Patent Grant
11655689
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.
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.
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.
A work string 112 is extended into the wellbore 102 from a surface location, such as the Earth'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
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
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.
In
The fracturing assembly 200 may further include a fracture sleeve 206a (alternately referred to as a “frac” sleeve) and a closure sleeve 206b, 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 206a 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 206a 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 206a to the open position, a first frac actuator 210a 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 206a, the sensor 212 could alternatively be located uphole from the frac sleeve 206a, 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 (
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 210a.
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 210a. 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 210a, 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 210a to cause the frac sleeve 206a to move towards the open position to expose the injection ports 208.
In the illustrated example, the first frac actuator 210a includes a piercing member 216 operable to pierce a pressure barrier 218 that initially separates a first chamber 220a and a second chamber 220b each defined in the base pipe 202. The first frac actuator 210a 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 220a to the second chamber 220b, which generates a pressure differential across the frac sleeve 206a. The generated pressure differential urges the frac sleeve 206a to move (displace) toward the open position (i.e., to the right in
In some embodiments, the pressure differential generated by piercing the pressure barrier 218 may be sufficient to fully displace the frac sleeve 206a to its open position. In other embodiments, however, it may be required to pressurize the central flow passage 204 to move the frac sleeve 206a fully to its open position, as described below.
In
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 206a. 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 206a is prevented by the baffle receiving sleeve 228, which is secured to the base pipe 202 at the shear member 230.
In
In embodiments where the differential pressure acting on the frac sleeve 206a 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 206a generated between the first and second chambers 220a,b may urge the frac sleeve 206a 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 206a to the fully open position.
In
After hydraulic fracturing operations have finished, it may be desired to move the frac sleeve 206a 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 210b included in the fracturing assembly 200 may be actuated or otherwise operated to move (displace) the closure sleeve 206b and thereby move the frac sleeve 206a back to the closed position. Similar to the first frac actuator 210a, in the illustrated example, the second frac actuator 210b includes a piercing member 236 configured to pierce a pressure barrier 238 that initially separates a third chamber 210c and a fourth chamber 210d each defined in the base pipe 202.
In some embodiments, actuation of the second frac actuator 210b to move the closure sleeve 206b 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 210a. 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 206b and, upon expiration of the predetermined time period, the electronics module 214 may actuate (operate) the second frac actuator 210b. 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 210c to the fourth chamber 210d, which generates a pressure differential across the closure sleeve 206b. The generated pressure differential urges the closure sleeve 206b to move (displace) uphole (i.e., to the left in
In other embodiments, however, a second or additional wireless signal may be detected by the sensor 212 to actuate the second frac actuator 210b. In such embodiments, the sensor 212 may be positioned uphole from the frac and closure sleeves 206a,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 206a,b to detect the additional wireless signal.
In
In other embodiments, the retractable baffle 226 may not be radially expanded as the closure sleeve 206b engages the retractable baffle 226 and moves the frac sleeve 206a 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).
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
The first frac actuator 210a (
In
The filtration device 408 serves as a filter medium designed to allow fluids derived from the formation 110 (
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 (
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
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 210a. Similar to the electronics module 214 of
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 210a,b of
In
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
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 602200 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 612a and a lower sleeve section 612b. As illustrated, the frac ports 610 are defined in the lower sleeve section 612b. Moreover, as described below, the upper and lower sleeve sections 612a,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 614a and a second frac actuator 614b. To move the frac sleeve 606 to the open position, the first frac actuator 614a is triggered, and to move the frac sleeve 606 back to the closed position, the second frac actuator 614b is triggered. The first frac actuator 614a may be triggered based on a wireless signal detected by a first sensor 616a coupled to the wall of the base pipe 602. The first sensor 616a may be similar to the sensor 212 of
The first sensor 616a may be communicably connected to an electronics module 618 similar to the electronics module 214 of
In embodiments where the first sensor 616a is a magnetic sensor, the electronic circuitry may be configured to determine whether the first sensor 616a 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
In embodiments where the first sensor 616a is a pressure sensor, a temperature sensor, or an acoustic sensor, actuation of the first frac actuator 614a may be triggered and otherwise undertaken as generally described above with reference to operation of the sensor 212 of
In
In other embodiments, however, the second frac actuator 614b may be communicably coupled to the electronics module 618 (
Operation of the fracturing assembly 118 will now be provided with reference to
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 (
In
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
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 (
In
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.
One of the filtration devices 502 of
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 614a of
The production sensor 714 may be communicably connected to an electronics module 716 similar to the electronics module 214 of
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
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
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.
In
In
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 (
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.
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.
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| Entry |
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|---|---|---|---|
| 20210254433 A1 | Aug 2021 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 16335242 | US | |
| Child | 17307966 | US |
