magnetic properties for comparison against magnetic fields/properties exhibited by the magnetic projectile  215  and detected by the production sensor  420 . 
     In embodiments where the production sensor  420  is a pressure sensor, predetermined pressure levels or sequences may be programmed into the memory of the electronics module  422  for comparison against an actual fluid pressure or a series (pattern) of pressure changes (fluctuations) detected in the central flow passage  404  by the production sensor  420 . Accordingly, to actuate the production actuator  418 , a well operator may selectively pressurize the central flow passage  404  to match one of the programmed pressure levels or sequences. 
     In embodiments where the production sensor  420  is a temperature sensor, a predetermined temperature level or disparity (fluctuation) may be programmed into the memory of the electronics module  422  for comparison against the real-time temperature or temperature fluctuations detected in the central flow passage  404  by the production sensor  420 . 
     In embodiments where the production sensor  420  is an acoustic sensor, predetermined acoustic signatures or acoustic sequences may be programmed into the memory of the electronics module  422  for comparison against noises or a series (pattern) of noise changes detected by the production sensor  420 . Such noises may be generated, for example, by axially translating and/or rotating a pipe string or other downhole tool within the wellbore. In other embodiments, however, the noises may comprise acoustic signals transmitted to the production sensor  420  from a remote location, such as the well surface. In yet other embodiments, the noise may be generated by fluid movement. 
     If the electronics module  422  determines that the production sensor  420  has detected a predetermined wireless signal, the electronic circuitry triggers actuation of the production actuator  418  to cause the production sleeve  416  to move to the open position and thereby expose the production ports  406 . In some embodiments, as illustrated, the production actuator  418  may be similar to one or both of the first and second frac actuators  210   a,b  of  FIGS.  2 A- 2 E . More specifically, the production actuator  418  includes a piercing member  424  configured to pierce a pressure barrier  426  that initially separates a first chamber  428   a  and a second chamber  428   b  defined by the base pipe  402 . When the production sensor  420  detects the predetermined wireless signal, the piercing member  424  is triggered to pierce the pressure barrier  426 , and a support fluid  430  (e.g., oil) flows from the first chamber  428   a  to the second chamber  428   b , which generates a pressure differential across the production sleeve  416 . The generated pressure differential urges the production sleeve  416  to move (displace) toward the open position. 
     In  FIG.  4 B , the production actuator  418  is shown actuated as the piercing member  424  has pierced the pressure barrier  426  such that the support fluid  430  in the first chamber  428   a  is able to escape into the second chamber  428   b  and the resulting pressure differential has moved the production sleeve  416  to the open position. In the open position, a fluid  432  from the annulus  122  may be drawn through the filtration device  408  and into the production annulus  414 . The fluid  432  may traverse the exterior of the base pipe  402  within the production annulus  414  until locating the production ports  406 , which allow the fluid  432  to enter the central flow passage  404  for production to the well surface. 
     In some embodiments, actuation of the production sleeve  416  may be time delayed. More specifically, the electronic circuitry of the electronics module  422  may include a timer that may be triggered (started) upon detection of the predetermined wireless signal with the production sensor  420 . The timer may be programmed with a predetermined time period for actuating the production actuator  418  and, upon expiration of the predetermined time period, the electronics module  422  may send a signal that actuates (operates) the production actuator  418 . The predetermined time period may provide sufficient time to accomplish the preceding hydraulic fracturing operations described above with reference to the fracturing assembly  200  of  FIGS.  2 A- 2 E . The predetermined time period may be about 6 hours, about 12 hours, about 24 hours, about 48 hours, more than 48 hours, or any time range falling therebetween. 
       FIG.  5    is an isometric view of an example completion section  500  that may form part of the completion assembly  114  of  FIG.  1   , according to one or more embodiments. The completion section  500  may be generally located between axially adjacent wellbore packers  116  ( FIG.  1   ) and include a fracturing assembly  118  and a production assembly  120  axially offset from the fracturing assembly  118 . The production assembly  120  includes a plurality of filtration devices  502  used to prevent the influx of particulate matter of a predetermined size. In the illustrated embodiment, the filtration devices  502  are in the form of slotted liners  502 , but could alternatively comprise sand screens or another type of downhole filtration system, without departing from the scope of the disclosure. 
       FIG.  6 A  is a partial cross-sectional side view of the fracturing assembly  118  of  FIG.  5   , according to one or more embodiments. As mentioned above, the fracturing assembly  118  may be used to inject a fluid into the annulus  122  defined between the completion assembly  114  ( FIG.  1   ) and the wellbore  102  ( FIG.  1   ). The fracturing assembly  118  includes a base pipe  602  that defines a central flow passage  604  in fluid communication with the work string  112  ( FIG.  1   ) such that fluids and objects (e.g., wellbore projectiles) conveyed into the wellbore  102  via the work string  112  will communicate with (flow into) the central flow passage  604 . 
     The fracturing assembly  118  further includes a frac sleeve  606  positioned for longitudinal movement within the central flow passage  604 . One or more injection ports  608  (two shown) are defined in the wall of the base pipe  602   200  and are blocked (occluded) when the frac sleeve  606  is in a first or “closed” position, thereby preventing fluid communication between the annulus  122  and the central flow passage  604 . As discussed below, the frac sleeve  606  is actuatable to move (i.e., displace) to a second or “open” position where fluid communication between the annulus  122  and the central flow passage  604  is facilitated. In the illustrated embodiment, fluid communication is facilitated by aligning one or more frac ports  610  defined in the frac sleeve  606  with the injection ports  608 . 
     In some embodiments, as illustrated, the frac sleeve  606  may comprise two sleeve sections, shown as an upper sleeve section  612   a  and a lower sleeve section  612   b . As illustrated, the frac ports  610  are defined in the lower sleeve section  612   b . Moreover, as described below, the upper and lower sleeve sections  612   a,b  may be able to translate a short distance relative to one another within the central flow passage  604 . 
     The fracturing assembly  118  further includes a first frac actuator  614   a  and a second frac actuator  614   b . To move the frac sleeve  606  to the open position, the first frac actuator  614   a  is triggered, and to move the frac sleeve  606  back to the closed position, the second frac actuator  614   b  is triggered. The first frac actuator  614   a  may be triggered based on a wireless signal detected by a first sensor  616   a  coupled to the wall of the base pipe  602 . The first sensor  616   a  may be similar to the sensor  212  of  FIG.  2 A  and, therefore, may comprise at least one of a magnetic sensor, an antenna, a pressure sensor, a temperature sensor, an acoustic sensor, a vibration sensor, a strain sensor, an accelerometer, a flow meter, or any combination thereof. While the first sensor  616   a  is shown located downhole from the frac sleeve  606 , the first sensor  616   a  could alternatively be located uphole from the frac sleeve  606 , without departing from the scope of the disclosure. 
     The first sensor  616   a  may be communicably connected to an electronics module  618  similar to the electronics module  214  of  FIGS.  2 A- 2 D . Accordingly, the electronics module  618  may include electronic circuitry configured to determine whether the first sensor  616   a  has detected a particular wireless signal, and may also include a power supply used to power operation of one or more of the electronics module  618 , the first sensor  616   a , and the first frac actuator  614   a.    
     In embodiments where the first sensor  616   a  is a magnetic sensor, the electronic circuitry may be configured to determine whether the first sensor  616   a  has detected a predetermined magnetic field, a pattern or combination of magnetic fields, or another magnetic property of a magnetic projectile  620  introduced into the central flow passage  404 . The magnetic projectile  620  may be the same as or similar to the magnetic projectile  215  of  FIGS.  2 A and  4 A  and, therefore, may comprise a ball, a dart, a plug, a fluid, a gel, a pill or slurry of magnetic particles, or any other device or substance that exhibits a magnetic property detectable by the first sensor  616   a . The electronics module  618  may also include a non-volatile memory having a database programmed with a predetermined magnetic field(s) or other magnetic properties for comparison against magnetic fields/properties exhibited by the magnetic projectile  620  and detected by the first sensor  616   a.    
     In embodiments where the first sensor  616   a  is a pressure sensor, a temperature sensor, or an acoustic sensor, actuation of the first frac actuator  614   a  may be triggered and otherwise undertaken as generally described above with reference to operation of the sensor  212  of  FIG.  2 A  and, therefore, will not be described again. 
       FIGS.  6 B and  6 C  are enlarged cross-sectional side views of the first and second frac actuators  614   a,b , respectively, as indicated by the dashed boxes of  FIG.  6 A . Similar to the actuators discussed above, the first and second frac actuators  614   a,b  can each comprise any type of actuator (e.g., electrical, hydraulic, mechanical, explosive, chemical, a combination thereof, etc.) used to advance a piercing member towards a pressure barrier upon actuation. In  FIG.  6 B , for example, the first frac actuator  614   a  includes a piercing member  622  operable to pierce a pressure barrier  624  that initially separates a first chamber  626   a  and a second chamber  626   b  each defined in the base pipe  602 . When the first sensor  616   a  detects the predetermined wireless signal, a command signal may be sent to the first frac actuator  614   a  to pierce the pressure barrier  624  with the piercing member  622 , which allows a support fluid (e.g., oil) to flow from the first chamber  626   a  to the second chamber  626   b  and generate a pressure differential across the frac sleeve  606 . The generated pressure differential urges the frac sleeve  606  to move (displace) toward the open position (i.e., to the right in  FIGS.  6 A and  6 B ). 
     In  FIG.  6 C , the second frac actuator  614   b  also includes a piercing member  628  operable to pierce a pressure barrier  630  that initially separates a third chamber  626   c  and a fourth chamber  626   d  each defined in the base pipe  602 . In some embodiments, the second frac actuator  614   b  may be actuated when a second sensor  616   b  detects a predetermined wireless signal. The second sensor  616   b  may be similar to the first sensor  616   a  and, therefore, may comprise at least one of a magnetic sensor, an antenna, a pressure sensor, a temperature sensor, an acoustic sensor, a vibration sensor, a strain sensor, an accelerometer, a flow meter, or any combination thereof. Moreover, the second sensor  616   b  may be communicably coupled to an electronics module (not shown) associated with the second frac actuator  614   b.    
     In other embodiments, however, the second frac actuator  614   b  may be communicably coupled to the electronics module  618  ( FIGS.  6 A and  6 B ) of the first frac actuator  614   a  ( FIGS.  6 A and  6 B ) and may operate based on a time delay. More specifically, the electronic circuitry of the electronics module  618  may include a timer that may be triggered (started) upon detection of the predetermined wireless signal used to actuate the first frac actuator  614   a . The timer may be programmed with a predetermined time period for actuating the second frac actuator  614   b  and, upon expiration of the predetermined time period, the electronics module  618  may send a command signal to actuate (operate) the second frac actuator  614   b . The predetermined time period may be programmed to provide sufficient time to accomplish the hydraulic fracturing operations. For example, the predetermined time period may be about 6 hours, about 12 hours, about 24 hours, about 48 hours, more than 48 hours, or any time range falling therebetween. When the predetermined time period expires, the piercing member  628  is actuated to pierce the pressure barrier  630 , and a support fluid (e.g., oil) flows from the third chamber  626   c  to the fourth chamber  626   d , which generates a pressure differential across the frac sleeve  606 . The generated pressure differential urges the frac sleeve  606  to move (displace) uphole (i.e., to the left in  FIGS.  6  and  6 B ) and thereby back to the closed position. 
     Operation of the fracturing assembly  118  will now be provided with reference to  FIGS.  6 A,  6 D, and  6 E , which depict progressive views of the fracturing assembly  118  during example operation. In  FIG.  6 A , the fracturing assembly  118  is shown in the closed position, where the frac sleeve  606  occludes the injection ports  608  and thereby prevents fluid communication between the annulus  122  and the central flow passage  604 . Once the predetermined wireless signal is detected by the first sensor  616   a , however, the first frac actuator  614   a  may be triggered to move the frac sleeve  606  toward the open position (i.e., to the right in  FIG.  6 A ). 
     In some embodiments, as illustrated, the fracturing assembly  118  may further include an isolation device  632  positioned within the central flow passage  604  and used to isolate the fracturing assembly  118  from downhole portions of the completion section  500  ( FIG.  5   ). In the illustrated embodiment, the isolation device  632  is in the form of a collapsible sand trap or diverter coupled to the distal end of the frac sleeve  606 . The sand diverter is depicted in  FIG.  6 A  in an open position that allows fluid communication through the central flow passage  604 . Upon moving the frac sleeve  606  to the closed position, however, the sand diverter may be configured to collapse radially and at least partially seal the central flow passage  606 , as described below. 
     In  FIG.  6 D , the first frac actuator  614   a  is shown actuated, as described above, and the resulting pressure differential across the frac sleeve  606  has moved the frac sleeve  606  to the open position where the injection ports  608  are exposed via the frac ports  610  defined in the frac sleeve  606 . In the illustrated embodiment, moving the frac sleeve  606  to the open position moves the lower sleeve section  612   b  while the upper sleeve section  612   a  remains relatively stationary. In other embodiments, however, the frac sleeve  606  may comprise a monolithic structure that moves as a unitary sleeve construction, without departing from the scope of the disclosure. 
     Moving the frac sleeve  606  to the open position may also result in full or partial isolation of the central flow passage  604  below the injection ports  608  as the isolation device  632  collapses to its closed position. As indicated above, the isolation device  632  may comprise a sand diverter. As the frac sleeve  606  moves to the right in  FIG.  6 D  and toward the open position, the sand diverter will eventually engage a radial shoulder  634  configured to deflect and collapse the sand diverter. In some embodiments, the sand diverter may provide a seal within the central flow passage  604 . In other embodiments, however, the sand diverter may simply prevent passage of particulate matter. The sand diverter may prove advantageous in vertical wells, for example, where sand, proppant, and gravel particulates from a gravel slurry or fracturing fluid might migrate downhole past the fracturing assembly  118  during a hydraulic fracturing operation. The sand diverter may serve to prevent migration of such particulate matter. 
     With the frac sleeve  606  in the open position, a fluid (e.g., a fracturing fluid, a gravel slurry, etc.) may then be flowed to the fracturing assembly  118  and into the central flow passage  604  at an elevated pressure to be injected into the annulus  122  via the exposed injection ports  608 . 
     After hydraulic fracturing operations have finished, it may be desired to move the frac sleeve  606  back to the closed position in preparation for production operations undertaken by the production assembly  120  ( FIG.  5   ) or in preparation for fracturing operations of another zone in the wellbore. To accomplish this, the second frac actuator  614   b  may be actuated as generally described above. In some embodiments, as discussed above, actuation of the second frac actuator  614   b  may be time delayed following detection of the first wireless signal by the first sensor  612   a . In other embodiments, actuation of the second frac actuator  614   b  may be triggered following detection of a second or additional wireless signal detected by the second sensor  616   b . In yet other embodiments, actuation of the second frac actuator  614   b  may be triggered following detection of the second wireless signal detected by the second sensor  616   b  and after a predetermined time delay sufficient to allow the fracturing operation to conclude. 
     In  FIG.  6 E , the frac sleeve  606  is shown moved back to the closed position following actuation of the second frac actuator  614   b , as generally described above. In the illustrated embodiment, moving the frac sleeve  606  to the closed position first moves the upper sleeve section  612   a , which eventually engages a portion of the lower sleeve section  612   b  at a radial shoulder  636  and thereafter pulls the lower sleeve section  612   b  as well. Again, in other embodiments, the frac sleeve  606  may comprise a monolithic structure that moves as a unitary sleeve construction, without departing from the scope of the disclosure. 
     As the frac sleeve  606  moves back to the closed position, the isolation device  632  moves out of engagement with the radial shoulder  634  and allows the isolation device  632  to radially expand once again to the open position. Radial expansion of the isolation device  632  may be facilitated through one or more torsion springs associated with the isolation device  632 . In other embodiments, however, the isolation device  232  may alternatively be made of a degradable material (e.g., any of the degradable materials mentioned above) that allows the isolation device  232  to dissolve over time and thereby clear the central flow passage  604  for subsequent fluid flow through the fracturing assembly  118 . 
       FIG.  7 A  is a partial cross-sectional side view of the production assembly  120  of  FIG.  5   , according to one or more embodiments. As mentioned above, the production assembly  120  may be used to produce fluids from the annulus  122  and originating from the surrounding subterranean formation  110  ( FIG.  1   ). The production assembly  120  is depicted as including a base pipe  702  that defines a central flow passage  704  and one or more production ports  706  that facilitate fluid communication between the central flow passage  704  and the annulus  122 . The base pipe  702  may be the same as or an axial extension of the base pipe  602  of the fracturing assembly  118  of  FIGS.  6 A- 6 E . Accordingly, the central flow passage  704  may fluidly communicate with the central flow passage  604  ( FIGS.  2 A- 2 E ) of the fracturing assembly  118  and any fluids drawn into the base pipe  702  may be conveyed into the work string  112  ( FIG.  1   ) and transported to a surface location for collection. 
     One of the filtration devices  502  of  FIG.  5    is depicted in  FIG.  7 A  as arranged about the base pipe  702 . The filtration device  502  serves as a filter medium designed to allow fluids derived from the surrounding formation  110  ( FIG.  1   ) to flow therethrough but substantially prevent the influx of particulate matter of a predetermined size. As illustrated, the filtration device  502  may be radially offset a short distance from the base pipe  702  and thereby define a production annulus therebetween. 
     The production assembly  120  further includes a production sleeve  708  positioned for longitudinal movement within the central flow passage  704 . The production ports  706  (one shown) are blocked (occluded) when the production sleeve  708  is in a first or “closed” position, thereby preventing fluid communication between the annulus  122  and the central flow passage  704 . The production sleeve  708 , however, is actuatable to move (i.e., displace) to a second or “open” position where the production ports  706  are exposed via one or more influx ports  710  defined in the production sleeve  708 . 
     To move the production sleeve  708  to the open position, a production actuator  712  is triggered based on a wireless signal. In some embodiments, the wireless signal may be the same wireless signal used to actuate the first frac actuator  614   a  of  FIGS.  6 A- 6 E , and actuation of the production actuator  712  may be based on a time delay sufficient to allow the hydraulic fracturing operations to terminate. In such embodiments, the production actuator  712  may be communicably coupled to the electronics module  618  ( FIGS.  6 A and  6 B ). In other embodiments, however, the wireless signal may comprise a second or additional wireless signal received or otherwise detected by a production sensor  714 . The production sensor  714  may be similar to the sensor  212  of  FIG.  2 A  and, therefore, may comprise at least one of a magnetic sensor, an antenna, a pressure sensor, a temperature sensor, an acoustic sensor, a vibration sensor, a strain sensor, an accelerometer, a flow meter, or any combination thereof. While the production sensor  714  is shown located downhole from the production sleeve  708 , the production sensor  714  could alternatively be located uphole from the production sleeve  708 , without departing from the scope of the disclosure. 
     The production sensor  714  may be communicably connected to an electronics module  716  similar to the electronics module  214  of  FIGS.  2 A- 2 D . Accordingly, the electronics module  716  may include electronic circuitry configured to determine whether the production sensor  714  has detected a particular wireless signal, and may also include a power supply used to power operation of one or more of the electronics module  716 , the production sensor  714 , and the production actuator  712 . 
     In embodiments where the production sensor  714  is a magnetic sensor, the electronic circuitry may be configured to determine whether the production sensor  714  has detected a predetermined magnetic field, a pattern or combination of magnetic fields, or another magnetic property of a magnetic projectile  718  introduced into the central flow passage  704 . The magnetic projectile  718  may be the same as or similar to the magnetic projectile  620  of  FIG.  6 A  and, therefore will not be described again. The electronics module  716  may also include a non-volatile memory having a database programmed with a predetermined magnetic field(s) or other magnetic properties for comparison against magnetic fields/properties exhibited by the magnetic projectile  718  and detected by the production sensor  714 . 
     In embodiments where the production sensor  714  is a pressure sensor, a temperature sensor, or an acoustic sensor, actuation of the production actuator  712  may be triggered and otherwise undertaken as generally described above with reference to operation of the sensor  212  of  FIG.  2 A  and, therefore, will not be described again. 
     If the electronics module  716  determines that the production sensor  714  has detected a predetermined wireless signal, the electronic circuitry triggers actuation of the production actuator  712  to cause the production sleeve  708  to move to the open position and thereby expose the production ports  706 . 
       FIG.  7 B  is an enlarged cross-sectional side view of the production actuator  712 , according to one or more embodiments. As illustrated, the production actuator  712  includes a piercing member  720  configured to pierce a pressure barrier  722  that initially separates a first chamber  724   a  and a second chamber  724   b  defined by the base pipe  702 . When the production sensor  714  detects the predetermined wireless signal (or when a command signal is sent to the production actuator  712  from the electronics module  618  of  FIGS.  6 A and  6 B ), the production actuator  712  is actuated to penetrate the pressure barrier  722  with the piercing member  720 . Penetrating the pressure barrier  722  allows a support fluid (e.g., oil) to flow from the first chamber  724   a  to the second chamber  724   b , which generates a pressure differential across the production sleeve  708 , and the generated pressure differential urges the production sleeve  708  to move (displace) toward the open position. 
       FIG.  7 C  is a cross-sectional side view of the production assembly  120  with the production sleeve  708  moved to the open position. The production actuator  712  is shown actuated in  FIG.  7 C  and the production sleeve  708  has moved within the central flow passage  704  to the open position where the influx ports  710  align with the production ports  706 . In the open position, fluids from the annulus  122  may be drawn through the filtration device  502  and into the production annulus until locating the production ports  706 , which allow the fluid to enter the central flow passage  704  via the influx ports  710  for production to the well surface. 
       FIGS.  8 A and  8 B  are cross-sectional side views of an alternate embodiment of the fracturing assembly  118  of  FIGS.  6 A- 6 E . Similar to the embodiment of  FIGS.  6 A- 6 E , the fracturing assembly  118  includes the frac sleeve  606 , the first and second frac actuators  614   a,b , and at least the first sensor  616   a  (alternately including also the second sensor  616   b ). Unlike the embodiment of  FIGS.  6 A- 6 E , however, the fracturing assembly  118  may further include an isolation device  802  in the form of a flapper or flapper valve. The isolation device  802  is positioned within the central flow passage  604  and used to isolate the fracturing assembly  118  from downhole portions of the completion section  500  ( FIG.  5   ). In some embodiments, the isolation device  802  may be coupled to the distal end of the frac sleeve  606  at a pivot point  804 , such as a torsion spring. In other embodiments, however, the isolation device  802  may be coupled to or otherwise carried by the base pipe  602 , without departing from the scope of the disclosure. 
     In  FIG.  8 A , the isolation device  802  is depicted in an open position that allows fluid communication through the central flow passage  604 . Upon moving the frac sleeve  606  to the closed position, however, the flapper isolation device  802  may be configured to pivot at the pivot point  804  to a closed position and at least partially seal the central flow passage  606 . 
     In  FIG.  8 B , the frac sleeve  606  has moved to the open position where the injection ports  608  are exposed via the frac ports  610  defined in the frac sleeve  606 . Moving the frac sleeve  606  to the open position also results in full or partial isolation of the central flow passage  604  below the injection ports  608  as the isolation device  802  pivots to the closed position. More particularly, as the frac sleeve  606  moves to the right in  FIG.  8 D  and toward the open position, the distal end of the flapper isolation device  802  will eventually engage the radial shoulder  634 , which deflects the flapper to its closed position. Upon moving the frac sleeve  606  back to the closed position, as described above, the flapper isolation device  802  may be configured to pivot back to the open position. In such embodiments, the torsion spring at the pivot point  804  may provide the necessary force required to pivot the isolation device  802  to the open position. 
     Embodiments are also contemplated herein where the isolation device  802  (in any form) is entirely omitted from the fracturing assembly  118 . In such embodiments, the fracturing and production assemblies  118 ,  120  may operate as generally described herein, an hydraulic fracturing at the fracturing assembly  118  may be undertaken since the remaining fracturing assemblies in the completion string  114  ( FIG.  1   ) will be closed and the distal end of the completion string  114  will also be closed. Consequently, the hydraulic pressure required for the fracturing operation can occur without the need for an isolation device  802  (in any form) used to isolate the fracturing assembly  118  from downhole portions of the completion string  114 . In such embodiments, a well operator may be able to fracture and produce desired portions of a surrounding subterranean formation  110  ( FIG.  1   ) by selectively actuating desired fracturing and completion assemblies  118 ,  120 . 
     Embodiments are also contemplated herein where an intervention or shifting tool may be used to manually (physically) shift one or both of the frac and production sleeves between open and closed positions. This may be required in the event an associated actuation device fails or is otherwise unable to properly actuate the frac and production sleeves, such as when debris or other downhole obstructions prevent proper actuation. In such embodiments, the frac and production sleeves described herein will have corresponding shifting profiles configured to receive a profile of the shifting tool. Once the profiles mate, axial loads may be applied on the frac and production sleeves to move between the open and closed positions. 
     It is noted that the frac and production actuators described herein are not limited to using piercing members configured to pierce or penetrate a pressure barrier. Rather, it is also contemplated herein to replace the described piercing members with a valve. In such embodiments, the valve may include a rod similar to the piercing members, but including one or more seals (e.g., O-rings) disposed about the rod. The rod may be extended into a conduit to generate a seal between adjacent fluid chambers. To enable fluid communication between the adjacent fluid chambers, and thereby actuate a frac sleeve or a production sleeve, the frac or production actuator may be actuated. Alternatively, the force required to push the rod out of the conduit (i.e., retract it) may be provided by fluid pressure pushing on the end of the rod. 
     Computer hardware used to implement the various illustrative blocks, modules, elements, components, methods, and algorithms described herein can include a processor configured to execute one or more sequences of instructions, programming stances, or code stored on a non-transitory, computer-readable medium. The processor can be, for example, a general purpose microprocessor, a microcontroller, a digital signal processor, an application specific integrated circuit, a field programmable gate array, a programmable logic device, a controller, a state machine, a gated logic, discrete hardware components, an artificial neural network, or any like suitable entity that can perform calculations or other manipulations of data. In some embodiments, computer hardware can further include elements such as, for example, a memory (e.g., random access memory (RAM), flash memory, read only memory (ROM), programmable read only memory (PROM), erasable read only memory (EPROM)), registers, hard disks, removable disks, CD-ROMS, DVDs, or any other like suitable storage device or medium. 
     Executable sequences described herein can be implemented with one or more sequences of code contained in a memory. In some embodiments, such code can be read into the memory from another machine-readable medium. Execution of the sequences of instructions contained in the memory can cause a processor to perform the process steps described herein. One or more processors in a multi-processing arrangement can also be employed to execute instruction sequences in the memory. In addition, hard-wired circuitry can be used in place of or in combination with software instructions to implement various embodiments described herein. Thus, the present embodiments are not limited to any specific combination of hardware and/or software. 
     As used herein, a machine-readable medium will refer to any medium that directly or indirectly provides instructions to a processor for execution. A machine-readable medium can take on many forms including, for example, non-volatile media, volatile media, and transmission media. Non-volatile media can include, for example, optical and magnetic disks. Volatile media can include, for example, dynamic memory. Transmission media can include, for example, coaxial cables, wire, fiber optics, and wires that form a bus. Common forms of machine-readable media can include, for example, floppy disks, flexible disks, hard disks, magnetic tapes, other like magnetic media, CD-ROMs, DVDs, other like optical media, punch cards, paper tapes and like physical media with patterned holes, RAM, ROM, PROM, EPROM, and flash EPROM. 
     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 elements 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.