US20250320783A1

US20250320783A1 - Selectable hole trimmer and methods thereof

Info

Publication number: US20250320783A1
Application number: US18/635,841
Authority: US
Inventors: Steven R. Radford; Carl E. Poteet, III
Original assignee: Black Diamond Oilfield Rentals LLC
Current assignee: Black Diamond Oilfield Rentals LLC
Priority date: 2024-04-15
Filing date: 2024-04-15
Publication date: 2025-10-16

Abstract

A selectable hole trimmer includes a body, sliding sleeve, orifice sleeve, and a latch mechanism. The body has upstream and downstream ends, a drilling fluid volume, and a body groove. The sliding sleeve is slidably disposed within the body to provide pressure to a pressurized volume. The orifice sleeve is slidably disposed within the sliding sleeve to engage and disengage the latch mechanism from the body groove. An actuator may provide the pressure to a selectable hole cutter to move the cutter between a retracted and extended state. The orifice sleeve receives a first fluid flow first rate above an activation threshold that moves the orifice sleeve to a downstream position to disengage the latch mechanism from the body groove. The orifice sleeve receives a second fluid flow rate below the activation threshold that moves the orifice sleeve to an upstream position to engage the latch mechanism and body groove.

Description

FIELD

The present invention relates generally to a device for use in downhole drilling.

BACKGROUND

While performing drilling operations in an oil and gas well, a drill string rotates a drill bit at an end of the drill string and circulates fluids, such as drilling mud, through the drill string and the drill bit. The fluids may lubricate, cool, and clean the drill bit. The fluids may also control downhole pressure, stabilize the wall of the borehole, and remove drill bit cuttings from the bottom of the hole. Very often, the fluids are engineered with different chemical make-ups to suit specific well applications. Sometimes controlling certain physical or operation properties of the fluids, such as the flow rate through the drill bit, may be as important as controlling the chemical make-ups.
Sometimes operations of downhole tools may be controlled using various sensors and controllers in a closed control loop. For example, U.S. Pat. No. 9,879,518 discloses an intelligent reamer for drilling using rotation sensor, fluid operation sensor, and a control scheme based on the measured rotational rate of the drill string (e.g., an rpm protocol).
Conventionally, a specialized downhole tool (i.e., DSI PBL® sub) may be used to bypass fluids from the drill bit. Such specialized downhole tool may achieve the bypass function by dropping a metal or polymer, hard or malleable ball into the drill string from the derrick floor. The ball then travels downhole and eventually seats into the bypass sub, sealing against the passage downhole. After sealing, the drilling fluids are forced toward lateral vent holes, thus bypassing the drill bit. To terminate this bypass, additional small balls are pumped down the drill string. The smaller balls will block the lateral vent holes. As the lateral vent holes are closed, the malleable metal or polymer ball are deformed and pushed through its seat and into a collector below, thus restoring the flow path to the drill bit.
Such downhole tool (i.e., DSI PBL® sub) often takes a long time for the various balls (either to cause the bypass or to restore the flow) to travel through the drill string and be seated on the seal. In some instances, pumping at 600 gpm down a 10,000 ft drill pipe of 5½-inch diameter would take approximately 12-15 minutes. Such downhole tool (i.e., DSI PBL® sub) also has a limited number of bypass/restore cycles before tool replacement. In some instances, because the collector becomes fully filled, only five sets of malleable metal or polymer ball may be inserted to cause bypasses before the whole downhole tool (i.e., DSI PBL® sub) must be replaced before further bypass operations. Furthermore, dropping the balls into the drill string to be pumped down to the bypass sub is typically a manual operation.
Another specialized tool (i.e., a fixed blade reamer) may be used to slightly enlarge a hole. The fixed blade reamer has a larger diameter than the rest of the drill string. Due to this larger diameter, the fixed blade reamer creates a high drag when sliding and not rotating in directional drilling. This high drag is problematic to the directional drilling process.
Accordingly, a downhole device (e.g., a selectable hole trimmer) is needed that does not create a high drag when sliding and not rotating in directional drilling.

STATEMENT REGARDING PRIOR DISCLOSURES BY THE INVENTOR OR A JOINT INVENTOR

Drilling Environment Implementing the Downhole Device

FIG. 1 illustrates an exemplary drilling environment 100 for implementing the disclosed downhole device. As shown, the exemplary drilling environment 100 includes a drilling rig having a drilling fluid (e.g., drilling mud) circulation system summarized below. The drilling environment 100 provides a conceptual understanding for the placement of the disclosed downhole device to be discussed and may include other components not shown in FIG. 1 . The drilling environment 100 includes a mud reservoir 108 on the ground 102. The mud reservoir 108 receives return drilling mud caught in the mud pit 104 and supplies the mud pump 106 drilling mud to send to the mud feed line 116. The mud feed line 116 feeds drilling mud into the drill string 120 through the swivel or top drive 125. The drilling mud travels along the drill string 120 from the Kelly drive 140 down to and exits the drill bit 132. The drilling mud carries away heat and debris from the drill bit 132 and returns it to the ground 102 via the annulus 122. The annulus 122 is the clearance space created between the outer diameter of the drill string 120 and the side surface 130 of the drilled hole created by the drill bit 132. The returning mud 124 flows from the drill bit 132 in the annulus 122 upward. After returning to the ground 102, the returning mud 124 travels in the mud return line 114 to return to the mud pits 104, passing by the shale shaker 112 to remove the drill debris.
FIG. 2 shows a local cross-sectional side view of a conceptual operation of the downhole device 210 in the exemplary drilling environment 100 of FIG. 1 . The downhole device 210 may be positioned at a desired location between the drill bit 132 and the ground 102. Other components or downhole devices may be installed or positioned between the downhole device 210 and the drill bit 132. When the downhole device 210 is actuated, a portion 220 of the drilling mud may bypass the drill bit 132 and flows into the annulus 120 while the returning mud 124 may include the remaining portion of the drilling mud. Details of the structure of the downhole device 210 in different embodiments are illustrated in FIGS. 3-6 and discussed below.

Exemplary Downhole Devices

FIG. 3 shows a cross-sectional side view of a first exemplary embodiment of the downhole device 210. As shown, the downhole device 210 includes a body as part of the drill string 120, a sleeve 310 sealingly slidable inside the body 120. See e.g., FIG. 14A: 310. The sleeve 310 may include at least one port 314 alignable with a corresponding bypass outlet 312 of the body 120. See e.g., FIG. 14A: 310, 312, 313 & 314. The bypass outlet 312 may include an erosion resistant nozzle 313. Id. The downhole device 210 further includes a resilient member 320 (e.g., a spring) biasing the sleeve 310 against the body 120. See e.g., FIG. 14A: 310 & 320. The downhole device 210 further includes a three-way valve with an actuator 340 that is configured to provide a pressure to the sleeve 310. See e.g., FIG. 14A: 310 & 340. The actuator 340 can actuate the sleeve 310 to move relative to the body 120, such as to align the bypass outlet 312 with the port 314. See e.g., FIG. 14A: 310, 312, 314 & 340. The downhole device 210 also includes a controller (e.g., the controller electronics 620 shown in FIG. 6 , or implemented as the computer device 700 of FIG. 7 as discussed below) configured to operate the actuator 340 in response to a change of a monitored operation condition. Id.
In some embodiments, the downhole device 210 would use information, measurements, and other received signals (electric or mechanical, such as pressure signals) to actuate the actuator 340. See e.g., FIG. 14A: 340. For example, the downhole device 210 may sense or measure the rotation rate in revolutions per minute (“rpm”), a flow rate of drilling mud fluid (e.g., in GPM), weight or pressure signals (e.g., related to well depth, length of drill string 120, and installed components) and control the actuator 340 in response to the measured signals. Id.
Turning to FIG. 3 , the downhole device 210 may have a neutral position where the sleeve 310 is biased away from the bypass outlet 312. See e.g., FIG. 14A: 310 & 312. As a result, the sleeve 310 forms a volume 322 with the body 120. Id. Before actuation, the drill string inlet 334 communicates fluid or its pressure (or both) to the volume inlet 336. See e.g., FIG. 14A: 334. Since the drill string inlet 334 takes drilling mud from the bore of the drill string 120 and is fluidly connected to the volume inlet 336 via the three-way valve actuator 340, the sliding sleeve volume 322 would have the same fluid pressure as that of the drill string 120. See e.g., FIG. 14A: 334 & 340. This pressure of the sliding sleeve volume 322 would be equal to the pressure outside of the sleeve 310 and therefore the sleeve 310 is subject only to the spring 320 and in the neutral position. See e.g., FIG. 14A: 310 & 320.
In the illustrated embodiment, a lock ring 330 may further be used to define the neutral position, for example, to allow the spring 320 to statically push the sleeve 310 against the lock ring 330. See e.g., FIG. 14A: 310 & 320. The lock ring 330, however, may be optional if an equivalent form of stopping mechanism, such as a catch key or the like formed in the sleeve 310 is employed. Id. Different configurations of providing the neutral position of the sleeve 310 under similar principle are possible and not exhaustively enumerated here. Id.
During operation, when the downhole device 210 is to shift flow paths to bypass the drill bit 132, a signal may be sent via rpm, for example, to the downhole device 210. The signal may be measured and/or processed in a microprocessor in the downhole device 210. The processor may then send a signal to the three-way valve and actuator 340 to change the pressure in the volume inlet 336. See e.g., FIG. 14A: 340. For example, the actuator 340 may increase or decrease the pressure in the volume 322. Id.
In some embodiments, the actuator 340 may connect the volume inlet 336 to the annulus outlet 332 and equalize the pressures in the sliding sleeve volume 322 to the annulus 122. See e.g., FIG. 14A: 340. Because the pressure in the annulus 122 is lower than the pressure in the drill string 120 (often by 2000 psi), the pressure applied to external surfaces of the sleeve 310 (outside the volume 322) becomes greater than the pressure applied to inner surfaces of the sleeve 310 (surfaces forming the volume 322). Id. The collective effect of this pressure difference would cause the sleeve 310 to compress the spring 320 and move toward the bypass outlet 312. See e.g., FIG. 14A: 310, 312 & 320.
The spring 320 may have a desired elasticity such that the pressure difference between the drill string pressure and the annulus pressure may fully align the bypass port 314 to the bypass outlet 312. See e.g., FIG. 14A: 312, 314 & 320. At least a portion of the drilling mud may bypass the drill bit 140 when the bypass port 314 is at least partially aligned with the bypass outlet 312. See e.g., FIG. 14A: 312 & 314. When the downhole device 210 sends a different rpm signal or stops sending a triggering signal, the actuator 340 (or its controller 620, 700) may shift the sleeve 310 back to the neutral position, by reconnecting the drill string inlet 334 to the volume inlet 336. See e.g., FIG. 14A: 310 & 334. As such, the operation of the sleeve 310 need not be externally powered, and the operation may fully use the existing pressure differences between the drill string 120 and the annulus 122. Id. The control and actuation of the three-way valve actuator 340 may be electrically powered like other downhole tools. See e.g., FIG. 14A: 340.
In some embodiments, the spring 320 may be a coil spring providing a biasing force corresponding to a threshold trigger pressure, i.e., a pressure balancing the force applied by the spring 320 to the sleeve 310. See e.g., FIG. 14A: 310 & 320. Once the pressure difference exceeds the threshold trigger pressure, the sleeve 310 may be moved toward the bypass outlet 312. See e.g., FIG. 14A: 310 & 312.
In some embodiments, the actuator 340 may be controlled in response to other signals besides rpm signals, such as an internal drill string pressure variation measured in a pressure transducer. See e.g., FIG. 14A: 340. For example, the internal drill string pressure variation satisfies a trigger condition for initiating a bypass of the drilling fluids. Sensors for measuring pressures, rpm, and other aspect of the downhole device 210 or the drill string 120 may be installed in various locations along the drill string 120, or may be onboard other tools of the drill string 120. Controller, power supply and other electronics are discussed in relation to FIG. 6 below.
FIG. 4 shows a cross-sectional side view of a second exemplary embodiment of the downhole device 210. Similar to the previous embodiment, the downhole device 210 includes a body as part of the drill string 120, a sleeve 410 sealingly slidable inside the body 120. See e.g., FIG. 14A: 410. The sleeve 410 may include at least one port 414 alignable with a corresponding bypass outlet 412 of the body 120. See e.g., FIG. 14A: 410 & 414. The bypass outlet 412 may include an erosion resistant nozzle 413. The downhole device 210 further includes a resilient member 420 (e.g., a spring) biasing the sleeve 410 against the body 120. See e.g., FIG. 14A: 410 & 420. The downhole device 210 further includes a motor driven pump 440 (herein called motor pump) that is configured to provide a pressure to the sleeve 410. See e.g., FIG. 14A: 410 & 440. The motor pump 440 can actuate the sleeve 410 to move relative to the body 120, such as to align the bypass outlet 412 with the port 414. See e.g., FIG. 14A: 410, 414 & 420.
The downhole device 210 may have a neutral position where the sleeve 410 is biased toward the bypass outlet 412 and the bypass port 414 is offset from the bypass outlet 412. See e.g., FIG. 14A: 410 & 414. The sleeve 410 is pushed by the spring 420 secured at a lock ring 430 toward the bypass outlet, forming a volume 422 with the body 120. See e.g., FIG. 14A: 410, 420 & 430. The volume 422 is connected to the motor pump 440 via a motor pump fluid line 436. See e.g., FIG. 14A: 436 & 440. In this embodiment, the pressure of the drilling fluids in the downhole device 210 bore (or the drill string 120) may communicate with an accumulator/pressure compensation vessel 442 (the “accumulator” 442). See e.g., FIG. 14A: 442. The accumulator 442 may actuate the adjacent piston to pressurize the internal oil in its oil chamber to the same pressure as that of the downhole device 210 (i.e., pressure inside the drill string 120). Id. The accumulator 442 and the motor pump 440 may both be housed in a radial housing 450 of the body 120. See e.g., FIG. 14A: 440, 442 & 450.
During operation, a microprocessor (e.g., included in the electronics 620 of FIG. 6 ) sends control signals to the motor pump 440. See e.g., FIG. 14A: 440. Upon receiving the control signals from the microprocessor, the motor pump 440 may pump pressurized oil from the accumulator 442 to the volume 422 via the motor pump fluid line 436. See e.g., FIG. 14A: 436, 440 & 442. As such, the pumped oil pressure caused by the motor pump 440 may move the sleeve 410 to align the bypass port 414 with the bypass outlet 412. See e.g., FIG. 14A: 410, 414 & 440. Because the drill string inlet 434 is hydraulically linked to the motor pump fluid line 436, the motor pump 440 needs not overcome the pressure in the drill string 120 and needs only overcome the bias force applied by the spring 420. See e.g., FIG. 14A: 420, 434, 436 & 440. When the bypass port 414 and the bypass outlet 412 are aligned, a portion of the drilling mud passing through the downhole device 210 is bypassed to the annulus 122. See e.g., FIG. 14A: 414. Whenever rpm ceased the downhole device 210 may be and is typically programmed to close the bypass path.
In some embodiments, the microprocessor sends control signals based on preprogrammed rpm protocols. When the operator decides to put the downhole device 210 to sleep and stop the bypass flow from the bore to the annulus, then a different, pre-programmed rpm protocol would be performed. Such intent may be transmitted through the drill string 120 and recognized by an accelerometer connected to the microprocessor. The resulting signal may shut off the pump and allow the spring 420 to return the sleeve 410 to the original position to seal the bypass outlet 412. See e.g., FIG. 14A: 410 & 420.
In some embodiments, the actuation of the sleeve 410 by the motor pump 440 may include linear sliding motion, spiral sliding motion, rotational motion, or a combination thereof. See e.g., FIG. 14A: 410 & 440. For example, the bypass port 414 and the bypass outlet 412 may be apart linearly or radially in different embodiments. See e.g., FIG. 14A: 414. The motor pump 440 may employ various hydraulic actuators to move the sleeve 410, not limited to the disclosed examples. See e.g., FIG. 14A: 410 & 440.
FIG. 5 shows a cross-sectional side view of a third exemplary embodiment of the downhole device 210. Similar to the previous embodiments, the downhole device 210 in this embodiment also includes a body as part of the drill string 120, a sleeve 510 sealingly slidable inside the body 120. The sleeve 510 may include at least one port 514 alignable with a corresponding bypass outlet 512 of the body 120. The bypass outlet 512 may include an erosion resistant nozzle 513. The downhole device 210 further includes a resilient member 520 (e.g., a spring) biasing the sleeve 510 against the body 120. The downhole device 210 further includes a three-way valve 540 that is configured to provide a pressure to the sleeve 510 to actuate the sleeve 510 to move relative to the body 120, such as to align (as illustrated when bypass actuation conditions are met) the bypass outlet 512 with the port 514. See e.g., FIG. 14A.
In FIG. 5 , the body 120 includes a radial housing 550 for enclosing a bore pressure oil accumulator 535, an annulus pressure oil accumulator 537, and the three-way valve 540. See e.g., FIG. 14A: 535 & 537. The bore pressure oil accumulator 535 is connected to the drill string inlet 534 that is open to the bore to receive pressure therein. Id. The bore pressure oil accumulator 535 may have mud from the drill string 120 to enter the volume 551 and apply pressure to the bore pressure oil accumulator 535. See e.g., FIG. 14A: 535 & 551. The bore pressure is communicated to the three-way valve 540 via the bore pressure oil accumulator inlet 542. Id. The annulus pressure oil accumulator 537 is connected to the annulus inlet 536 to receive pressure therein. See e.g., FIG. 14A: 537. The annulus pressure oil accumulator 537 may have mud from the annulus 122 to enter the volume 552 and apply pressure to the annulus pressure oil accumulator 537. Id. The annulus pressure is communicated to the three-way valve 540 via the annulus pressure oil accumulator inlet 544. Id.
During operation, the pressure in the bore of the downhole device 210 is higher than the pressure in the annulus 122, often by about 1000-2000 psi. The bore pressure is communicated from the drill string inlet 534 through the bore pressure oil accumulator 535 to the three-way valve 540. See e.g., FIG. 14A: 535. Similarly, the pressure of the mud in the annulus between the downhole device 210 and the side surface 130 of the drilled hole is communicated to the volume 536 and the annulus pressure oil accumulator 537. See e.g., FIG. 14A: 537. The oil from the annulus pressure oil accumulator 537 is then communicated to the three-way valve 540. Id.
The output port of the three-way valve 540 is shown as the sleeve volume inlet 538 and communicates, via the volume inlet 538, to the volume 522 between the sliding sleeve 510 and the downhole device 210's inner diameter, sealed by seals that allows for relative movement between the sleeve 510 and the body 120. See e.g., FIG. 14A.
Inside that volume 522 is also a spring 520 which forces the sleeve 510 to the left (toward top of the downhole device 210) when there is no pressure differential between the bore and the volume 522, similar to the first embodiment shown in FIG. 3 . When the three-way valve 540 relays the pressure from the drill string inlet 540 to the sleeve volume inlet 538, the sleeve 510 is positioned in a normally “closed” position. See e.g., FIG. 14A.
Whenever an rpm protocol or other prescribed signal (pressure, bit weight, etc.) is sensed by one or more accelerometers and communicated to the microprocessor (both located in another pocket in the downhole device 210 (not shown) then the valve (V) is signaled to shift to the non-closed position. The three-way valve 540 communicates the pressure of the annulus 122 via the annulus pressure oil accumulator inlet 544 to the volume inlet 538 and thus to the volume 522. See e.g., FIG. 14A. Because the annulus pressure can be said to be always lower than the internal flow in the tool, this lower pressure in the volume 522 shifts the sleeve 510 to the right as shown, aligning the bypass port 514 to the bypass outlet 512. This actuates the bypass flow and allows free flow of drilling fluids from the bore to the annulus.
When drilling mud bypass is no longer desired, then an rpm signal (or other types of signals) may be given, such as stopping the rotation entirely. The accelerometer measures such signals and the microprocessor processes the measured signals to determine a corresponding control output. The three-way valve 540 may then be controlled to shift back to the original closed position. This is achieved by communicating the bore pressure from the drill string inlet 534 to the volume 522 (which are identical pressures) and allowing the spring 520 to move the sleeve 510 to offset the bypass port 514 from the bypass outlet 512, sealing off the bypass flow. See e.g., FIG. 14A.
FIG. 6 shows a cross-sectional top view of an exemplary embodiment of the downhole device 210. The configuration shown in FIG. 6 is applicable to the previous embodiments discussed in FIGS. 3-5 . For example, the downhole device 210 may include one or more radial housing 350, 450, or 550 for containing the actuator 340, 440, or 540. The downhole device 210 may include an internal tube (e.g., the internal cylindrical surface) housing the sleeve 310, 410, or 510.
As shown, the downhole device 210 includes three radial housings, possibly equally spaced 120 degrees apart. In some embodiments, one or more, such as two, or four, or another different number of radial housings may be used instead of three. The radial housing 350, 450, or 550 may each include one or more, or all the component(s) of the bypass actuation system without preference or limitations. For example, the radial housing 350, 450, or 550 may include at least one of an oil accumulator, a motor pump, a battery 610, the actuator, the three-way valve, or motor pump 340, 440, or 540, or the controller/electronics 620, 700 as discussed above.
In some embodiments, the battery 610, the electronics 620, and the actuators 340, 440, and 540 may respectively be connected by a wire 612 and a control line 622. For example, the control line 622 may be embedded in a bored hole or holes in the body 120 around the sleeve 310, 410, or 510 to reach the corresponding radial housing 350, 450, or 550. In some embodiments, the power line 612 may connect directly with the actuator or motor pump 340, 440, or 540. In other embodiments, the power line 612 may connect directly with the electronics 620, 700. In other embodiments, the power line 612 may connect indirectly with the actuator or motor pump 340, 440, or 540 via the electronics 620, 700. Other arrangements are possible. In some implementations, wireless communication for receiving sensing signals and sending control signals may be employed between the electronics 620 and the actuator or pump 340, 440, or 540. Although the battery 610, the electronics 620, and the actuator or pump 340, 440, or 540 are shown to be separately placed in individual radial housings 350, 450, or 550, they may be reconfigured to share one or more radial housings as desired.
FIG. 7A illustrates an exemplary schematic for controlling the downhole device 210 as shown in FIGS. 3-6 . The electronics 620 may include a microprocessor, one or more accelerometers, a voltage regulator, and a pressure sensor, for example. In some embodiments, the illustrated schematic applies to FIG. 4 . For example, the electronics 620 may send control signals to a motor or actuator 710 that is operable to power the motor pump 440. Details of data acquisition and generation of the control signals may reference U.S. Pat. No. 9,879,518, specifically, FIGS. 5, 6, and 6A and the corresponding descriptions.
Upon receiving power or actuation from the actuator 710, the motor pump 440 may communicate pressurized oil from the oil reservoir or accumulator 712 to actuate the sleeve 410 to overcome the bias force by the spring 420 and to align bypass port 414 with bypass outlet 412. The mud 705 in borehole is communicated to the oil accumulator 442 that provides the pressurized oil to the oil accumulator 712. Different configurations are possible in view of the bypass method discussed below.
FIG. 7B shows an exemplary schematic of a controller 700 of the electronics 620 applicable to the downhole device 210. Referring to the drawings in general, and initially to FIGS. 7A and 7B in particular, the controller 700 is but one example of a suitable configuration for the electronics 620 and is not intended to suggest any limitation as to the scope of use or functionality of this disclosure. Neither should the controller 700 be interpreted as having any dependency or requirement relating to any one or combination of components illustrated.
Embodiments of this disclosure may be described in the general context of computer code or machine-executable instructions stored as program modules or objects and executable by one or more computing devices, such as a laptop, server, mobile device, tablet, etc. Generally, program modules including routines, programs, objects, components, data structures, etc., refer to code that perform particular tasks or implement particular abstract data types. Embodiments of this disclosure may be practiced in a variety of system configurations, including handheld devices, consumer electronics, general-purpose computers, more specialty computing devices, and the like. Embodiments of this disclosure may also be practiced in distributed computing environments where tasks may be performed by remote-processing devices that may be linked through a communications network.
With continued reference to FIG. 7B, the controller 700 of the downhole device 210 includes a bus 701 that directly or indirectly couples the following devices: memory 713, one or more processors 714, one or more presentation components 716, one or more input/output (I/O) ports 718, I/O components 720, a user interface 722 and an illustrative power supply 724 (such as the battery 610 of FIG. 6 ). The presentation components 716 and the user interface 722 may be above ground and connected to the bus 701 remotely or when the tool is located above ground for servicing. The bus 701 represents what may be one or more busses (such as an address bus, data bus, or combination thereof).
Although the various blocks of FIG. 7B are shown with lines for the sake of clarity, in reality, delineating various components is not so clear, and metaphorically, the lines would more accurately be fuzzy. For example, one may consider a presentation component such as a display device to be an I/O component. Additionally, many processors have memory. The diagram of FIG. 7B is merely illustrative of an exemplary computing device that can be used in connection with one or more embodiments of the present invention. Further, a distinction is not made between such categories as “workstation,” “server,” “laptop,” “mobile device,” etc., as all are contemplated within the scope of FIG. 7B and reference to “computing device.”
The controller 700 of the downhole device 210 typically includes a variety of computer-readable media. Computer-readable media can be any available media that may be accessed by the controller 700 and include both volatile and nonvolatile media, removable and non-removable media. By way of example, and not limitation, computer-readable media may comprise computer-storage media and communication media.
The computer-storage media includes volatile and nonvolatile, removable and non-removable media implemented in any method or technology for storage of information such as computer-readable instructions, data structures, program modules, or other data. Computer-storage media includes, but is not limited to, Random Access Memory (RAM), Read Only Memory (ROM), Electronically Erasable Programmable Read Only Memory (EEPROM), flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other holographic memory, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium that can be used to encode desired information and which can be accessed by the controller 700.
The memory 713 includes computer-storage media in the form of volatile and/or nonvolatile memory. The memory 713 may be removable, non-removable, or a combination thereof. Suitable hardware devices include solid-state memory, hard drives, optical-disc drives, etc. The controller 700 of the downhole device 210 includes one or more processors 714 that read data from various entities such as the memory 713 or the I/O components 720.
The presentation component(s) 716 present data indications to a user or other device. In an embodiment, the controller 700 outputs present data indications including separation rate, temperature, pressure and/or the like to a presentation component 716. Suitable presentation components 716 include a display device, speaker, printing component, vibrating component, and the like.
The user interface 722 allows the user to input/output information to/from the controller 700. Suitable user interfaces 722 include keyboards, key pads, touch pads, graphical touch screens, and the like. For example, the user may input a type of signal profile into the controller 700 or output a separation rate to the presentation component 716 such as a display. In some embodiments, the user interface 722 may be combined with the presentation component 716, such as a display and a graphical touch screen. In some embodiments, the user interface 722 may be a portable hand-held device. The use of such devices is well known in the art.
The one or more I/O ports 718 allow the controller 700 to be logically coupled to other devices including the accelerometers, pressure sensors, rpm sensors, and other I/O components 720, some of which may be built in. Examples of other I/O components 720 include a control terminal above the ground, the actuators 340, 440, and 540, wireless device, other sensors, and actuators in the drill string 120, and the like. During operation, for example, the I/O ports 718 enables the controller 700, via the control line 622, for example, to operate on the three-way valves 340 and 540 to alter the connection between different ports.
Any suitable controller may be used with this invention. For example, U.S. Pat. No. 9,879,518 discloses an intelligent reamer for drilling using rotation sensor, fluid operation sensor, and a control scheme based on the measured rotational rate of the drill string (e.g., an rpm protocol). The U.S. Pat. No. 9,879,518 disclosure regarding the data acquisition, sensing, signal transmission, signal processing, control, and other technical aspects in the that patent are hereby cited as background and incorporated by reference to the extent that they is not inconsistent with this invention.
FIG. 8A shows a side view of an exemplary embodiment of the downhole device 210 having carved structures 810 and 820 for regulating the annular fluid flow. FIG. 8B shows a cross-sectional side view, and FIG. 8C shows a cross-sectional top view of the same. The carved structures 810 and 820 may be slots carved on the external surface of the body 805 of the downhole device 210. The carved structure 820 is lower than the carved structure 810 when the example downhole device 210 is positioned in an erected orientation. The carved structures 810 and 820 may motivate the annular flow of the drilling fluids upward. For example, the carved structures 810 and 820 form helical profiles that when the carved structures 810 and 820 are rotated clockwise (viewing downward into the well), the fluids in the carved structures 810 and 820 would receive an upward actuation. This may be similar to a full coverage stabilizer or a spiral collar.
In some embodiments, the carved structures 810 and 820 may cause turbulence to bring the cuttings off the wall and allow the upward flow from the bit to carry them upward in the well. In some embodiments, the carved structure 810 may intersect with the bypass outlet 312, 412, or 512 to provide the helical motion of the circulated drill fluids in the annulus 122 from the outset. Although FIG. 8A illustrates the carved structures 810 and 820 to be certain helical shape, different shapes, such as the varying degrees of helical angles, may be used, as long as they form a general axial arrangement. In some embodiments, the carved structures 810 and 820 may have a substantial depth based on the wall thickness, as shown in FIG. 8B.

Alternative Exemplary Downhole Device

FIG. 10A shows a side view of an exemplary embodiment of an alternative downhole device 210 having carved structures 1010 and 1020 for regulating annular fluid flow. FIG. 10B shows a cross-sectional side view, and FIG. 10C shows a cross-sectional top view of the same. The carved structures 1010 and 1020 may be slots carved on the external surface of the body 1005 of the downhole device 210. The carved structure 1020 is lower than the carved structure 1010 when the example downhole device 210 is positioned in an erected orientation. The carved structures 1010 and 1020 may motivate the annular flow of the drilling fluids upward. For example, the carved structures 1010 and 1020 form helical profiles that when the carved structures 1010 and 1020 are rotated clockwise (viewing downward into the well), the fluids in the carved structures 1010 and 1020 would receive an upward actuation. This may be similar to a full coverage stabilizer or a spiral collar.
In some embodiments, the carved structures 1010 and 1020 may cause turbulence to bring the cuttings off the wall and allow the upward flow from the bit to carry them upward in the well. In some embodiments, the carved structure 1010 may intersect with the bypass outlet 312, 412, or 512 to provide the helical motion of the circulated drill fluids in the annulus 122 from the outset. Although FIG. 10A illustrates the carved structures 1010 and 1020 to be certain helical shape, different shapes, such as the varying degrees of helical angles, may be used, as long as they form a general axial arrangement. In some embodiments, the carved structures 1010 and 1020 may have a substantial depth based on the wall thickness, as shown in FIG. 10B.

Exemplary Downhole Devices Configured as a Selectable Hole Trimmer

FIG. 14A shows a cross-sectional side view of an exemplary embodiment of the downhole device configured as a selectable hole trimmer 1400, showing a selectable hole cutter 1401 on the downhole device 1400; FIG. 14B shows a detailed view of the selectable hole trimmer 1400 of FIG. 14A; and FIG. 14C shows a Section A cross-sectional view of the selectable hole trimmer 1400 of FIG. 14A.
FIG. 15A shows a view of an exemplary embodiment of the downhole device configured as a selectable hole trimmer 1500, showing a plurality of selectable hole cutters 1401 on the downhole device 1500 in a deactivated position; FIG. 15B shows a Section A-A cross-sectional view of the selectable hole trimmer 1500 of FIG. 15A, showing a deactivated cutter piston 1402, a nozzle 1404, a body 1505, an intermediate sleeve 1510 a, a sliding sleeve 1510 b, a pressure equalization slot 1521 a, and a return spring 1520; FIG. 15C shows a detailed B view of the selectable hole trimmer 1500 of FIG. 15A-15B, showing a deactivated cutter piston 1402, a nozzle 1404, an activation port 1514 b and a pressure equalization slot 1521 b; FIG. 15D shows a detailed C view of the selectable hole trimmer 1500 of FIG. 15A-15C, showing a hydraulic fluid port 1514 a; and FIG. 15E shows a Section D-D cross-sectional view of the selectable hole trimmer 1500 of FIG. 15A-15D, showing a deactivated cutter piston 1402, an intermediate sleeve 1510 a, and a sliding sleeve 1510 b.
FIG. 16A shows a view of an exemplary embodiment of the downhole device configured as a selectable hole trimmer 1600, showing the selectable hole cutter 1401 on the downhole device 1600 in an activated position; FIG. 16B shows a Section A-A cross-sectional view of the selectable hole trimmer 1600 of FIG. 16A, showing an activated cutter piston 1402, a nozzle 1404, a body 120, 1605, an intermediate sleeve 1610 a, a sliding sleeve 1610 b, a pressure equalization slot 1621 a, and a return spring 1620 b; FIG. 16C shows a detailed B view of the selectable hole trimmer 1600 of FIG. 16A-16B, showing an activated cutter piston 1402 with an extended cutter 1406, a nozzle 1404, and an activation port 1614 b; FIG. 16D shows a detailed C view of the selectable hole trimmer 1600 of FIG. 16A-16C, showing a hydraulic fluid port 1614 a; and FIG. 16E shows a Section D-D cross-sectional view of the selectable hole trimmer 1600 of FIG. 16A-16D, showing an activated cutter piston 1402 with extended cutters 1406, an intermediate sleeve 1610 a, and a sliding sleeve 1610 b.
FIG. 19A shows a view of another exemplary embodiment of the downhole device configured as a selectable hole trimmer 1900 without any bypass nozzles, showing a selectable hole cutter 1401 on the downhole device 1900 in a deactivated position; FIG. 19B shows a Section A-A cross-sectional view of the selectable hole trimmer 1900 of FIG. 19A, showing a deactivated cutter piston 1402, a body 120, 1905, an intermediate sleeve 1910 a, a sliding sleeve 1910 b, a hydraulic fluid port 1914, a compensating spring 1920 a, and a return spring 1920 b; FIG. 19C shows a Section C-C cross-sectional view of the selectable hole trimmer 1900 of FIG. 19A-19B, showing an intermediate sleeve 1910 a, and a sliding sleeve 1910 b.
FIG. 21A shows a cross-sectional view of another exemplary embodiment of a downhole device configured as a selectable hole trimmer 2100, showing a selectable hole cutter 1401 on the downhole device 2100 in a deactivated position, an intermediate sleeve 2110 a, compensating sleeve 2110 c, a hydraulic fluid port 2114, compensating port 2115, and a stop block 1158; FIG. 21B shows a cross-sectional view of the exemplary selectable hole trimmer 2100 of FIG. 21A, showing an activated cutter piston 1402 with extended cutters 1406, the intermediate sleeve 2110 a, the compensating sleeve 2110 c, the hydraulic fluid port 2114, compensating port 2115, and the stop block 1158; FIG. 21C shows a detailed cross-sectional view of the exemplary selectable hole trimmer 2100 of FIG. 21A, showing a deactivated cutter piston 1402 with retracted cutters 1406, the compensating sleeve 2110 c and the stop block 1158; FIG. 21D shows a detailed cross-sectional view of the exemplary selectable hole trimmer 2100 of FIG. 21B, showing the activated cutter piston 1402 with extended cutters 1406; FIG. 21E shows a detailed cross-sectional view of the exemplary hole trimmer 2100 of FIGS. 21A and 21C; FIG. 21F shows a detailed view of the exemplary hole trimmer 2100 of FIGS. 21B and 21D; and FIG. 21G shows an upper, left perspective view of the exemplary selectable hole trimmer 2100 of FIGS. 21A-21F, showing the activated cutter piston 1402 with extended cutters 1406.
FIGS. 14A, 15B, 16B, 19B and 21A-21B show a cross-sectional side view of an exemplary embodiment of the downhole device configured as a selectable hole trimmer 1400, 1500, 1600, 1900, 2100, showing a selectable hole cutter 1401. The selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may be positioned at a desired location between the drill bit 132 and the ground 102. See e.g., FIG. 1 . Other components or downhole devices may be installed or positioned between the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 and the drill bit 132. Id.
In another embodiment, one or more selectable hole trimmers 1400, 1500, 1600, 1900, 2100 may be positioned at a desired locations between the drill bit 132 and the ground 102. See e.g., FIG. 1 . Other components or downhole devices may be installed or positioned between the one or more selectable hole trimmers 1400, 1500, 1600, 1900, 2100 and the drill bit 132. Id.
The one or more selectable hole trimmers 1400, 1500, 1600, 1900, 2100 may be any suitable number without limitation. In an embodiment, the one or more selectable hole trimmers 1400, 1500, 1600, 1900, 2100 may be up to about 50 (and any range or value there between). In an embodiment, the one or more selectable hole trimmers 1400, 1500, 1600, 1900, 2200 may be up to about 20. In an embodiment, the one or more selectable hole trimmers 1400, 1500, 1600, 1900, 2100 may be about 10. In an embodiment, the one or more selectable hole trimmers 1400, 1500, 1600, 1900, 2100 may be about 3.
The one or more selectable hole trimmers 1400, 1500, 1600, 1900, 2100 may be separated by any suitable distance without limitation. In an embodiment, the one or more selectable hole trimmers 1400, 1500, 1600, 1900, 2100 may be separated by up to about 100-feet (and any range or value there between). In an embodiment, the one or more selectable hole trimmers 1400, 1500, 1600, 1900, 2100 may be separated by up to about 30-feet. In an embodiment, the one or more selectable hole trimmers 1400, 1500, 1600, 1900, 2100 may be separated by up to about 3-feet. In an embodiment, the one or more selectable hole trimmers 1400, 1500, 1600, 1900, 2100 may be separated by up to about 1-foot. In an embodiment, the one or more selectable hole trimmers 1400, 1500, 1600, 1900, 2100 may be separated by about 0-foot.
As shown in FIG. 14A, the selectable hole trimmer 1400 comprises a body 1405 as part of the drill string 120, a sleeve 310 sealingly slidable inside the body 120, 1405. See also FIGS. 1 & 3 . The sleeve 310 may comprise at least one port 314 alignable with a corresponding bypass outlet 312 of the body 120, 1405. The bypass outlet 312 may comprise an erosion resistant nozzle 313. The selectable hole trimmer 1400 further comprises a resilient member 320 (e.g., a spring) biasing the sleeve 310 against the body 120, 1405. The selectable hole trimmer 1400 further comprises a three-way valve with an actuator 340 that is configured to provide a pressure to the sleeve 310. The actuator 340 can actuate the sleeve 310 to move relative to the body 120, 1405, such as to align the bypass outlet 312 with the port 314. The selectable hole trimmer 1400 also comprises a controller (e.g., the controller electronics 620 shown in FIG. 6 , or implemented as the computer device 700 of FIG. 7 as discussed below) configured to operate the actuator 340 in response to a change of a monitored operation condition.
In some embodiments, the selectable hole trimmer 1400 would use information, measurements, and other received signals (electric or mechanical, such as pressure signals) to actuate the actuator 340. See also FIGS. 1 & 3 . For example, the selectable hole trimmer 1400 may sense or measure the rotation rate in revolutions per minute (“rpm”), weight or pressure signals (e.g., related to well depth, length of drill string 120, and installed components) and control the actuator 340 in response to the measured signals.
Turning to FIG. 14A, the selectable hole trimmer 1400 may have a neutral position where the sleeve 310 is biased away from the bypass outlet 312. See also FIG. 3 . As a result, the sleeve 310 forms a volume 322 with the body 120, 1405. Before actuation, the drill string inlet 334 communicates fluid or its pressure (or both) to the volume inlet 336. Since the drill string inlet 334 takes drilling mud from the bore of the drill string 120 and is fluidly connected to the volume inlet 336 via the three-way valve actuator 340, the sliding sleeve volume 322 would have the same fluid pressure as that of the drill string 120. This pressure of the sliding sleeve volume 322 would be equal to the pressure outside of the sleeve 310 and therefore the sleeve 310 is subject only to the spring 320 and in the neutral position.
In the illustrated embodiment, a lock ring 330 may further be used to define the neutral position, for example, to allow the spring 320 to statically push the sleeve 310 against the lock ring 330. See also FIG. 3 .
Similar to the previous embodiment, the selectable hole trimmer 1400 comprises a body 1405 as part of the drill string 120, a sleeve 410 sealingly slidable inside the body 120, 1405. See also FIGS. 1 & 4 . The sleeve 410 may comprise at least one port 414 alignable with a corresponding bypass outlet 412 of the body 120. The bypass outlet 412 may comprise an erosion resistant nozzle 413. The downhole device 210 further comprises a resilient member 420 (e.g., a spring) biasing the sleeve 410 against the body 120, 1405. The selectable hole trimmer 1400 further comprises a motor driven pump 440 (herein called motor pump) that is configured to provide a pressure to the sleeve 410. The motor pump 440 can actuate the sleeve 410 to move relative to the body 120, 1405, such as to align the bypass outlet 412 with the port 414.
The selectable hole trimmer 1400 may have a neutral position where the sleeve 410 is biased toward the bypass outlet 412 and the bypass port 414 is offset from the bypass outlet 412. The sleeve 410 is pushed by the spring 420 secured at a lock ring 430 toward the bypass outlet, forming a volume 422 with the body 120, 1405. The volume 422 is connected to the motor pump 440 via a motor pump fluid line 436. In this embodiment, the pressure of the drilling fluids in the selectable hole trimmer 1400 bore (or the drill string 120) may communicate with an accumulator/pressure compensation vessel 442 (the “accumulator” 442). The accumulator 442 may actuate the adjacent piston to pressurize the internal oil in its oil chamber to the same pressure as that of the downhole device 210 (i.e., pressure inside the drill string 120). The accumulator 442 and the motor pump 440 may both be housed in a radial housing 450 of the body 120, 1405.
FIG. 14B shows a detailed view of the selectable hole trimmer 1400 of FIG. 14A, showing a selectable hole cutter 1401. As shown in FIG. 14B, the selectable hole cutter 1401 has a cutter piston 1402 disposed within a container 1408 or cutout of a downhole device 1400.
In an embodiment, one or more cutter pistons 1402 may be affixed to the container 1408 or cutout of a downhole device 1400, 1500, 1600, 1900, 2100 via one or more fasteners. See e.g., FIGS. 21A-21D. Fasteners are well known in the art.
In an embodiment, one or more selectable hole cutters 1401 comprises one or more cutter pistons 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402.
In an embodiment, one or more selectable hole cutters 1401 comprises a cutter blade 1406 a and one or more cutter pistons 1402. In an embodiment, the cutter blade 1406 a has one or more cutter pistons 1402 affixed to the cutter blade 1406 a. In an embodiment, the cutter blade 1406 a has one or more cutters 1406 affixed to the cutter blade 1406 a.
In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may have one or more selectable hole cutters 1401 and one or more nozzles 1404. In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may have one or more selectable hole cutters 1401 and one or more nozzles 1404 disposed between the one or more selectable hole cutters 1401.
The cutter piston 1402 may be any suitable shape. For example, suitable shapes, include, but are not limited to, shapes having a round (e.g., cylindrical) or elliptical base. In an embodiment, the cutter piston 1402 may be a cylindrical shape having a first end 1402 a and a second end 1402 b. The first end 1402 a may have a shoulder. The second end 1402 b may have the one or more cutters 1406.
The cutter piston 1402 may be any suitable size, as space allows. In an embodiment, the cutter piston 1402 may be up to about 4-inches in diameter, and any range or value there between. In an embodiment, the cutter piston 1402 may be from about 1-inches to about 4-inches in diameter. In an embodiment, the cutter piston 1402 may be from about 1.5-inches to about 2-inches in diameter.
The shoulder of the cutter piston 1402 may be any suitable size to retain a compressed spring, as space allows.
The nozzle 1404 may be any suitable nozzle. For example, a suitable nozzle 1404 includes, but is not limited to, a carbide nozzle.
The nozzle 1404 may be any suitable size. In an embodiment, the nozzle 1404 may be up to about 1-inch diameter, and any range or value there between. In an embodiment, the nozzle 1404 may be up to about ½-inch diameter. In an embodiment, the nozzle 1404 may be ¼-inch diameter.
In an embodiment, the selectable hole cutter 1401 has a cutter piston 1402 having a first end 1402 a and a second end 1402 b. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the second end 1402 b of the cutter piston 1402, wherein the first end 1402 a of the cutter piston 1402 is disposed within a container 1408 or a cutout of a downhole device 1400, 1500, 1600, 1900, 2100. See e.g., FIGS. 15B-15C, 16B-16C, 19B & 21A-21D.
In an embodiment, the selectable hole cutter 1401 has a cutter piston 1402 having a first end 1402 a and a second end 1402 b and one or more cutters 1406 affixed at or near the second end 1402 b of the cutter piston 1402, wherein the first end 1402 a of the cutter piston 1402 is disposed within a container 1408 or a cutout of a downhole device 1400, 1500, 1600, 1900, 2100. See e.g., FIGS. 15B-15C, 16B-16C, 19B & 21A-21D.
In an embodiment, one or more cutters 1406 may be affixed to the second end 1402 a of the cutter piston 1402. In an embodiment, one or more cutters 1406 may be affixed at or near the second end 1402 a of the cutter piston 1402.
The cutters 1406 may be any suitable cutter capable of and oriented to contact, and cut or gouge a side surface of a drilled hole 130. For example, suitable cutters 1406, include, but are not limited to, polycrystalline diamond compact (PDC) cutters, welded pads with tungsten carbide chunks, welded pads with tungsten carbide discs, and combinations thereof.
In an embodiment, the selectable hole cutter 1401 has a cutter piston 1402 having a first end 1402 a and a second end 1402 b, one or more cutters 1406 and one or more non-aggressive elements affixed at or near the second end 1402 b of the cutter piston 1402, wherein the first end 1402 a of the cutter piston 1402 is disposed within a container 1408 or a cutout of a downhole device 1400, 1500, 1600, 1900, 2100. See e.g., FIGS. 15B-15C, 16B-16C, 19B & 21A-21D.
In an embodiment, one or more cutters 1406 and one or more non-aggressive elements may be affixed to the second end 1402 a of the cutter piston 1402. See e.g., FIGS. 15B-15C, 16B-16C and 19B. In an embodiment, one or more cutters 1406 and one or more non-aggressive elements may be affixed at or near the second end 1402 a of the cutter piston 1402. Id.
In an embodiment, one or more cutters 1406 and one or more non-aggressive elements may be affixed to the second end 1402 a of one or more cutter pistons 1402. See e.g., FIGS. 21A-21D. In an embodiment, one or more cutters 1406 and one or more non-aggressive elements may be affixed at or near the second end 1402 a of one or more cutter pistons 1402. Id. In an embodiment, the one or more cutters 1406 and, in some embodiments, the one or more non-aggressive elements may be affixed to the second end of the one or more cutter pistons 1402 via fasteners, welds or other means. Id. Fasteners and welds are well known in the art.
The cutters 1406 may be any suitable cutter capable of and oriented to contact, and cut or gouge a side surface of a drilled hole 130. For example, suitable cutters 1406, include, but are not limited to, polycrystalline diamond compact (PDC) cutters, welded pads with tungsten carbide chunks, welded pads with tungsten carbide discs, and combinations thereof.
The non-aggressive elements may be any suitable elements capable of and oriented to contact, but not cut or gouge a side surface of the drilled hole 130. For example, suitable non-aggressive elements include, but are not limited to, PDC or carbide ovoids, welded and ground hardfacing, ground smooth carbide pads, welded smooth carbide pads, PDC cutters oriented parallel to the side surface of the drilled hole 130 to contact but not cut or gouge the surface, and combinations thereof.
The container 1408 or cutout of the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may be any suitable shape. For example, suitable shapes include, but are not limited to, shapes having a round (e.g., cylindrical) or elliptical base. In an embodiment, the container 1408 may be a cylindrical shape having a first end 1408 a and a second end 1408 b. The first end 1408 a may be open. The second end 1408 b may have an opening.
In an embodiment, a spring 1410 and a spacer 1412 are disposed between the cutter piston 1402 and the container 1408 or cutout.
In an embodiment, the spring 1410 may be any suitable spring capable of being disposed between the cutter piston 1402 and the container 1408 or cutout.
In an embodiment, the spacer 1412 may be any suitable shape capable of being disposed between the cutter piston 1402 and the container 1408 or cutout. For example, suitable shapes include, but are not limited to, shapes having a round (e.g., cylindrical) or elliptical base. In an embodiment, the spacer 1412 may be cylindrical shape having a first end 1412 a and a second end 1412 b. The first end 1412 a may be open. The second end 1412 b may be open.
In an embodiment, the spring 1410 is compressed against the shoulder of the cutter piston 1402 and held in a compressed position by a lock ring and a snap ring 1414.
In an embodiment, the lock ring and the snap ring 1414 may be any suitable lock ring and snap ring capable of holding the spring 1410 in a compressed position against a shoulder of the cutter piston 1402.
When one or more cutter pistons 1402 are deactivated, one or more springs 1410 retracts the one or more cutter pistons 1402 into one or more containers 1408 or cutouts. See e.g., FIG. 21A-21D.
When the one or more cutter pistons 1402 are activated, one or more spacers 1412 limit extension/travel of the one or more cutter pistons 1402 (and the one or more cutters 1406) out of the one or more containers 1408 or cutouts. See e.g., FIGS. 21A-21D.
When the one or more cutter pistons 1402 are activated, the one or more cutters 1406 may extend out of the one or more containers 1408 or cutouts, and contact, and cut or gouge a side surface of a drilled hole 130. See e.g., FIGS. 21A-21D.
When the one or more cutter pistons 1402 are activated, the one or more cutters 1406 and the one or more non-aggressive elements (not shown) may extend out of the one or more containers 1408 or cutouts, and contact, but not cut or gouge a side surface of the drilled hole 130. See e.g., FIGS. 21A-21D.
When the one or more cutter pistons 1402 are fully activated, the one or more cutters 1406 may extend or travel any suitable distance 1420 out of the one or more containers 1408 or cutouts. See e.g., FIGS. 21A-21D. When the one or more cutter pistons 1402 are fully activated, the one or more cutters 1406 may extend or travel any suitable distance 1420 out of the one or more containers 1408 or cutouts, as aggressiveness requires and space allows. In an embodiment, the one or more cutters 1406 may extend or travel up to about ½-inch. In an embodiment, the one or more cutters 1406 may extend or travel up to about ¼-inch. In an embodiment, the one or more cutters 1406 may extend or travel such that their diameter is about ¼-inch larger that the drill bit size.
When the one or more cutter pistons 1402 are fully activated, the one or more cutters 1406 and one or more non-aggressive elements may extend or travel any suitable distance 1420 out of the one or more containers 1408 or cutouts. See e.g., FIGS. 15B-15C, 16B-16C, 19B & 21A-21D. When the one or more cutter pistons 1402 are fully activated, the one or more cutters 1406 and one or more non-aggressive elements may extend or travel any suitable distance 1420 out of the one or more containers 1408 or cutouts, as aggressiveness requires and space allows. Id. In an embodiment, the one or more cutters 1406 and one or more non-aggressive elements may extend or travel up to about 1-inch, and any range or value there between. In an embodiment, the one or more cutters 1406 and one or more non-aggressive elements (not shown) may extend or travel up to about ½-inch. In an embodiment, the one or more cutters 1406 and one or more elements (not shown) may extend or travel such that their diameter is about ¼-inch larger that the drill bit size.
When the one or more cutter pistons 1402 are deactivated, one or more springs 1410 retract the one or more cutter pistons 1402 (and one or more cutters 1406) into the one or more containers 1408 or cutouts away from the side surface of the drilled hole 130. See e.g., FIGS. 15B-15C, 16B-16C, 19B & 21A-21D.
When the one or more cutter pistons 1402 are deactivated, the one or more springs 1410 retract the one or more cutter pistons 1402 (and one or more cutters 1406 and the one or more non-aggressive elements (not shown)) into the one or more containers 1408 or cutouts away from the side surface of the drilled hole 130. See e.g., FIGS. 15B-15C, 16B-16C, 19B & 21A-21D.
FIG. 14C shows a Section A cross-sectional view of the selectable hole trimmer 1400 of FIG. 14A, showing a plurality of selectable hole cutters 1401 and a plurality of nozzles 1404. See e.g., FIGS. 15B-15C, 16B-16C, 19B & 21A-21D. As shown in FIG. 14C, the selectable hole cutter 1401 may have a cutter piston 1402 disposed within a container 1408 or cutout of the downhole device 1400.
In these embodiments, the selectable hole trimmer 1400 comprises a selectable hole cutter 1401 and a nozzle 1404. See e.g., FIGS. 14A-14C.
In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may have any suitable number of selectable hole cutters 1401, as space allows. In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may have up to about 30 selectable hole cutters 1401, and any range or value there between. In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may have up to about 20 selectable hole cutters 1401. In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may have up to about 10 selectable hole cutters 1401. In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may have up to about 3 selectable hole cutters 1401.
In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may have any suitable number of nozzles 1404, as space allows. In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may have up to about 30 nozzles 1404, and an range or value there between. In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may have up to about 20 nozzles 1404. In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may have up to about 10 nozzles 1404. In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 may have up to about 3 nozzles 1404.
In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 comprises a first plurality of selectable hole cutters 1401 a separated by any suitable radial distance 1416 a. In an embodiment, the first plurality of selectable hole cutters 1401 a may be separated by any suitable radial distance 1416 a around a circumference of the selectable hole trimmer 1400, 1500, 1600, 1900, 2100, as space allows. In an embodiment, the first plurality of selectable hole cutters 1401 a may be separated by an approximately equal radial distance 1416 a around a circumference of the selectable hole trimmer 1400, 1500, 1600, 1900, 2100, as space allows. For example, if the first plurality of selectable hole cutters 1401 a is 3 selectable hole cutters 1401, the 3 selectable hole cutters 1401 may be separated by about 120 degrees around the circumference of the selectable hole trimmer 1400, 1500, 1600, 1900, 2100.
In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 comprises a second plurality of selectable hole cutters 1401 b separated by a longitudinal distance 1718 a, 1618 a along an axial length of the selectable hole trimmer 1400, 1500, 1600, 1900, 2100. See e.g., FIG. 17-18 . In an embodiment, the second plurality of selectable hole cutters 1401 b may be separated by any suitable longitudinal distance 1718 a, 1618 a along an axial length of the selectable hole trimmer 1400, 1500, 1600, 1900, 2100, as space allows. Id. In an embodiment, the second plurality of selectable hole cutters 1401 b may be separated by up to about 30-inches, and any range or value there between. In an embodiment, the second plurality of selectable hole cutters 1401 b may be separated by up to about 20-inches. In an embodiment, the second plurality of selectable hole cutters 1401 b may be separated by up to about 10-inches. In an embodiment, the second plurality of selectable hole cutters 1401 b may be separated by up to about 6-inches.
In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 comprises a first plurality of nozzles 1404 a, 1704 a, 1804 a separated by any suitable radial distance 1416 b. See e.g., FIGS. 17-18 . In an embodiment, the first plurality of nozzles 1404 a, 1704 a, 1804 a may be separated by any suitable radial distance 1716 a around a circumference of the selectable hole trimmer 1400, 1500, 1600, 1900, 2100, as space allows. Id. In an embodiment, the first plurality of nozzles 1404 a, 1704 a, 1804 a may be separated by an approximately equal radial distance 1716 a around a circumference of the selectable hole trimmer 1400, 1500, 1600, 1900, 2100. Id. For example, if the first plurality of nozzles 1404 a, 1704 a, 1804 a is 3 nozzles 1704, 1804, the 3 nozzles 1704, 1804 may be separated by about 120 degrees around the circumference of the selectable hole trimmer 1400, 1500, 1600, 1900, 2100. Id.
In an embodiment, the selectable hole trimmer 1400, 1500, 1600, 1900, 2100 comprises a second plurality of nozzles 1404 b separated by a longitudinal distance 1718 b, 1618 b along an axial length of the selectable hole trimmer 1400, 1500, 1600, 1900, 2100. See e.g., FIGS. 17-18 . In an embodiment, the second plurality of nozzles 1404 b may be separated by any suitable longitudinal distance 1718 b, 1618 b along an axial length of the selectable hole trimmer 1400, 1500, 1600, 1900, 2100, as space allows. Id. In an embodiment, the second plurality of nozzles 1404 b may be separated by up to about 30-inches, and any range or value there between. In an embodiment, the second plurality of nozzles 1404 b may be separated by up to about 20-inches. In an embodiment, the second plurality of nozzles 1404 b may be separated by up to about 10-inches. In an embodiment, the second plurality of nozzles 1404 b may be separated by up to about 6-inches.
FIG. 17 shows a view of an exemplary selectable hole trimmer 1400, 1500, 1600, 1900, 2100 configured as a linear optimizer tool 1700, showing a linear configuration. As shown in FIG. 17 , the linear optimizer tool 1700 has a plurality of selectable hole cutters 1401, 1701 and a plurality of nozzles 1404, 1704.
In an embodiment, the linear optimizer tool 1700 may have any suitable number of selectable hole cutters 1401, 1701 in a linear configuration, as space allows. In an embodiment, the linear optimizer tool 1700 may have up to about 30 selectable hole cutters 1401, 1701 in a linear configuration, and any range or value there between. In an embodiment, the linear optimizer tool 1700 may have up to about 20 selectable hole cutters 1401, 1701 in a linear configuration. In an embodiment, the linear optimizer tool 1700 may have up to about 10 selectable hole cutters 1401, 1701 in a linear configuration. In an embodiment, the linear optimizer tool 1700 may have up to about 3 selectable hole cutters 1401, 1701 in a linear configuration. See e.g., FIG. 17 .
In an embodiment, the linear optimizer tool 1700 may have any suitable number of nozzles 1404, 1704 in a linear configuration, as space allows. In an embodiment, the linear optimizer tool 1700 may have up to about 30 nozzles 1404, 1704 in a linear configuration, and any range or value there between. In an embodiment, the linear optimizer tool 1700 may have up to about 20 nozzles 1404, 1704 in a linear configuration, and any range or value there between. In an embodiment, the linear optimizer tool 1700 may have up to about 10 nozzles 1404, 1704 in a linear configuration. In an embodiment, the linear optimizer tool 1700 may have up to about 3 nozzles 1404, 1704 in a linear configuration. See e.g., FIG. 17 .
In an embodiment, the linear optimizer tool 1700 comprises a first plurality of selectable hole cutters 1401 a, 1701 a separated by any suitable radial distance 1416 a, 1716 a. In an embodiment, the first plurality of selectable hole cutters 1401 a, 1701 a may be separated by any suitable radial distance 1416 a, 1716 a around a circumference of the linear optimizer tool 1700, as space allows. In an embodiment, the first plurality of selectable hole cutters 1401 a, 1701 a may be separated by an approximately equal radial distance 1416 a, 1716 a around a circumference of the linear optimizer tool 1700. For example, if the first plurality of selectable hole cutters 1401 a, 1701 a is 3 selectable hole cutters 1401, 1701, the 3 selectable hole cutters 1401, 1701 may be separated by about 120 degrees around the circumference of the linear optimizer tool 1700.
In an embodiment, the linear optimizer tool 1700 comprises a second plurality of selectable hole cutters 1401 b, 1701 b separated by a longitudinal distance 1718 a along an axial length of the linear optimizer tool 1700 in a linear configuration. In an embodiment, the second plurality of selectable hole cutters 1401 b, 1701 b may be separated by any suitable longitudinal distance 1718 a along an axial length of the linear optimizer tool 1700 in a linear configuration, as space allows. In an embodiment, the second plurality of selectable hole cutters 1401 b, 1701 b may be separated by up to about 30-inches in a linear configuration, and any range or value there between. In an embodiment, the second plurality of selectable hole cutters 1401 b, 1701 b may be separated by up to about 20-inches in a linear configuration. In an embodiment, the second plurality of selectable hole cutters 1401 b, 1701 b may be separated from about 10-inches in a linear configuration. In an embodiment, the second plurality of selectable hole cutters 1401 b, 1701 b may be separated by about 6-inches in a linear configuration.
In an embodiment, the linear optimizer tool 1700 comprises a first plurality of nozzles 1404 a, 1704 a separated by any suitable radial distance 1416 b, 1716 b. In an embodiment, the first plurality of nozzles 1404 a, 1704 a may be separated by any suitable radial distance 1416 a, 1716 a around a circumference of the linear optimizer tool 1700, as space allows. In an embodiment, the first plurality of nozzles 1404 a, 1704 a may be separated by an approximately equal radial distance 1416 a, 1716 a around a circumference of the linear optimizer tool 1700. For example, if the first plurality of nozzles 1404 a, 1704 a is three nozzles 1404, 1704, the three nozzles 1404, 1704 may be separated by about 120 degrees around the circumference of the linear optimizer tool 1700.
In an embodiment, the linear optimizer tool 1700 comprises a second plurality of nozzles 1404 b, 1704 b separated by a longitudinal distance 1718 b along an axial length of the linear optimizer tool 1700 in a linear configuration. In an embodiment, the second plurality of nozzles 1404 b, 1704 b may be separated by any suitable longitudinal distance 1718 b along an axial length of the linear optimizer tool 1700 in a linear configuration, as space allows. In an embodiment, the second plurality of nozzles 1404 b, 1704 b may be separated by up to about 30-inches in a linear configuration, and range or value there between. In an embodiment, the second plurality of nozzles 1404 b, 1704 b may be separated by up to about 20-inches in a linear configuration. In an embodiment, the second plurality of nozzles 1404 b, 1704 b may be separated by up to about 10-inches in a linear configuration. In an embodiment, the second plurality of nozzles 1404 b, 1704 b may be separated by up to about 6-inches in a linear configuration.
FIG. 18 shows a view of an exemplary selectable hole trimmer 1400, 1500, 1600, 1900, 2100 configured as a spiral optimizer tool 1800, showing a spiral configuration. As shown in FIG. 18 , the spiral optimizer tool 1800 has a plurality of selectable hole cutters 1401, 1801 and a plurality of nozzles 1404, 1804.
In an embodiment, the spiral optimizer tool 1800 may have any suitable number of selectable hole cutters 1401, 1801 in a spiral configuration, as space allows. In an embodiment, the spiral optimizer tool 1800 may have up to about 30 selectable hole cutters 1401, 1801 in a spiral configuration, and any range or value there between. In an embodiment, the spiral optimizer tool 1800 may have up to about 20 selectable hole cutters 1401, 1801 in a spiral configuration. In an embodiment, the spiral optimizer tool 1800 may have up to about 10 selectable hole cutters 1401, 1801 in a spiral configuration. In an embodiment, the spiral optimizer tool 1800 may have up to about 3 selectable hole cutters 1401, 1801 in a spiral configuration. See e.g., FIG. 18 .
In an embodiment, the spiral optimizer tool 1800 may have any suitable number of nozzles 1404, 1804 in a spiral configuration, as space allows. In an embodiment, the spiral optimizer tool 1800 may have up to about 30 nozzles 1404, 1804 in a spiral configuration, and any range or value there between. In an embodiment, the spiral optimizer tool 1800 may have up to about 20 nozzles 1404, 1804 in a spiral configuration. In an embodiment, the spiral optimizer tool 1800 may have up to about 10 nozzles 1404, 1804 in a spiral configuration. In an embodiment, the spiral optimizer tool 1800 may have up to about 3 nozzles 1404, 1804 in a spiral configuration. See e.g., FIG. 18 .
In an embodiment, the spiral optimizer tool 1800 comprises a first plurality of selectable hole cutters 1401 a, 1801 a separated by any suitable radial distance 1416 a, 1716 a. In an embodiment, the first plurality of selectable hole cutters 1401 a, 1801 a may be separated by any suitable radial distance 1416 a, 1716 a around a circumference of the spiral optimizer tool 1800, as space allows. In an embodiment, the first plurality of selectable hole cutters 1401 a, 1801 a may be separated by an approximately equal radial distance 1416 a, 1716 a around a circumference of the spiral optimizer tool 1800. For example, if the first plurality of selectable hole cutters 1401 a, 1801 a is three selectable hole cutters 1401, 1801, the three selectable hole cutters 1401, 1801 may be separated by about 120 degrees around the circumference of the spiral optimizer tool 1800.
In an embodiment, the spiral optimizer tool 1800 comprises a second plurality of selectable hole cutters 1401 b, 1801 b separated by a longitudinal distance 1818 a along an axial length of the spiral optimizer tool 1800 in a spiral configuration. In an embodiment, the second plurality of selectable hole cutters 1401 b, 1801 b may be separated by any suitable longitudinal distance 1818 a along an axial length of the spiral optimizer tool 1800 in a spiral configuration, as space allows. In an embodiment, the second plurality of selectable hole cutters 1401 b, 1801 b may be separated by up to about 30-inches in a spiral configuration, and any range or value there between. In an embodiment, the second plurality of selectable hole cutters 1401 b, 1801 b may be separated by up to about 20-inches in a spiral configuration. In an embodiment, the second plurality of selectable hole cutters 1401 b, 1801 b may be separated by up to about 10-inches in a spiral configuration. In an embodiment, the second plurality of selectable hole cutters 1401 b, 1801 b may be separated by up to about 6-inches in a spiral configuration.
In an embodiment, the spiral optimizer tool 1800 comprises a first plurality of nozzles 1404 a, 1804 a separated by any suitable radial distance 1416 b, 1716 b. In an embodiment, the first plurality of nozzles 1404 a, 1804 a may be separated by any suitable radial distance 1416 a, 1716 a around a circumference of the spiral optimizer tool 1800, as space allows. In an embodiment, the first plurality of nozzles 1404 a, 1804 a may be separated by an approximately equal radial distance 1416 a, 1716 a around a circumference of the spiral optimizer tool 1800. For example, if the first plurality of nozzles 1404 a, 1804 a is three nozzles 1404, 1804, the three nozzles 1404, 1804 may be separated by about 120 degrees around the circumference of the spiral optimizer tool 1800.
In an embodiment, the spiral optimizer tool 1800 comprises a second plurality of nozzles 1404 b, 1804 b separated by a longitudinal distance 1818 b along an axial length of the spiral optimizer tool 1800 in a spiral configuration. In an embodiment, the second plurality of nozzles 1404 b, 1804 b may be separated by any suitable longitudinal distance 1818 b along an axial length of the spiral optimizer tool 1800 in a spiral configuration, as space allows. In an embodiment, the second plurality of nozzles 1404 b, 1804 b may be separated by up to about 30-inches in a spiral configuration, and any range or value there between. In an embodiment, the second plurality of nozzles 1404 b, 1804 b may be separated by up to about 20-inches in a spiral configuration. In an embodiment, the second plurality of nozzles 1404 b, 1804 b may be separated by up to about 10-inches in a spiral configuration. In an embodiment, the second plurality of nozzles 1404 b, 1804 b may be separated by up to about 6-inches in a spiral configuration.

Method of Assembling Downhole Device

FIG. 13 shows a method of assembling the downhole device 1300. As shown in FIG. 13 , a method of assembling a device for bypassing fluids around a drill bit 1306 may include: providing a lower sleeve, an upper sleeve and a resilient member 1302 (see e.g., FIGS. 11A-11B); assembling the lower sleeve, the upper sleeve and the resilient member to form a sleeve 1304 (see e.g., FIGS. 11C-1 & 11C-2 ); and assembling a body and the sleeve to form the device for bypassing drill fluids around the drill bit 1306 (see e.g., FIGS. 11D-11E). In an embodiment, the sleeve 310, 410 and 510 may be sealingly slideable inside the body 1105. Id. In an embodiment, the sleeve 310, 410 and 510 has a bypass port 314, 414 and 514 alignable with an erosion resistant nozzle 313, 413 and 513 of the body 1105. Id.
In some embodiments, the resilient member comprises a spring 320, 420 and 520.
FIG. 11A shows a side view of a lower sleeve and an upper sleeve of an alternative exemplary embodiment of the downhole device 210 having carved structures 1110 and 1120 for regulating fluid flow prior to a first step of assembly. See e.g., FIGS. 11D-11E: 1110 & 1120. FIG. 11B shows a side view of the lower sleeve, the upper sleeve and a spring of the downhole device 210 shown in FIG. 11A after the first step of assembly.
As shown in FIGS. 11A-11B, the sleeve 310, 410 and 510 of the downhole device 210 includes: a lower sleeve 1154, an upper sleeve 1156 and a resilient member. In some embodiments, the resilient member comprises a spring 320, 420 and 520.
In some embodiments, the lower sleeve 1154 and the upper sleeve 1156 are attached via a connection. See e.g., FIG. 11A. In some embodiments, the lower sleeve 1154 and the upper sleeve 1156 are removably attached via a threaded connection. Id. In some embodiments, the lower sleeve 1154 and the upper sleeve 1156 are removably attached via a threaded connection and a set screw. Id.
FIG. 11C-1 shows a side view of a stop block of the downhole device 210 shown in FIGS. 11A-11B; FIG. 11C-2 shows a side view of the assembled sleeve of the exemplary embodiment of the downhole device 210 shown in FIG. 11B; and FIG. 11D shows a side view of a body and the sleeve of the downhole device 210 prior to a second step of assembly. FIG. 11E shows a cross-sectional view of the body and the sleeve of the downhole device 210 of FIGS. 11A-11D after the second step of assembly.
As shown in FIGS. 11C-1 and 11C-2 , the sleeve 310, 410 and 510 of the downhole device 210 includes: a lower sleeve 1154, an upper sleeve 1156 and a resilient member. In some embodiments, the resilient member comprises a spring 320, 420 and 520. See e.g., FIG. 11C-2 .
In some embodiments, the upper sleeve 1156 comprises a stop block 1158. In some embodiments, the upper sleeve 1156 comprises a stop block 1158 for the spring 320, 420 and 520.
As shown in FIGS. 11D-11E, the downhole device 210 comprises a body 1105 and the sleeve 310, 410 and 510. In some embodiment, the downhole device 210 comprises a body 1158 (see FIGS. 11C-1 & 11C-2 :1158) having carved structures 1110 and 1120. See e.g., FIGS. 11D-11E: 1110 & 1120.
In an embodiment, the downhole device 210 further comprises a bypass outlet 312, 412 and 512 and a radial housing 350, 450 and 550.
As shown in FIG. 11E, the body 1105 and the sleeve 310, 410 and 510 are attached via a connection. See e.g., FIG. 11D. In some embodiment, the body 1105 and the sleeve 310, 410, 510 are attached via a threaded connection. Id.
FIG. 11F shows a cross-sectional view of the body 1105 and the sleeve 310, 410 and 510 of the downhole device 210 shown in FIG. 11E prior to a third step of assembly. FIG. 11G shows a cross-sectional view of the downhole device 210 of FIGS. 11A-11F after the third step of assembly.
As shown in FIGS. 11F and 11G, the body 1105 and the sleeve 310, 410 and 510 are attached via a connection. See e.g., FIGS. 11D-11E: 1105. In some embodiment, the body 1105 and the sleeve 310, 410, 510 are attached via a threaded connection. Id. In some embodiments, the body 1105 and the sleeve 310, 410 and 510 are attached via threaded connection and a snap ring. See e.g., FIG. 11G.

Alternative Downhole Device Configured as Selectable Hole Trimmer

As discussed above, FIG. 19A shows a view of another exemplary embodiment of the downhole device configured as a selectable hole trimmer 1900 without any bypass nozzles, showing a selectable hole cutter 1401 on the downhole device 1900 in a deactivated position; FIG. 19B shows a Section A-A cross-sectional view of the selectable hole trimmer 1900 of FIG. 19A, showing a deactivated cutter piston 1402, a body 120, 1905, an intermediate sleeve 1910 a, a sliding sleeve 1910 b, a hydraulic fluid port 1914, a compensating spring 1920 a, and a return spring 1920 b; FIG. 19C shows a Section C-C cross-sectional view of the selectable hole trimmer 1900 of FIG. 19A-19B, showing an intermediate sleeve 1910 a, and a sliding sleeve 1910 b.
As also discussed above, FIG. 21A shows a cross-sectional view of another exemplary embodiment of a downhole device configured as a selectable hole trimmer 2100, showing a selectable hole cutter 1401 on the downhole device 2100 in a deactivated position, an intermediate sleeve 2110 a, compensating sleeve 2110 c, a hydraulic fluid port 2114 and a stop block 1158; FIG. 21B shows a cross-sectional view of the exemplary selectable hole trimmer 2100 of FIG. 21A, showing an activated cutter piston 1402 with extended cutters 1406, the intermediate sleeve 2110 a, the compensating sleeve 2110 c, the hydraulic fluid port 2114 and the stop block 1158; FIG. 21C shows a detailed cross-sectional view of the exemplary selectable hole trimmer 2100 of FIG. 21A, showing a deactivated cutter piston 1402 with retracted cutters 1406, the intermediate sleeve 2110 a, the compensating sleeve 2110 c, the hydraulic fluid port 2114 and the stop block 1158; FIG. 21D shows a detailed cross-sectional view of the exemplary selectable hole trimmer 2100 of FIG. 21B, showing the activated cutter piston 1402 with extended cutters 1406; FIG. 21E shows a detailed cross-sectional view of the exemplary hole trimmer 2100 of FIGS. 21A and 21C; FIG. 21F shows a detailed view of the exemplary hole trimmer 2100 of FIGS. 21B and 21D; and FIG. 21G shows an upper, left perspective view of the exemplary selectable hole trimmer 2100 of FIGS. 21A-21F, showing the activated cutter piston 1402 with extended cutters 1406.
As shown in FIGS. 19A-19C and 21A-21G, a downhole device 1900, 2100 comprises an intermediate sleeve 1910 a, 2110 a, a sliding sleeve/pressure compensating piston 1910 b or a sliding sleeve 2110 b, a hydraulic fluid port 1914, 2114, a compensating port 1915, 2115, a volume 1921 b (between the intermediate sleeve 1910 a and the sliding sleeve/pressure compensating piston 1910 b) or a compensating sleeve 2110 c, a volume 1922, 2122 (between the intermediate sleeve 1910 a, 2110 a and the body 1905, 2105) and one or more selectable hole cutters 1401.
In an embodiment, the one or more selectable hole cutters 1401 comprises one or more cutter pistons 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402.
In an embodiment, the one or more selectable hole cutters 1401 comprises a cutter blade 1406 a and one or more cutter pistons 1402. In an embodiment, the cutter blade 1406 a has one or more cutter pistons 1402 affixed to the cutter blade 1406 a. In an embodiment, the cutter blade 1406 a has one or more cutters 1406 affixed to the cutter blade 1406 a.
When the downhole device 1900, 2100 is sliding or tripping into or out of a borehole, the downhole device 1900, 2100, namely the one or more selectable hole cutters 1401 are in a deactivated position. The one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also the deactivated position.
The body 1905, 2105 of the selectable hole trimmer 1900, 2100 is attached to the intermediate sleeve 1910 a, 2110 a via the stop block 1158.
As the downhole device 1900 is lowered in the borehole, the hydrostatic pressure pushes a sliding sleeve/pressure compensating piston 1910 b down (to the right in FIG. 19B), which compresses hydraulic fluid in a pressurized volume 1922 (i.e., a hydraulic fluid chamber) as the sliding sleeve/pressure compensating piston 1910 b slides over the intermediate sleeve 1910 a.
Similarly, as the downhole device 2100 is lowered in the borehole, the hydrostatic pressure pushes a compensating sleeve 2110 c down (to the right in FIG. 21A), which compresses hydraulic fluid in a pressurized volume 2122 (i.e., a hydraulic fluid chamber) as the compensating sleeve 2110 c slides over the intermediate sleeve 2110 a.
Until the downhole device 1900, 2100 is signaled to activate, the one or more selectable hole cutters 1401 will remain in the deactivated position. In other words, the one or more cutter pistons 1402 will remain in the deactivated position with the one or more cutters 1406 also in the deactivated position.
When the downhole device 1900, 2100 is sliding or tripping into or out of the borehole, the one or more selectable hole cutters 1401 are designed to be in a deactivated position. In other words, the one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also in the deactivated position.
When the drill string 120 is rotating, the one or more selectable hole cutters 1401 are designed to be in an activated position. In other words, the one or more cutter pistons 1402 are in the activated position with one or more cutters 1406 also in the activated position.
As shown in FIGS. 19A, 19C and 21A-21B, a downhole device 1900, 2100 comprises the battery 610, the controller/electronics 620, 700, and the motor pump 440.
As discussed above, the downhole device 1900, 2100 may activated automatically by rpm, by pressure or by other means by the controller/electronics 620, 700 in pockets 1930.
In an embodiment, a two-way valve 2250 is part of the controller/electronics 620, 700 located in the pockets 1930. When the downhole device 1900, 2100 receives a signal by rpm or by other means to activate the one or more selectable hole cutters 1401, then a pre-pressurized hydraulic fluid passes from the compensating sleeve 2110 c through a compensating port 1915, 2115 to open the two-way valve 2250, 2150 a. The open two-way valve 2250, 2250 a allows the pressured hydraulic fluid to pass through one or more hydraulic fluid ports 1914, 2114 to pressurize a volume 1922, 2122 (i.e., hydraulic fluid chamber) and to activate one or more selectable hole cutters 1401.
In an embodiment, the one or more of the hydraulic fluid ports 1914, 2114 may be located at each end of the downhole tool 1900, 2100 radially inward of the one or more cutter pistons 1402.
This pressurized hydraulic fluid activates the one or more cutter pistons 1402 of the selectable hole cutters 1401, which extends the one or more cutter pistons 1402 and the one or more cutters 1406 outward radially to engage and cut a side surface of the drilled hole 130.
Until the downhole device 1900, 2100 is signaled to deactivate, the one or more selectable hole cutters 1401 will remain in the activated position. In other words, the one or more cutter pistons 1402 will remain in the activated position with one or more cutters 1406 also in the activated position. The signal to deactivate may be by stopping rpm or by manual means from an operator.
When the downhole device 1900, 2100 receives the signal to deactivate, a pump 340, 440, 2240 in the pocket 1930 begins operating. The pump 340, 440, 2240 along with one or more springs 1410 forces the pressured hydraulic fluid away from the one or more cutter pistons 1402 and the two-way valve 2250 b is closed.
As such, the one or more selectable hole cutters 1401 are deactivated, returning the one or more cutter pistons 1402 back to the deactivated position via a spring 1410 and returning the pressurized hydraulic fluid back to the compensating sleeve 2110 c into the pressurized volume 2122 (i.e., pressurized hydraulic fluid chamber).
The downhole device 1900, 2100 is ready to operate and to activate the one or more selectable hole cutters 1401 again on demand or automatically when rotation resumes.
FIG. 22 shows a hydraulic schematic of an exemplary embodiment of a downhole device configured as a selectable hole trimmer 1900, 2100, showing a hydraulic fluid system 2200.
As shown in FIG. 22 , the hydraulic fluid system 2200 comprises a sliding sleeve/compensating piston 1910 b or a compensating sleeve 2110 c, a two-way valve 2250, 2250 a, 2250 b, a selectable hole cutter 1401, and a pump 2240.
In an embodiment, the downhole device 1900, 2100 may be activated by opening a first two-way valve 2250 a and deactivated by closing a second two-way valve 2250 b.
In an embodiment, the selectable hole cutter 1401 has a cutter piston 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402. In an embodiment, a spring 1410 and a spacer 1412 are disposed between the cutter piston 1402 and the container 1408 or cutout.
In an embodiment, the hydraulic fluid system 2200 may further comprise a fail-safe solenoid valve 2260. In an embodiment, the fail-safe solenoid valve 2260 may be in a normally open position.
In an event of a power failure, a hydraulic fluid leak, a temperate spike or other adverse situation, the fail-safe solenoid valve 2260 automatically switches to the normally open position to vent pressurized hydraulic fluid out of the downhole device 1900, 2100 to deactivate the one or more selectable hole cutters 1401. In other words, the one or more springs 1410 return the one or more cutter pistons 1402 to a deactivated position with one or more cutters 1406 also in the deactivated position. The downhole device 1900, 2100 may be retrieved from the borehole without any interference from the one or more selectable hole cutters 1401.

Method for Bypassing Drilling Fluids Using the Downhole Device

FIG. 9 shows a flow diagram of a method for bypassing drilling fluids from a downhole drill bit 900. As shown in FIG. 9 , the method for bypassing drilling fluids from a downhole drill bit 900 may include: providing a drill bit a flow of drilling fluids 902; determining whether a trigger condition has been satisfied 904; upon determining the trigger condition has been satisfied, actuating a sleeve to move relative to a body sealingly housing the sleeve 906; at least partially aligning a port in the sleeve to a nozzle of the body 908; and directing a portion of the flow of drilling fluids through the port and the nozzle to bypass the drill bit 910. In an embodiment, the flow of drilling fluids returns in an annulus.
In some embodiments, determining the satisfaction of the trigger condition 904 may include measuring a value related to a rotation speed of the downhole drill bit or a pressure of the drilling fluids or weight and comparing the measured value to a reference value.
In some other embodiments, determining the satisfaction of the trigger condition 904 may include receiving a control signal from a controller. For example, the control signal may be provided in response to a rotation protocol. In other instances, the control signal may also be determined based on depth, user input, or other operation feedbacks.
In some embodiments, determining the satisfaction of the trigger condition 904 may include comparing a pressure of the drilling fluids inside the drill string and a pressure of the drilling fluids in the annulus outside the drill string to ascertain a pressure difference and in some embodiments, actuating the sleeve to move relative to the body includes actuating a three-way valve in response to the pressure difference between the drilling fluids inside the drill string and the drilling fluids in the annulus.
In some other embodiments, comparing the pressure of the drill fluids inside the drill string and the pressure of the drilling fluids in the annulus outside the drill string may include receiving the drilling fluids inside the drill string in an accumulator or pressure compensator and receiving the drilling fluids in the annulus in another accumulator or pressure compensator.
In some embodiments, actuating the sleeve to move relative to the body 906 comprises actuating a three-way valve in response to the pressure difference between the drilling fluids inside the drill string and the drilling fluids in the annulus.
In some embodiments, actuating the sleeve to move relative to the body 906 may include sliding the sleeve inside the body, or rotating the sleeve inside the body, or both.
In some embodiments, the method further includes biasing the sleeve against the body to close the port from the nozzle upon determining the trigger condition has not been satisfied.
In some other embodiments, biasing the sleeve against the body to close the port from the nozzle may include offsetting the port from the nozzle using a spring.

Method for Bypassing Drilling Fluids Using Alternative Downhole Device

FIG. 12 shows a flow diagram of a method for bypassing drilling fluids from a downhole drill bit 1200. As shown in FIG. 12 , the method for bypassing drilling fluids from a downhole drill bit 1200 may include: providing a drill bit a flow of drilling fluids 1202; determining whether a trigger condition has been satisfied 1204; upon determining the trigger condition has been satisfied, actuating a sleeve to move relative to a body sealingly housing the sleeve 1206, and at least partially aligning a port in the sleeve to a nozzle of the body 1208; and directing a portion of the flow of drilling fluids through the port and the nozzle to bypass the drill bit 1210. In an embodiment, the flow of drilling fluids returns in an annulus. In an embodiment, a resilient member comprises a spring providing a biasing force corresponding to a threshold trigger pressure.
In some embodiments, determining the satisfaction of the trigger condition 1204 may include measuring a value related to a rotation speed of the downhole drill bit or a pressure of the drilling fluids or weight and comparing the measured value to a reference value.
In some other embodiments, determining the satisfaction of the trigger condition 1204 may include receiving a control signal from a controller. For example, the control signal may be provided in response to a rotation protocol. In other instances, the control signal may also be determined based on depth, user input, or other operation feedbacks.
In some embodiments, determining the satisfaction of the trigger condition 1204 may include comparing a pressure of the drilling fluids inside the drill string and a pressure of the drilling fluids in the annulus outside the drill string to ascertain a pressure difference and in some embodiments, actuating the sleeve to move relative to the body includes actuating a three-way valve in response to the pressure difference between the drilling fluids inside the drill string and the drilling fluids in the annulus.
In some other embodiments, comparing the pressure of the drill fluids inside the drill string and the pressure of the drilling fluids in the annulus outside the drill string may include receiving the drilling fluids inside the drill string in an accumulator or pressure compensator and receiving the drilling fluids in the annulus in another accumulator or pressure compensator.
In some embodiments, actuating the sleeve to move relative to the body 1206 comprises actuating a three-way valve in response to the pressure difference between the drilling fluids inside the drill string and the drilling fluids in the annulus.
In some embodiments, actuating the sleeve to move relative to the body 1206 may include sliding the sleeve inside the body, or rotating the sleeve inside the body, or both.
In some embodiments, the method further includes biasing the sleeve against the body to close the port from the nozzle upon determining the trigger condition has not been satisfied.
In some other embodiments, biasing the sleeve against the body to close the port from the nozzle may include offsetting the port from the nozzle using a coil spring.

Method of Using Downhole Device Configured as Selectable Hole Trimmer

FIG. 20 shows a flow diagram of a method of using a downhole device configured as a selectable hole trimmer 2000. As shown in FIG. 20 , a method of using a downhole device as a selectable hole trimmer 2000 may include: providing a drill bit a flow of drilling fluids 2002; determining whether a trigger condition has been satisfied 2004; upon determining the trigger condition has been satisfied, actuating a sleeve to move relative to a body sealingly housing the sleeve 2006; at least partially aligning a port in the sleeve to a nozzle and an activation port in the sleeve to a selectable hole cutter 2008; and directing a portion of the flow of drilling fluids through the port to the nozzle to bypass the drill bit and through the activation port to the selectable hole cutter to activate a cutter piston 2010.
In an embodiment, the flow of drilling fluids returns in an annulus. In an embodiment, a resilient member comprises a spring providing a biasing force corresponding to a threshold trigger pressure.
In some embodiments, determining the satisfaction of the trigger condition 2004 may include measuring a value related to a rotation speed of the downhole drill bit or a pressure of the drilling fluids or weight and comparing the measured value to a reference value.
In some other embodiments, determining the satisfaction of the trigger condition 2004 may include receiving a control signal from a controller. For example, the control signal may be provided in response to a rotation protocol. In other instances, the control signal may also be determined based on depth, user input, or other operation feedbacks.
In some embodiments, determining the satisfaction of the trigger condition 2004 may include comparing a pressure of the drilling fluids inside the drill string and a pressure of the drilling fluids in the annulus outside the drill string to ascertain a pressure difference and in some embodiments, actuating the sleeve to move relative to the body includes actuating a three-way valve in response to the pressure difference between the drilling fluids inside the drill string and the drilling fluids in the annulus.
In some other embodiments, comparing the pressure of the drill fluids inside the drill string and the pressure of the drilling fluids in the annulus outside the drill string may include receiving the drilling fluids inside the drill string in an accumulator or pressure compensator and receiving the drilling fluids in the annulus in another accumulator or pressure compensator.
In some embodiments, actuating the sleeve to move relative to the body 2006 comprises actuating a three-way valve in response to the pressure difference between the drilling fluids inside the drill string and the drilling fluids in the annulus.
In some embodiments, actuating the sleeve to move relative to the body 2006 may include sliding the sleeve inside the body, or rotating the sleeve inside the body, or both.
In some embodiments, the method further includes biasing the sleeve against the body to close the port from the nozzle and the activation port from the selectable hole cutter upon determining the trigger condition has not been satisfied.
In some other embodiments, biasing the sleeve against the body to close the port from the nozzle and the activation port from selectable hole cutter may include offsetting the port from the nozzle and the activation port from the selectable hole cutter using a coil spring.
In some other embodiments, the method further comprises increasing a diameter of a borehole using the activated selectable hole cutter.

Method of Using Alternative Downhole Device Configured as Selectable Hole Trimmer

FIG. 23A shows a flow diagram of another method of using a downhole device configured as a selectable hole trimmer; FIG. 23B shows a flow diagram of additional steps for the method of FIG. 23A; and FIG. 23C shows a flow diagram of additional steps for the method of FIGS. 23A-23B.
In an embodiment, a method of using a downhole device as a selectable hole trimmer 2300 may include: providing a drill bit a flow of drilling fluids 2302; determining whether a trigger condition has been satisfied 2304; upon determining the trigger condition has been satisfied, opening a valve in a control system to pressurize a volume 2306; at least partially pressurizing an activation port to a selectable hole cutter of the body 2308; and directing a portion of the flow of drilling fluids through the activation port to the selectable hole cutter to activate the cutter piston 2310.
As shown in FIG. 23B, the method 2300 may further include: determining whether a second trigger condition has been satisfied 2312; upon determining the second trigger condition has been satisfied, operating a pump in the control system to return the drilling fluids to the volume and to deactivate the cutter piston 2314; and closing the valve in the control system 2316.
As shown in FIG. 23C, the method may further include in an event of a power failure, a hydraulic fluid leak or a temperature spike, opening a fail-safe valve to vent drilling fluids and to deactivate the cutter piston 2318.
In an embodiment, the flow of drilling fluids returns in an annulus.
In some embodiments, determining the satisfaction of the trigger condition 2004 may include measuring a value related to a rotation speed of the downhole drill bit or a pressure of the drilling fluids or weight and comparing the measured value to a reference value.
In some other embodiments, determining the satisfaction of the trigger condition 2304 may include receiving a control signal from a controller. For example, the control signal may be provided in response to a rotation protocol. In other instances, the control signal may also be determined based on depth, user input, or other operation feedbacks.
In some embodiments, determining the satisfaction of the trigger condition 2304 may include comparing a pressure of the drilling fluids inside the drill string and a pressure of the drilling fluids in the annulus outside the drill string to ascertain a pressure difference.
In some other embodiments, comparing the pressure of the drill fluids inside the drill string and the pressure of the drilling fluids in the annulus outside the drill string may include receiving the drilling fluids inside the drill string in an accumulator or pressure compensator and receiving the drilling fluids in the annulus in another accumulator or pressure compensator.
In some other embodiments, the method further comprises increasing a diameter of a borehole using the activated cutter piston.

Second Alternative Downhole Device Configured as Selectable Hole Trimmer

FIG. 24 shows a partial cross-sectional view of an exemplary embodiment of a downhole device configured as a selectable hole trimmer 2400, showing a selectable hole cutter 1401 on the downhole device 2400 in a deactivated position, a dual solenoid compensating sleeve 2410 d, an annular compensating ring 2410 e, a volume/waste ring 2410 f, a hydraulic fluid port 2414 and a hydraulic fluid waste port 2414 a. As shown in FIG. 24 , the selectable hole trimmer 2400 comprises a dual solenoid compensating sleeve 2410 d, an annular compensating ring 2410 e, a volume/waste ring 2410 f, a hydraulic fluid port 2414, a hydraulic fluid waste port 2414 a, a dual solenoid valve 2418, a drilling mud volume 2422 a, a waste volume 2422 b, a pressurized volume 2422 c and one or more selectable hole cutters 1401.
In an embodiment, the selectable hole trimmer further comprises a drilling mud port 2414 b, a one-way valve 2419 and a hydraulic fluid return spring 2420 c.
In an embodiment, the one or more selectable hole cutters 1401 comprises one or more cutter pistons 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402.
In an embodiment, the one or more selectable hole cutters 1401 comprises a cutter blade 1406 a and one or more cutter pistons 1402. In an embodiment, the cutter blade 1406 a has one or more cutter pistons 1402 affixed to the cutter blade 1406 a. In an embodiment, the cutter blade 1406 a has one or more cutters 1406 affixed to the cutter blade 1406 a.
When the downhole device 2400 is sliding or tripping into or out of a borehole, the downhole device 2400, namely the one or more selectable hole cutters 1401 are in a deactivated position. The one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also the deactivated position.
The body 2405 of the selectable hole trimmer 2400 may be attached to the dual solenoid compensating sleeve 2410 d via a connection. In an embodiment, the body 2405 of the selectable hole trimmer 2400 may be attached to the dual solenoid compensating sleeve 2410 d via a threaded connection (e.g., threaded nut). In some embodiments, the dual solenoid compensating sleeve 2410 d is held in place with a hydraulic fluid return spring 2420 c at a lower end and a snap ring (not shown) at an upper end.
As the downhole device 2400 is lowered in the borehole, the hydrostatic pressure in a drilling mud volume 2422 a pushes an annular compensating ring 2410 e downward (to the right in FIG. 24 ), which compresses hydraulic fluid in a pressurized waste volume 2422 b (i.e., a hydraulic fluid chamber).
Similarly, the hydrostatic pressure in the pressurized waste volume 2422 b pushes a volume/waste ring 2410 f downward (to the right in FIG. 24 ), which compresses hydraulic fluid in a pressurized volume 2422 c (i.e., a hydraulic fluid chamber).
Until the downhole device 2400 is signaled to activate, the one or more selectable hole cutters 1401 will remain in the deactivated position. In other words, the one or more cutter pistons 1402 will remain in the deactivated position with the one or more cutters 1406 also in the deactivated position.
When the downhole device 2400 is sliding or tripping into or out of a borehole, the downhole device 2400, namely the one or more selectable hole cutters 1401 are in a deactivated position. The one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also the deactivated position.
As the downhole device 2400 is lowered in the borehole, the hydrostatic pressure of the drilling mud between inside the downhole device 2400 and outside annulus 122 by way of typical pressure drops through drill string components below the selectable hole trimmer 2400. In an embodiment, a pressure differential (between the inside pressure and the outside annulus pressure) may be greater than or equal to about 100 psi, and any range or value there between. In an embodiment, the pressure differential may be greater than or equal to about 1,000 psi.
As the downhole device 2400 is lowered in the borehole, the hydrostatic pressure in a drilling mud volume 2422 a pushes an annular compensating ring 2410 e downward (to the right in FIG. 24 ), which compresses hydraulic fluid in a pressurized waste volume 2422 b (i.e., a hydraulic fluid chamber).
Similarly, the hydrostatic pressure in the pressurized waste volume 2422 b pushes a volume/waste ring 2410 f downward (to the right in FIG. 24 ), which compresses hydraulic fluid in a pressurized volume 2422 c (i.e., a hydraulic fluid chamber).
Until the downhole device 2400 is signaled to activate, the one or more selectable hole cutters 1401 will remain in the deactivated position. In other words, the one or more cutter pistons 1402 will remain in the deactivated position with the one or more cutters 1406 also in the deactivated position.
When the downhole device 2400 is sliding or tripping into or out of the borehole, the one or more selectable hole cutters 1401 are designed to be in a deactivated position. In other words, the one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also in the deactivated position.
When the drill string 120 is rotating, the one or more selectable hole cutters 1401 are designed to be in an activated position. In other words, the one or more cutter pistons 1402 are in the activated position with one or more cutters 1406 also in the activated position.
As shown in FIGS. 19A, 19C and 21A-21B, a downhole device 1900, 2100, 2400 comprises the battery 610, the controller/electronics 620, 700, and the motor pump 440. However, the downhole device 2400 does not require a motor pump 440.
As discussed above, the downhole device 1900, 2100, 2400 may activated automatically by rpm, by pressure or by other means by the controller/electronics 620, 700 in pockets 1930.
In an embodiment, the dual solenoid valve 2418 is part of the controller/electronics 620, 700 located in the pockets 1930. When the downhole device 1900, 2400 receives a signal by rpm or by other means to activate the one or more selectable hole cutters 1401, the dual solenoid valve 2418 is switched to an open position. The open dual solenoid valve 2418 allows the pressured hydraulic fluid to pass through one or more hydraulic fluid ports 2414 to activate one or more selectable hole cutters 1401.
In an embodiment, the one or more of the hydraulic fluid ports 2414 may be located at each end of the downhole tool 2400 radially inward of the one or more cutter pistons 1402.
This pressurized hydraulic fluid activates the one or more cutter pistons 1402 of the selectable hole cutters 1401, which extends the one or more cutter pistons 1402 and the one or more cutters 1406 outward radially to engage and cut a side surface of the drilled hole 130.
Until the downhole device 2400 is signaled to deactivate, the one or more selectable hole cutters 1401 will remain in the activated position. In other words, the one or more cutter pistons 1402 will remain in the activated position with one or more cutters 1406 also in the activated position. The signal to deactivate may be by stopping rpm or by manual means from an operator.
When the downhole device 2400 receives the signal to deactivate, the dual solenoid valve 2418 is switched to a closed position. The closed dual solenoid valve 2418 allows the pressurized hydraulic fluid to pass through the hydraulic fluid waste port 2414 a into the waste volume 2422 b. The annular compensating ring 2410 e moves slightly upward (to the left in FIG. 24 ) to make room for the hydraulic fluid waste and forces pressurized drilling mud out of the downhole device 2400 through the drilling mud port 2414 b.
As such, the one or more selectable hole cutters 1401 are deactivated, returning the one or more cutter pistons 1402 back to the deactivated position via a spring 1410.
The downhole device 2400 is ready to operate and to activate the one or more selectable hole cutters 1401 again on demand or automatically when rotation resumes.
In an embodiment, the downhole device 2400 may be activated by opening a dual solenoid valve 2418 and deactivated by closing the dual solenoid valve 2418.
In an embodiment, the selectable hole cutter 1401 has a cutter piston 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402. In an embodiment, a spring 1410 and a spacer 1412 are disposed between the cutter piston 1402 and the container 1408 or cutout.
When the flow of drilling mud stops (e.g., drilling rig pumps are shut-off), the one or more selectable hole cutters 1401 will be in a deactivated position. The pressure differential across the volume/waste ring is negligible. The hydraulic fluid return spring 2420 c decompresses and moves the volume/waste ring upward (to left in FIG. 24 ).
As a result, hydraulic fluid waste in the waste volume 2422 b is forced through the one-way valve 2419 in the volume/waste ring 2410 f into the pressurized volume 2422 c. This recharges the pressurized volume 2422 c so that it does not run out of hydraulic fluid as the downhole device cycles.
The downhole device 2400 is ready to operate and to activate the one or more selectable hole cutters 1401 again on demand or automatically when rotation resumes.
In an embodiment, the downhole device 2400 may be activated by opening a dual solenoid valve 2418 and deactivated by closing the dual solenoid valve 2418.
In an embodiment, the hydraulic fluid system 2200 may further comprise a fail-safe solenoid valve 2260. In an embodiment, the fail-safe solenoid valve 2260 may be in a normally open position.
In an event of a power failure, a hydraulic fluid leak, a temperate spike or other adverse situation, the fail-safe solenoid valve 2260 automatically switches to the normally open position to vent pressurized hydraulic fluid out of the downhole device 2400 to deactivate the one or more selectable hole cutters 1401. In other words, the one or more springs 1410 return the one or more cutter pistons 1402 to a deactivated position with one or more cutters 1406 also in the deactivated position. The downhole device 2400 may be retrieved from the borehole without any interference from the one or more selectable hole cutters 1401.

Third Alternative Downhole Device Configured as Selectable Hole Trimmer

FIG. 25A shows a cross-sectional view of an exemplary embodiment of a downhole device configured as a selectable hole trimmer 2500, showing a selectable hole cutter 1401 in a deactivated position, an intermediate sleeve 2510 a, a sliding sleeve 2510 b, a hydraulic fluid port 2514, an activation dart 2540, a seat 2544, a hydraulic fluid port 2514 and a stop lock 2550; and FIG. 25B shows a cross-sectional view of the selectable hole trimmer 2500 of FIG. 25B, showing an alternative sliding sleeve 2510 b. As shown in FIGS. 25A and 25B, the selectable hole trimmer 2500 comprises an intermediate sleeve 2510 a, a sliding sleeve 2510 b, a hydraulic fluid port 2514, a lower port 2516, an upper port 2517, a volume 2522 (between the intermediate sleeve 2510 a and the body 2505) and one or more selectable hole cutters 1401.
In an embodiment, the one or more selectable hole cutters 1401 comprises one or more cutter pistons 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402.
In an embodiment, the one or more selectable hole cutters 1401 comprises a cutter blade 1406 a and one or more cutter pistons 1402. In an embodiment, the cutter blade 1406 a has one or more cutter pistons 1402 affixed to the cutter blade 1406 a. In an embodiment, the cutter blade 1406 a has one or more cutters 1406 affixed to the cutter blade 1406 a.
When the downhole device 2500 is sliding or tripping into or out of a borehole, the downhole device 2500, namely the one or more selectable hole cutters 1401 are in a deactivated position. The one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also the deactivated position.
The body 2505 of the selectable hole trimmer 2500 is attached to the intermediate sleeve 2510 a via a stop lock 2550.
After the downhole device 2500 is lowered in the borehole and an activation dart 2540 is dropped to seal a seat 2544 in the sliding sleeve 2510 b, the hydrostatic pressure of the drilling mud on the activation dart 2640 in the seat 2644 forces the sliding sleeve 2610 h to move down and to align the lower port 2516 and the upper port 2517, which compresses a return spring 2520 b and moves the sliding sleeve 2510 b downward. See e.g., 25A.
In an embodiment, an upper port 2517 in the sliding sleeve 2510 b aligns with a lower port 2516 in the intermediate sleeve 2510 a to pressurize a top of a divider seal ring 2546 with drilling mud. See e.g., FIG. 25A.
Alternatively, the sliding sleeve 2510 b moves downward and presses on the top of the divider seal ring 2546. See e.g., FIG. 25B.
The divider seal ring 2546 moves downward and forces pressurized hydraulic fluid to pass through one or more hydraulic fluid ports 2514 to pressurize a volume 2522 (i.e., hydraulic fluid chamber) and to activate one or more selectable hole cutters 1401. Id.
This pressurized hydraulic fluid activates the one or more cutter pistons 1402 of the selectable hole cutters 1401, which extends the one or more cutter pistons 1402 and the one or more cutters 1406 outward radially to engage and cut a side surface of the drilled hole 130.
The activation dart 2540 may be made of any suitable material to seal a seat 2544 in the sliding sleeve 2510 b. For example, a suitable material includes, but is not limited to, a metal, a polymer, a rubber or other similar material. In an embodiment, the activation dart 2540 is made of a metal. In an embodiment, the activation dart 2540 is made of a polymer.
The deactivation ball 2542 may be any suitable size to seal a port 2541 in the activation dart 2540. For example, a suitable size includes, but is not limited to from about 1 inch to about 2.75 inch diameter and any range or value there between.
The seat 2544 in the sliding sleeve 2510 b may be made of any suitable material. For example, a suitable material includes, but is not limited to, a polymer, a rubber or other similar material. In an embodiment, the seat 2544 is made of a polymer. In an embodiment, the seat 2544 is made of a polyurethane.
Until the downhole device 2500 is manually signaled to activate, the one or more selectable hole cutters 1401 will remain in the deactivated position. In other words, the one or more cutter pistons 1402 will remain in the deactivated position with the one or more cutters 1406 also in the deactivated position.
When the downhole device 2500 is sliding or tripping into or out of the borehole, the one or more selectable hole cutters 1401 are designed to be in a deactivated position. In other words, the one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also in the deactivated position. The signal to activate may be by manual means from an operator.

Manual Actuation

When the downhole device 2500 is sliding or tripping into or out of a borehole, the downhole device 2500, namely the one or more selectable hole cutters 1401 are in a deactivated position. The one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also the deactivated position.
The body 2505 of the selectable hole trimmer 2500 is attached to the intermediate sleeve 2510 a via the stop lock 2550.
As the downhole device 2500 is lowered in the borehole, the hydrostatic pressure pushes a sliding sleeve 2510 b downward, which compresses hydraulic fluid in a pressurized volume 2522 (i.e., a hydraulic fluid chamber) as the sliding sleeve 2510 b slides over the intermediate sleeve 2510 a.
Until the downhole device 2500 is manually signaled to activate, the one or more selectable hole cutters 1401 will remain in the deactivated position. In other words, the one or more cutter pistons 1402 will remain in the deactivated position with the one or more cutters 1406 also in the deactivated position.
When the downhole device 2500 is sliding or tripping into or out of the borehole, the one or more selectable hole cutters 1401 are designed to be in a deactivated position. In other words, the one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also in the deactivated position. The signal to activate may be by manual means from an operator.
When the downhole device 2500 is manually signaled to activate, an activation dart 2540 is dropped to seal a seat 2544 in the sliding sleeve 2510 b, to increase the pressure of the drilling mud above the sealed dart 2540 and to provide by-pass flow of the drilling mud to the drill bit 132. The pressure of the drilling mud compresses the return spring 2520 b and moves the sliding sleeve 2510 b downward.
In an embodiment, an upper port 2517 in the sliding sleeve 2510 b aligns with a lower port 2516 in the intermediate sleeve 2510 a to pressurize a top of a divider seal ring 2546 with drilling mud. See e.g., FIG. 25A.
Alternatively, the sliding sleeve 2510 b moves downward and presses on the top of the divider sear ring 2546 with drilling mud. See e.g., FIG. 25B.
The divider seal ring 2546 moves downward and forces pressurized hydraulic fluid to pass through one or more hydraulic fluid ports 2514 to pressurize a volume 2522 (i.e., hydraulic fluid chamber) and to activate one or more selectable hole cutters 1401. Id.
In an embodiment, the one or more of the hydraulic fluid ports 2514 may be located at each end of the downhole tool 2500 radially inward of the one or more cutter pistons 1402.
This pressurized hydraulic fluid activates the one or more cutter pistons 1402 of the selectable hole cutters 1401, which extends the one or more cutter pistons 1402 and the one or more cutters 1406 outward radially to engage and cut a side surface of the drilled hole 130.
When the flow of drilling mud stops (e.g., drilling rig pumps are shut-off), the one or more selectable hole cutters 1401 will be in a deactivated position. This activation/deactivation of the one or more cutters 1406 is automatic for as long as the dart 2540 remains sealed in the seat 2544.
In an embodiment, the pressurized hydraulic fluid pushes the divider seal ring 2546 upwards and forces the drilling mud to flow through a check valve 2562, which bypasses an upper seal 2549. See e.g., FIG. 25A. The one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also the deactivated position.
Alternatively, the pressurized hydraulic fluid and return spring 2520 b forces the divider seal ring 2546 upwards. See e.g., FIG. 25B. The one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also the deactivated position.
Until the downhole device 2500 is manually signaled to deactivate (or until the flow of the drilling mud stops), the one or more selectable hole cutters 1401 will remain in the activated position. In other words, the one or more cutter pistons 1402 will remain in the activated position with one or more cutters 1406 also in the activated position. The signal to deactivate may be by manual means from an operator.
When the downhole device 2500 receives the signal to deactivate, a deactivation ball 2542 is dropped to seal a port 2541 through the activation dart 2540 and to stop the bypass flow of drilling mud to the drill bit 132. The pressure difference across the activation dart 2540 forces the activation dart 2540 through the seat 2544 along with the deactivation ball 2542 into a catcher basket 2570.
As such, the one or more selectable hole cutters 1401 are deactivated, returning the one or more cutter pistons 1402 back to the deactivated position via a spring 1410 and returning the pressurized hydraulic fluid back into the pressurized volume 2522 (i.e., pressurized hydraulic fluid chamber).
The downhole device 2500 is ready to operate and to activate the one or more selectable hole cutters 1401 again when another activation dart 2540 is dropped.
In an embodiment, the downhole device 2500 may be activated by dropping an activation dart 2540 and deactivated by dropping a deactivation ball 2542.
In an embodiment, the selectable hole cutter 1401 has a cutter piston 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402. In an embodiment, a spring 1410 and a spacer 1412 are disposed between the cutter piston 1402 and the container 1408 or cutout.

Automatic Actuation

As shown in FIGS. 19A, 19C and 21A-21B, a downhole device 1900, 2100, 2500 comprises the battery 610, the controller/electronics 620, 700, and the motor pump 440.
As discussed above, the downhole device 1900, 2100, 2500 may activated automatically by rpm, by pressure or by other means by the controller/electronics 620, 700 in pockets 1930.
For example, downhole device 2500 may include an alternative, controller/electronic controlled hydraulic fluid supply. See e.g., FIGS. 25A-25B.
In an embodiment, the hydraulic fluid system 2200 may further comprise a fail-safe solenoid valve 2260. In an embodiment, the fail-safe solenoid valve 2260 may be in a normally open position.
In an event of a power failure, a hydraulic fluid leak, a temperate spike or other adverse situation, the fail-safe solenoid valve 2260 automatically switches to the normally open position to vent pressurized hydraulic fluid out of the downhole device 2500 to deactivate the one or more selectable hole cutters 1401. In other words, the one or more springs 1410 return the one or more cutter pistons 1402 to a deactivated position with one or more cutters 1406 also in the deactivated position. The downhole device 2500 may be retrieved from the borehole without any interference from the one or more selectable hole cutters 1401.

Fourth Alternative Downhole Device Configured as Selectable Hole Trimmer

FIG. 26A shows a side view of an exemplary embodiment of a downhole device configured as a selectable hole trimmer 2600, showing a charge subassembly A and a trimmer subassembly B having a selectable hole cutter 1401 in a deactivated position; FIG. 26B shows a cross-sectional view of the selectable hole trimmer of FIG. 26A, showing the selectable hole cutter 1401 in a deactivated position; FIG. 26C shows a detailed view of the selectable hole cutter 1401 of the selectable hole trimmer of FIGS. 26A-26B, showing a cutter piston 1402, a cutter 1406, a spring 1410 and a retaining ring 1414; and FIG. 26D shows a cross-sectional view of the selectable hole cutter 1401 of FIG. 26C, showing the cutter piston 1402 and the cutter 1406. As shown in FIGS. 26A and 26B, the selectable hole trimmer 2600 comprises an upper sleeve 2610 g, a charge sleeve 2610 h, a catch sleeve 2610 i, a transfer sleeve 2610 j.
FIG. 26E shows a cross-sectional view of selectable hole trimmer of FIGS. 26A-26D, showing the selectable hole trimmer 2600 being activated with an activation ball 2640 a and a catch sleeve 2610 i being lowered downward to a lower position; FIG. 26F shows a cross-sectional view of selectable hole trimmer of FIGS. 26A-26D, showing the selectable hole trimmer 2600 in a deactivated position with an activation ball 2640 a in a seat 2644 in a catch sleeve 2610 j and with a charge sleeve 2610 h and the catch sleeve 2610 j in an upper position; FIG. 26G shows a cross-sectional view of selectable hole trimmer of FIGS. 26A-26D, showing the selectable hole trimmer 2600 in an activated position with an activation ball 2640 a in a seat 2644 of the catch sleeve 2510 j and with a charge sleeve 2610 h and the catch sleeve 2610 i in a lower position; FIG. 26H shows a detailed view of an upper end of the selectable hole trimmer 2600 of FIG. 26A-26B, showing the selectable hole trimmer 2600 in a deactivated position and a seat 2644 in the catch sleeve 2610 j; FIG. 26I shows a detailed view of the upper end of the selectable hole trimmer 2600 of FIGS. 26E-26G, showing the selectable hole trimmer 2600 in an activated position and an activation ball 2640 a in a seat 2644 in the catch sleeve 2610 j.
In an embodiment, the one or more selectable hole cutters 1401 comprises one or more cutter pistons 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402.
In an embodiment, the one or more selectable hole cutters 1401 comprises a cutter blade 1406 a and one or more cutter pistons 1402. In an embodiment, the cutter blade 1406 a has one or more cutter pistons 1402 affixed to the cutter blade 1406 a. In an embodiment, the cutter blade 1406 a has one or more cutters 1406 affixed to the cutter blade 1406 a.
When the downhole device 2600 is sliding or tripping into or out of a borehole, the downhole device 2600, namely the one or more selectable hole cutters 1401 are in a deactivated position. The one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also the deactivated position.
The body 2605 of the selectable hole trimmer 2600 may be attached to the upper sleeve 2610 g via a connection. In an embodiment, the body 2605 of the selectable hole trimmer 2600 may be attached to the upper sleeve 2610 g via a threaded connection (e.g., threaded nut).
In an embodiment, the upper sleeve is held in place with a snap ring (not shown) at an upper end. In an embodiment, the snap ring (not shown) may act as a stop.
In an embodiment, the upper sleeve 2610 g is held in place with a stop (not shown) at a lower end and a snap ring (not shown) at an upper end.
The upper sleeve 2610 g provides a radial spacer such that the cross-sectional area of the charge sleeve 2610 h is the same at a lower end and an upper end so that the charge sleeve 2610 h is not moved downward or upward due to hydrostatic pressure.
The upper sleeve 2610 g acts as an upper stop for the charge sleeve 2610 h.
After the downhole device 2600 is lowered in the borehole and the activation ball 2640 is dropped to seal a seat 2644 in the catch sleeve 2610 i, the hydrostatic pressure of the drilling mud on the activation ball 2640 in the seat 2644 disengages a detent ring 2611 (between the charge sleeve 2610 h and the catch sleeve 2610 i) and allows the catch sleeve 2610 i to move slightly downward to a lower position (to the right in FIG. 26E) within the charge sleeve 2610 h.
The activation ball 2640 a may be made of any suitable material to seal a seat 2644 in the catch sleeve 2610 i. For example, a suitable material includes, but is not limited to, a metal, a polymer, rubber or other similar material. In an embodiment, the activation ball 2640 a is made of metal. In an embodiment, the activation ball 2640 a is made of a polymer. In an embodiment, the activation ball 2640 a is made of a rubber.
The activation ball 2640 a may be any suitable size to seal the seat 2644 in the catch sleeve 2610 i. For example, a suitable size includes, but is not limited to from about 2.25 inch to about 2.75 inch diameter and any range or value there between. In an embodiment, the activation ball 2640 a is about 2.375 inches in diameter. In an embodiment, the activation ball 2640 a is about 2.5-inches in diameter.
The detent ring 2611 may be made from any suitable material. For example, a suitable material includes, but is not limited to a metal, a polymer, a rubber or other similar material. In an embodiment, the detent ring 2611 is made from a polymer. In an embodiment, the detent ring 2611 is made from a rubber. In an embodiment, the detent ring 2611 is made from a metal. In an embodiment, the detent ring 2611 may be a metal C-ring.
In an embodiment, the detent ring 2611 is disposed between the charge sleeve 2610 h and the catch sleeve 2610 i. In an embodiment, the detent ring 2611 holds the catch sleeve 2610 i in relative position to the charge sleeve 2610 h.
The drilling mud flows from the charge sleeve 2610 h through a bypass port 2617 a into a drilling mud volume 2622 a in the body 2605. Then, the drilling mud flows from the drilling mud volume 2622 a through a return port 2616 a in the charge sleeve 2610 h and in the catch sleeve 2610 i back into the interior of the charge sleeve 2610 h to provide a bypass flow of drilling mud to the drill bit 132.
The charge sleeve 2610 h moves downward to a lower position (to the right in FIG. 26G) and forces pressurized hydraulic fluid through the hydraulic fluid ports 2614 in the transfer sleeve 2610 j and through the hydraulic ports 2414 a along an outer diameter of the transfer sleeve 2610 j to activate one or more selectable hole cutters 1401.
This pressurized hydraulic fluid activates the one or more cutter pistons 1402 of the selectable hole cutters 1401, which extends the one or more cutter pistons 1402 and the one or more cutters 1406 outward radially to engage and cut a side surface of the drilled hole 130.
In an embodiment, the charge sleeve 2610 h has an internal stop (not shown) to prevent the catch sleeve 2610 i from moving further downward. In an embodiment, the charge sleeve 2610 h has the internal stop (not shown) at about an axial mid-position to prevent the catch sleeve 2610 i from moving further downward.
Until the downhole device 2600 is manually signaled to activate, the one or more selectable hole cutters 1401 will remain in the deactivated position. In other words, the one or more cutter pistons 1402 will remain in the deactivated position with the one or more cutters 1406 also in the deactivated position.
When the downhole device 2600 is sliding or tripping into or out of a borehole, the downhole device 2600, namely the one or more selectable hole cutters 1401 are in a deactivated position. The one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also the deactivated position.
Until the downhole device 2600 is manually signaled to activate, the one or more selectable hole cutters 1401 will remain in the deactivated position. In other words, the one or more cutter pistons 1402 will remain in the deactivated position with the one or more cutters 1406 also in the deactivated position.
When the downhole device 2600 is sliding or tripping into or out of the borehole, the one or more selectable hole cutters 1401 are designed to be in a deactivated position. In other words, the one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also in the deactivated position. The signal to activate may be by manual means from an operator.

Manual Actuation

When the downhole device 2600 is manually signaled to activate, the activation ball 2640 is dropped to seal the seat 2644 on the catch sleeve 2610 i, to increase the hydrostatic pressure of the drilling mud above the sealed ball 2640. The hydrostatic pressure of the drilling mud on the activation ball 2640 in the seat 2644 disengages the detent ring 2611 (between the charge sleeve 2610 h and the catch sleeve 2610 i) and allows the catch sleeve 2610 i to move slightly downward to the lower position (to the right in FIG. 26E) within the charge sleeve 2610 h.
The drilling mud flows from the charge sleeve 2610 h through the bypass port 2617 a into a drilling mud volume 2622 a in the body 2605. Then, the drilling mud flows from the drilling mud volume 2622 a through the return port 2616 a in the charge sleeve 2610 h and in the catch sleeve 2610 i back into the interior of the charge sleeve 2610 h to provide the bypass flow of drilling mud to the drill bit 132.
The charge sleeve 2610 h moves downward to the lower position and forces pressurized hydraulic fluid through the hydraulic fluid ports 2614 in the transfer sleeve 2610 j and through the hydraulic ports 2414 a along an outer diameter of the transfer sleeve 2610 j to activate one or more selectable hole cutters 1401.
This pressurized hydraulic fluid activates the one or more cutter pistons 1402 of the selectable hole cutters 1401, which extends the one or more cutter pistons 1402 and the one or more cutters 1406 outward radially to engage and cut a side surface of the drilled hole 130.
Until the flow of the drilling mud stops), the one or more selectable hole cutters 1401 will remain in the activated position. In other words, the one or more cutter pistons 1402 will remain in the activated position with one or more cutters 1406 also in the activated position.
When the flow of drilling mud stops (e.g., drilling rig pumps are shut-off), the one or more selectable hole cutters 1401 will be in a deactivated position. As such, the one or more selectable hole cutters 1401 are deactivated via the spring 1410, returning the one or more cutter pistons 1402 back to the deactivated position via a spring 1410 and returning the charge sleeve 2610 h and catch sleeve 2610 i upward to their upper positions due to increased hydraulic fluid pressure. See e.g., FIG. 26F.
The downhole device 2600 is ready to operate and to activate the one or more selectable hole cutters 1401 again when the flow of drilling mud continues.
When the flow of drilling mud continues (e.g., drilling rig pumps are turned on), the charge sleeve 2610 h and the catch sleeve 2610 i will move downward again to the lower position (to the right in FIG. 26G), as discussed above.
When the flow of drilling mud stops (e.g., drilling rig pumps are shut-off), the one or more selectable hole cutters 1401 will be in a deactivated position. As such, the one or more selectable hole cutters 1401 are deactivated via the spring 1410, returning the one or more cutter pistons 1402 back to the deactivated position via a spring 1410 and returning the charge sleeve 2610 h upward to the upper position (to the left in FIG. 26F) due to increased hydraulic fluid pressure. See e.g., FIG. 26F.
The downhole device 2600 is ready to slide or trip out of the borehole.
When the downhole device 2600 is sliding or tripping out of the borehole, the drilling mud above the actuation ball in the charge sleeve drains through a port 2616 b into the drilling mud volume 2622 a. Then, the drilling mud drains from the drilling mud volume 2622 a through the return port 2616 a back into the interior of the charge sleeve 2610 h and out of the selectable hole trimmer 2600.
In an embodiment, the selectable hole cutter 1401 has a cutter piston 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402. In an embodiment, a spring 1410 and a spacer 1412 are disposed between the cutter piston 1402 and the container 1408 or cutout.
Method of Using Second Alternative Downhole Device Configured as Selectable Hole Trimmer
FIG. 27A shows a flow diagram of a method of using the selectable hole trimmer 2700 of FIG. 24 ; and FIGS. 27B-27D show flow diagrams of additional steps for the method 2700 of FIG. 27A. As shown in FIG. 27A, the method of using the selectable hole trimmer 2700 may include: providing a drill bit a flow of drilling fluids 2702; lowering a selectable hole trimmer in a borehole to move a solenoid compensating sleeve and a volume/waste ring downward to compress hydraulic fluid in a pressurized volume 2704; and directing the flow of hydraulic fluids from the pressurized volume through an activation port to a selectable hole cutter to activate the selectable hole cutter 2706.
As shown in FIG. 27B, the method 2700 may further include stopping the flow of drilling fluids through the selectable hole trimmer to deactivate the selectable hole cutter 2708.
As shown in FIG. 27C, the method 2700 may further include stopping the flow of drilling fluids through the selectable hole trimmer 2710 and directing the flow of the hydraulic fluids through a waste port into a waste volume to move an annular compensating ring upward, wherein the annular compensating ring forces the flow of the drilling fluids out of the selectable hole cutter through a drilling fluid port 2712.
As shown in FIG. 27D, the method 2700 may further include stopping the flow of the hydraulic fluids through the selectable hole trimmer to decompress a hydraulic return spring and to move a volume/waste ring upwards, wherein the volume/waste ring forces the flow of the hydraulic fluids in the waste volume through a one-way valve into the pressurized volume 2714.

Method of Using Third Alternative Downhole Device Configured as Selectable Hole Trimmer

FIG. 28A shows a flow diagram of a method of using the selectable hole trimmer 2800 of FIGS. 25A-25B; and FIGS. 28B-28C show flow diagrams of additional steps for the method 2800 of FIG. 28A. As shown in FIG. 28A, the method of using the selectable hole trimmer 2800 may include providing a drill bit a flow of drilling fluids 2802; lowering a selectable hole trimmer in a borehole 2804; and dropping an activation dart to seal a seat, compress a return spring and move the sliding sleeve downward to pressurize a top of a divider seal with the flow of the drilling fluids, wherein the divider seal ring moves downward and forces pressurized hydraulic fluids through an activation port to a selectable hole cutter to activate the selectable hole cutter 2806.
As show in FIG. 28B, the method 2800 may further include stopping the flow of the drilling fluids through the selectable hole trimmer to deactivate the selectable hole cutter 2808.
As shown in FIG. 28C, the method 2800 may further include dropping a deactivation ball to stop the flow of the drilling fluids through the selectable hole trimmer and to deactivate the selectable hole cutter 2810.

Method of Using Fourth Alternative Downhole Device Configured Selectable Hole Trimmer

FIG. 29A shows a flow diagram of a method 2900 of using the selectable hole trimmer 2600 of FIGS. 26A-26I; and FIGS. 29B-29C show flow diagrams of additional steps for the method 2900 of FIG. 29A. As shown in FIG. 29A, the method of using the selectable hole trimmer may include: providing a drill bit a flow of drilling fluids 2902; lowering a selectable hole trimmer in a borehole 2904; dropping an activation ball to seal a seat, disengage a detent ring between a charge sleeve and a catch sleeve and allow the charge sleeve to move downward to a lower position within the charge sleeve 2906; and directing the flow of the drilling fluids from the charge sleeve through a bypass port into a drilling fluid volume and from the drilling fluid volume through a return port back into an interior of the charge sleeve to move the charge sleeve downward, wherein the charge sleeve forces hydraulic fluid through an activation port to a selectable hole cutter to activate a selectable hole cutter 2908.
As shown in FIG. 29B, stopping the flow of the drilling fluids through the selectable hole trimmer to deactivate the selectable hole cutter 2910.
As shown in FIG. 29C, stopping the flow of the drilling fluids through the selectable hole trimmer 2912; raising the selectable hole trimmer in the borehole 2914; and draining drilling fluids from above the actuation ball in the charge sleeve through a port into the drilling mud volume and from the drilling mud volume through the return port back into the interior of the charge sleeve and out of the selectable hole trimmer 2916.

SUMMARY

This disclosure presents a downhole device and method to trigger, shift, and/or operate a downhole device (e.g., a selectable hole trimmer) of a drilling string in a wellbore. At a high level, the disclosed device causes cutters to extend and may cause a portion of drilling fluids to bypass the drill bit and into the annulus. The tool operation may be triggered upon certain conditions related to the flow rate of drilling fluids or other conditions such as the rotation speeds of the drill string, pressure of the drilling fluids, or the like. For example, the drill string may receive a flow of drilling fluids at a standard operational flow rate (e.g., 300 gallons per minute (gpm). The drill string may receive increased flow rates of drilling fluid (e.g., 500 gpm, 600 gpm, 700 gpm, etc.), decreased flow rates of drilling fluid, and/or no flowrate of drilling fluid (e.g., a 0 gpm flow rate). Variations in the flow rate may provide a recognizable series of signals to a downhole device that extend/retract cutter pistons, communicate to pumps or valves to operate, or pause/stop operations. In other instances, the bypass may be triggered in response to changes in the drill string weight, which may be varied in a recognizable fashion such that a load cell may send signals to a microprocessor and open or close valves or pump. The internal drill string pressure variations may be distinctive and recognizable by a pressure transducer in the downhole device. Such variations may then trigger a microprocessor to send further signals to start/stop a pump or open/close a bypass valve or port in the disclosed device.
The disclosed device and method of bypassing drilling fluids from the drill bit may be used in various situations. For example, the use of rotation rate (e.g., revolutions per minute, or rpm) recognition or other methods may be used to start a pump or open/close valves and flow paths for the drilling mud to bypass some or all of the drilling mud from the drill string to the annulus. The bypass fluids may also be used to power other devices or provide a source of data for measurements. Also, one of the primary purposes for the bypass flow through the nozzles is that it can provide mud flow to cool and clean the cutters on the pistons and to prevent a pressure lock if the tool fails and the sleeve seals the pistons in the out position.
In some aspects, the techniques described herein relate to a downhole device configured as a selectable hole trimmer including: a sliding sleeve moveably disposed inside a tool body having an upstream end and a downstream end, the tool body including a drilling fluid volume and wherein the sliding sleeve is disposed within and slidable inside the tool body to provide a pressure to a pressurized volume; an orifice sleeve moveably disposed inside the sliding sleeve, wherein the orifice sleeve is slidable inside the sliding sleeve to selectively engage and disengage a latch mechanism from a body groove of the tool body; an actuator connected to the pressurized volume and configured to provide the pressure to a selectable hole cutter of the tool body to actuate the selectable hole cutter between a retracted state and an extended state; wherein: the orifice sleeve is configured to receive a flow of drilling fluids at a first flow rate above an activation threshold that moves the orifice sleeve from an upstream position to a downstream position to disengage the latch mechanism from the body groove, and the orifice sleeve is configured to receive the flow of drilling fluids at a second flow rate below the activation threshold that moves the orifice sleeve from the downstream position to the upstream position to engage the latch mechanism with the body groove.
In some aspects, the techniques described herein relate to a downhole device, wherein the activation threshold is a drilling fluid volumetric flow rate of 600 gallons per minute or greater.
In some aspects, the techniques described herein relate to a downhole device, further including: a sleeve groove including a well defining a deepest portion of the sleeve groove; an inclined portion; an edge connecting the well and the inclined portion; and wherein: the well is configured to receive at least a portion of the latch mechanism to disengage the latch mechanism from the body groove.
In some aspects, the techniques described herein relate to a downhole device, wherein the sleeve groove extends around a circumference of an outer wall of the orifice sleeve, the well is located at an upstream end of the sleeve groove, and the inclined portion is located at a downstream end of the sleeve groove.
In some aspects, the techniques described herein relate to a downhole device, further including: a sliding sleeve spring configured to bias the sliding sleeve toward the upstream end of the tool body; an orifice sleeve spring configured to bias the orifice sleeve toward the upstream end of the tool body; and wherein: a spring constant of the orifice sleeve spring is greater than a spring constant of the sliding sleeve spring.
In some aspects, the techniques described herein relate to a downhole device, wherein: the latch mechanism prevents a downstream movement of the sliding sleeve while engaged with the body groove; and a volume is defined between the sliding sleeve and the tool body such that the downstream movement of the sliding sleeve compresses the volume to engage the actuator.
In some aspects, the techniques described herein relate to a downhole device, wherein the latch mechanism includes: a recess formed in an outer wall of the sliding sleeve; a through-hole defined through the outer wall of the sliding sleeve; a latch key disposed within the recess and moveable between a first position and a second position; a latch spring disposed in the recess configured to urge the latch key towards the first position; a cap configured to retain at least a portion of the latch key or the latch spring inside the recess; wherein: the latch key is configured to engage with the body groove in the first position, and the latch key is configured to disengage from the body groove in the second position.
In some aspects, the techniques described herein relate to a downhole device configured as a selectable hole trimmer including: a sliding sleeve moveably disposed inside a tool body having an upstream end and a downstream end, the tool body including a drilling fluid volume and wherein the sliding sleeve is disposed within and slidable inside the tool body to provide a pressure to a pressurized volume; an actuator connected to the pressurized volume and configured to provide the pressure to a selectable hole cutter of the tool body to actuate the selectable hole cutter between a retracted state and an extended state; a sleeve groove formed within the tool body, the sleeve groove having a first position at a downstream end of the sleeve groove, a trigger position at an upstream end of the sleeve groove, and a second position disposed between the first position and the trigger position; a guide pin extending into the sleeve groove and configured to selectively engage at least the first position, the trigger position, or the second position; wherein: a first flow, above an activation threshold, flowing through the selectable hole trimmer is configured to disengage the guide pin from the first position and engage the guide pin with the trigger position, thereby moving the selectable hole cutter to the extended state, a second flow, below the activation threshold and below a locking threshold that is smaller than the activation threshold, flowing through the selectable hole trimmer is configured to disengage the guide pin from the trigger position and engage the guide pin with the second position, while maintaining the selectable hole cutter in the extended state, a third flow, above the activation threshold, flowing through the selectable hole trimmer is configured to disengage the guide pin from the second position and engage the guide pin with an additional trigger position, and a fourth flow, below the activation threshold and below the locking threshold, flowing through the selectable hole trimmer is configured to disengage the guide pin from the additional trigger position and engage the guide pin with an additional first position, thereby moving the selectable hole cutter to the retracted state.
In some aspects, the techniques described herein relate to a downhole device, wherein the actuator includes at least one of a piston portion of the sliding sleeve or an annular ring disposed between the sliding sleeve and the tool body.
In some aspects, the techniques described herein relate to a downhole device, wherein the sleeve groove further includes: a first slanted surface configured to direct the guide pin between the first position and the trigger position; a second slanted surface configured to direct the guide pin between the trigger position and the second position; a third slanted surface configured to direct the guide pin between the second position and the additional trigger position; and a fourth slanted surface configured to direct the guide pin between the additional trigger position and the additional first position.
In some aspects, the techniques described herein relate to a downhole device, wherein: the activation threshold is 660 gallons per minute or greater; and the locking threshold is 600 gallons per minute or greater.
In some aspects, the techniques described herein relate to a downhole device, further including: an intermediate sleeve disposed inside the tool body, the intermediate sleeve located between the tool body and the sliding sleeve; and wherein: the pressurized volume is defined between the intermediate sleeve and the tool body.
In some aspects, the techniques described herein relate to a downhole device, wherein: the sleeve groove is formed on an outer wall of the sliding sleeve and the guide pin is coupled to an inner wall of the intermediate sleeve; or the sleeve groove is formed on the inner wall of the intermediate sleeve and the guide pin is coupled to the outer wall of the sliding sleeve.
In some aspects, the techniques described herein relate to a downhole device, wherein a sliding sleeve spring is disposed within the intermediate sleeve and downstream of the sliding sleeve, the sliding sleeve spring configured to bias the sliding sleeve toward the upstream end of the tool body.
In some aspects, the techniques described herein relate to a method of using a downhole device configured as a selectable hole trimmer including: providing a drill bit a flow of drilling fluids; lowering the selectable hole trimmer in a borehole; receiving, by the selectable hole trimmer, the flow of drilling fluids at a flow rate above an activation threshold; and after receiving the flow above the activation threshold, causing a first movement of a sliding sleeve within the selectable hole trimmer to compress a volume, wherein the compressed volume forces hydraulic fluid through a port to move a selectable hole cutter from a retracted state to an extended state.
In some aspects, the techniques described herein relate to a method, wherein the activation threshold is 600 gallons per minute or greater.
In some aspects, the techniques described herein relate to a method, further including: in response to receiving the flow above the activation threshold, disengaging a latch mechanism from a body groove of a tool body of the selectable hole trimmer via a movement of an orifice sleeve, wherein disengaging the latch mechanism causes the first movement of the sliding sleeve; receiving, by the selectable hole trimmer, the flow of drilling fluids below a deactivation threshold; in response to receiving the flow below the deactivation threshold, engaging the body groove with the latch mechanism via a second movement of the sliding sleeve; and in response to the second movement of the sliding sleeve, moving the selectable hole cutter from the extended state to the retracted state.
In some aspects, the techniques described herein relate to a method, wherein the deactivation threshold is 300 gallons per minute or less.
In some aspects, the techniques described herein relate to a method, wherein the first movement of the sliding sleeve within the selectable hole trimmer to compress the volume includes displacing the sliding sleeve such that a guide pin disengages from a first position of a sleeve groove within the selectable hole trimmer and engages a trigger position of the sleeve groove, and further including: decreasing the flow rate below the activation threshold and below a locking threshold to displace the sliding sleeve such that the guide pin disengages from the trigger position and engages a second position of the sleeve groove, wherein the activation threshold is greater than the locking threshold; maintaining the selectable hole cutter in the extended state while the guide pin engages the second position; increasing the flow rate above the activation threshold such that the guide pin disengages from the second position and engages an additional trigger position; decreasing the flow rate below the activation threshold and the locking threshold to displace the sliding sleeve such that the guide pin disengages from the additional trigger position and engages an additional first position of the sleeve groove; and moving the selectable hole cutter from the extended state to the retracted state as the guide pin engages the additional first position.
In some aspects, the techniques described herein relate to a method, wherein: the activation threshold is 660 gallons per minute or greater; and the locking threshold is 600 gallons per minute or greater.
These and other objects, features and advantages will become apparent as reference is made to the following detailed description, preferred embodiments, and examples, given for the purpose of disclosure, and taken in conjunction with the accompanying drawings and appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a further understanding of the nature and objects of the present invention, reference should be made to the following detailed disclosure, taken in conjunction with the accompanying drawings, in which like parts are given like reference numerals, and wherein:

FIG. 1 illustrates an exemplary drilling environment for implementing a downhole device;

FIG. 2 shows a cross-sectional side view of a conceptual operation of the downhole device in the exemplary drilling environment of FIG. 1 ;

FIG. 3 shows a cross-sectional side view of a first exemplary embodiment of the downhole device;

FIG. 4 shows a cross-sectional side view of a second exemplary embodiment of the downhole device;

FIG. 5 shows a cross-sectional side view of a third exemplary embodiment of the downhole device;

FIG. 6 shows a cross-sectional top view of an exemplary embodiment of the downhole device;

FIG. 7A shows an exemplary schematic for controlling the downhole device;

FIG. 7B shows an exemplary schematic of a controller applicable to the downhole device;

FIG. 8A shows a side view of an exemplary embodiment of the downhole device having carved structures for regulating the annular fluid flow;

FIG. 8B shows a cross-sectional side view of the exemplary embodiment of the downhole device shown in FIG. 8A;

FIG. 8C shows a cross-sectional top view of the exemplary embodiment of the downhole device shown in FIG. 8A;

FIG. 9 shows a flow diagram of a method for bypassing drilling fluids from a downhole drill bit;

FIG. 10A shows a side view of an exemplary embodiment of an alternative downhole device having carved structures for regulating annular fluid flow;

FIG. 10B shows a cross-sectional side view of the exemplary embodiment of the downhole device shown in FIG. 10A;

FIG. 10C shows a detailed view cross-sectional top view of the exemplary embodiment of the downhole device shown in FIG. 10B;

FIG. 11A shows a top view of a lower sleeve and an upper sleeve of an alternative exemplary embodiment of the downhole device shown in FIGS. 10A-10C prior to a first step of assembly;

FIG. 11B shows a top view of the lower sleeve, the upper sleeve and a spring of the exemplary embodiment of the downhole device shown in FIG. 11A after the first step of assembly;

FIG. 11C-1 shows a side view of a stop block of the exemplary embodiment of the downhole device shown in FIGS. 11A-11B prior to a second step of assembly;

FIG. 11C-2 shows a side view of the assembled sleeve of the exemplary embodiment of the downhole device shown in FIG. 11B prior to a second step of assembly;

FIG. 11D shows a side view of a body of the exemplary embodiment of the downhole device prior to a second step of assembly;

FIG. 11E shows a cross-sectional view of the body and the sleeve of the exemplary embodiment of the downhole device of FIGS. 11A-11D after the second step of assembly;

FIG. 11F shows a cross-sectional view of the body and the sleeve of the exemplary embodiment of the downhole device shown in FIG. 11E prior to a third step of assembly;

FIG. 11G shows a cross-sectional view of the exemplary embodiment of the downhole device of FIGS. 11A-11F after the third step of assembly;

FIG. 12 shows a flow diagram of a method for bypassing drilling fluids from a downhole drill bit;

FIG. 13 shows a method of assembling the downhole device;

FIG. 14A shows a cross-sectional side view of an exemplary embodiment of the downhole device configured as a selectable hole trimmer, showing a selectable hole cutter on the downhole device;

FIG. 14B shows a detailed view of the selectable hole trimmer of FIG. 14A;

FIG. 14C shows a Section A cross-sectional view of the selectable hole trimmer of FIG. 14A;

FIG. 15A shows a view of an exemplary embodiment of a downhole device configured as a selectable hole trimmer, showing a plurality of selectable hole cutters on the downhole device in a deactivated position;

FIG. 15B shows a Section A-A cross-sectional view of the selectable hole trimmer of FIG. 15A, showing a deactivated cutter piston, a nozzle, a body, an intermediate sleeve, a sliding sleeve, a pressure equalization slot, and a return spring;

FIG. 15C shows a detailed B view of the selectable hole trimmer of FIG. 15A-15B, showing a deactivated cutter piston, a nozzle, an activation port and a pressure equalization slot;

FIG. 15D shows a detailed C view of the selectable hole trimmer of FIG. 15A-15C, showing a hydraulic fluid port;

FIG. 15E shows a Section D-D cross-sectional view of the selectable hole trimmer of FIG. 15A-15D, showing a deactivated cutter piston, an intermediate sleeve, and a sliding sleeve;

FIG. 16A shows a view of an exemplary embodiment of the downhole device configured as a selectable hole trimmer, showing a selectable hole cutter on the downhole device in an activated position;

FIG. 16B shows a Section A-A cross-sectional view of the selectable hole trimmer of FIG. 16A, showing an activated cutter piston, a nozzle, a body, an intermediate sleeve, a sliding sleeve, a pressure equalization slot, and a return spring;

FIG. 16C shows a detailed B view of the selectable hole trimmer of FIG. 16A-16B, showing an activated cutter piston with an extended cutter, a nozzle, and an activation port;

FIG. 16D shows a detailed C view of the selectable hole trimmer of FIG. 16A-16C, showing a hydraulic fluid port;

FIG. 16E shows a Section D-D cross-sectional view of the selectable hole trimmer of FIG. 16A-16D, showing an activated cutter piston with extended cutters, an intermediate sleeve, and a sliding sleeve;

FIG. 17 shows a view of an exemplary embodiment of a selectable hole trimmer configured as a linear optimizing tool, showing a linear configuration;

FIG. 18 shows a view of an exemplary embodiment of a selectable hole trimmer configured as a spiral optimizing tool, showing a spiral configuration;

FIG. 19A shows a view of another exemplary embodiment of the downhole device configured as a selectable hole trimmer without any bypass nozzles, showing a selectable hole cutter on the downhole device in a deactivated position;

FIG. 19B shows a Section A-A cross-sectional view of the selectable hole trimmer of FIG. 19A, showing a deactivated cutter piston, body, an intermediate sleeve, a sliding sleeve, a hydraulic fluid port, a compensating spring, and a return spring;

FIG. 19C shows a Section C-C cross-sectional view of the selectable hole trimmer of FIG. 19A-19B, showing an intermediate sleeve, and a sliding sleeve;

FIG. 20 shows a flow diagram of a method of using a downhole device configured as a selectable hole trimmer;

FIG. 21A shows a cross-sectional view of another exemplary embodiment of a downhole device configured as a selectable hole trimmer, showing a selectable hole cutter on the downhole device in a deactivated position, an intermediate sleeve, a compensating sleeve, a hydraulic fluid port, a compensating port, and a stop block;

FIG. 21B shows a cross-sectional view of the selectable hole trimmer of FIG. 21A, showing an activated cutter piston with extended cutters, the intermediate sleeve, the compensating sleeve, the hydraulic fluid port, the compensating port, and the stop block;

FIG. 21C shows a detailed cross-sectional view of the selectable hole trimmer of FIG. 21A, showing a deactivated cutter piston with retracted cutters, the compensating sleeve and the stop block;

FIG. 21D shows a detailed cross-sectional view of the selectable hole trimmer of FIGS. 21B, showing the activated cutter piston with extended cutters;

FIG. 21E shows a detailed cross-sectional view of the selectable hole trimmer of FIGS. 21A and 21C;

FIG. 21F shows a detailed view of the selectable hole trimmer of FIGS. 21B and 21D;

FIG. 21G shows an upper, left perspective view of the selectable hole trimmer of FIGS. 21A-21F, showing the activated cutter piston with extended cutters;

FIG. 22 shows a hydraulic schematic of an exemplary embodiment of a downhole device configured as a selectable hole trimmer;

FIG. 23A shows a flow diagram of another method of using a downhole device configured as a selectable hole trimmer;

FIG. 23B shows a flow diagram of additional steps for the method of FIG. 23A;

FIG. 23C shows a flow diagram of additional steps for the method of FIGS. 23A-23B;

FIG. 24 shows a partial cross-sectional view of an exemplary embodiment of a downhole device configured as a selectable hole trimmer, showing a selectable hole cutter on the downhole device in a deactivated position, a dual solenoid compensating sleeve, an annular compensating ring, a volume/waste ring, a hydraulic fluid port and a hydraulic fluid waste port 2414 a.

FIG. 25A shows a cross-sectional view of an exemplary embodiment of a downhole device configured as a selectable hole trimmer, showing a selectable hole cutter in a deactivated position, an intermediate sleeve, a sliding sleeve, a hydraulic fluid port, an activation dart, a seat, a hydraulic fluid port and a stop lock;

FIG. 25B shows a cross-sectional view of the selectable hole trimmer of FIG. 25B, showing an alternative sliding sleeve;

FIG. 26A shows a side view of an exemplary embodiment of a downhole device configured as a selectable hole trimmer, showing a charge subassembly A and a trimmer subassembly B having a selectable hole cutter in a deactivated position;

FIG. 26B shows a cross-sectional view of the selectable hole trimmer of FIG. 26A, showing the selectable hole cutter in a deactivated position;

FIG. 26C shows a detailed view of the selectable hole cutter of the selectable hole trimmer of FIGS. 26A-26B, showing a cutter piston, a cutter, a spring and a retaining ring;

FIG. 26D shows a cross-sectional view of the selectable hole cutter of FIG. 26C, showing the cutter piston and the cutter;

FIG. 26E shows a cross-sectional view of selectable hole trimmer of FIGS. 26A-26D, showing the selectable hole trimmer being activated with an activation ball and a catch sleeve being lowered downward to a lower position;

FIG. 26F shows a cross-sectional view of selectable hole trimmer of FIGS. 26A-26D, showing the selectable hole trimmer in a deactivated position with an activation ball in a seat of a catch sleeve and with a charge sleeve and the catch sleeve in an upper position;

FIG. 26G shows a cross-sectional view of selectable hole trimmer of FIGS. 26A-26D, showing the selectable hole trimmer in an activated position with an activation ball in a seat of a catch sleeve and with a charge sleeve and the catch sleeve in a lower position;

FIG. 26H shows a detailed view of an upper end of the selectable hole trimmer of FIG. 26A-26B, showing the selectable hole trimmer in a deactivated position and a seat in the catch sleeve;

FIG. 26I shows a detailed view of the upper end of the selectable hole trimmer of FIGS. 26E-26G, showing the selectable hole trimmer in an activated position and an activation ball in a seat in the catch sleeve;

FIG. 27A shows a flow diagram of a method of using the selectable hole trimmer of FIG. 25 ;

FIG. 27B shows a flow diagram of additional steps for the method of FIG. 27A;

FIG. 27C shows a flow diagram of additional steps for the method of FIG. 27A;

FIG. 27D shows a flow diagram of additional steps for the method of FIG. 27A;

FIG. 28A shows a flow diagram of a method of using the selectable hole trimmer of FIGS. 25A and 25B;

FIG. 28B shows a flow diagram of additional steps for the method of FIG. 28A;

FIG. 28C shows a flow diagram of additional steps for the method of FIG. 28A;

FIG. 29A shows a flow diagram of a method of using the selectable hole trimmer of FIGS. 26A-26I;

FIG. 29B shows a flow diagram of additional steps for the method of FIG. 29A; and

FIG. 29C shows a flow diagram of additional steps for the method of FIG. 29A;

FIGS. 30A and 30B show a cross-sectional view of an exemplary embodiment of a downhole device configured as a selectable hole trimmer, showing a close up view of an upstream end of the selectable hole cutter having a sliding sleeve and an orifice sleeve;

FIG. 30C shows a detailed view of the orifice sleeve and an upstream end of the sliding sleeve of the downhole device of FIGS. 30A and 30B;

FIG. 30D shows the downhole device of FIGS. 30A and 30B with the orifice sleeve moved to a downstream position and a latch mechanism disengaged from a sleeve groove;

FIG. 30E shows the downhole device of FIGS. 30A and 30B with the sliding sleeve moved to a downstream position such that a selectable hole cutter is in an extended state;

FIG. 31 shows a flow diagram of a method of using the selectable hole trimmer of FIGS. 30A-E;

FIG. 32 shows a schematic view of another exemplary embodiment of a downhole device configured as a selectable hole trimmer;

FIG. 33 shows a cross-sectional view of another exemplary embodiment of a downhole device of FIG. 32 configured as a selectable hole trimmer having a sliding sleeve with a sleeve groove and an intermediate sleeve with a guide pin;

FIG. 34A shows a cross-sectional view of another exemplary embodiment of the downhole device of FIGS. 32 and 33 configured as a selectable hole trimmer having a sliding sleeve with a sleeve groove and an intermediate sleeve with a guide pin;

FIG. 34B shows a detailed view of the sliding sleeve and a configuration of the guide pin of the downstream device of FIG. 34A;

FIG. 34C shows a cross-sectional view of the exemplary embodiment of the downhole device of FIG. 34A to represent a possible arrangement of the components of the downhole device with the guide pin located at the position shown in FIG. 34B;

FIG. 34D shows a detailed view of the sliding sleeve and a configuration of the guide pin of the downstream device of FIG. 34A;

FIG. 34E shows a cross-sectional view of the exemplary embodiment of the downhole device of FIG. 34A to represent a possible arrangement of the components of the downhole device with the guide pin located at the position shown in FIG. 34D;

FIG. 35 shows a flow diagram of a method of using the selectable hole trimmers of FIGS. 32-34E;

FIG. 36 shows a flow diagram of additional steps for the method of FIG. 35 .

FIG. 37 shows an example embodiment of a latch mechanism of the downhole device configured as a selectable hole trimmer of FIGS. 30A-E.

DETAILED DESCRIPTION

The following detailed description of various embodiments of the present invention references the accompanying drawings, which illustrate specific embodiments in which the invention can be practiced. While the illustrative embodiments of the invention have been described with particularity, it will be understood that various other modifications will be apparent to and can be readily made by those skilled in the art without departing from the spirit and scope of the invention. Accordingly, it is not intended that the scope of the claims appended hereto be limited to the examples and descriptions set forth herein but rather that the claims be construed as encompassing all the features of patentable novelty which reside in the present invention, including all features which would be treated as equivalents thereof by those skilled in the art to which the invention pertains. Therefore, the scope of the present invention is defined only by the appended claims, along with the full scope of equivalents to which such claims are entitled.
In general, the disclosed downhole device may run on a drill string during a drilling operation for an oil and gas well. The downhole device may operate to bypass some of the drilling fluid (mud) on command to reduce the flow through the drill bit, to clean/cool the cutters and to prevent cutter piston lock-out. The downhole device may respond to a downlink, or communication from the driller on surface, such as signal generated in response to a protocol of rpm, drilling mud fluid volume, or other changes to a drilling string. In some embodiments, the downhole device may be deployed in the hole in an asleep/deactivated mode that awaits actuation signals. Once in position, an operator may produce rotation, pressure, weight, rpm, drilling mud volumetric flows, or other predetermined protocols to wake up the tool. Once awakened, the downhole device may respond to rotation rates, drilling mud fluid flow rates, or the like above a predetermined value for initiating the bypass operation and respond to rotation rates, drilling mud fluid flow rates, or the like not above the predetermined value for stopping the bypass operation. Other controls based on different measurable values may be used. In some embodiments, in addition to the bypass operation, the downhole device may provide a cutting, trimming, or other operation configured to increase a pass-through diameter of a borehole.
The downhole device response to the signal may include the opening or closing of one or more valves and changing of the flow path of hydraulic oil in a mechanism. Alternatively, this action may begin operation of a pump/motor and pump oil to shift a sleeve. This action changes the flow path of drilling mud through the downhole device to accomplish a function, such as sliding a sleeve or opening or closing a flow path for the drilling mud.
Further rpm protocol, or other downlink, pressure, flow rate, or bit weight protocol may shift the flow path and open and close valves. Other tools incorporating this triggering method may move an internal sleeve to expose drilling reamer elements to expand and increase the inner diameter of the borehole. Another tool may use the resultant sliding sleeve action to force a reaming cutter block up a ramp to increase the inner diameter of the hole. Finally, another modification may be to fully close the tool bore and force all of the mudflow to exit the downhole device allowing none to go to the drilling bit.
The disclosed downhole device may begin operation in response to a protocol of rpm changes or changes in bit weight or pressure or flow rate or other metrics. These signals would be recognized by the disclosed downhole device to make the change of flow path or other activity in the downhole device. The disclosed downhole device may open a flow path from the internal tool flow path of drilling mud to the annulus of the downhole device. Some percentage of the mud flowing through the drill string may then bypass to the annulus. In other embodiments, the disclosed downhole device may also open flow path of the drilling mud to borehole reaming pistons or sliding cutter blocks, which may enlarge the borehole.
Further, the downhole devices disclosed herein may provide for controllable and/or selectable activation and deactivation of cutter elements based on the geometries or activation mechanisms disposed within the downhole devices. In some embodiments, the activation mechanisms allow for the downhole devices to selectably alternate/transition between an activated state where hole cutting devices are extended and a deactivated state where hole cutting devices are retracted. In the activated state, the hole cutting devices located on the downhole device may extend outward from a body of the device and trim off ledges, curves, or other discontinuities in the borehole surrounding the device. In this way, the downhole device may better prepare the borehole for the instillation of casing pipe. Further, the downhole device may selectively transition to the deactivated state where hole cutting devices are retracted. In the deactivated state, the hole cutting devices located on the downhole device may recede such that they do not extend further than an outer perimeter or surface of the body of the downhole device. In this way, once the downhole device is to be extracted for example, the downhole device may be better suited to exit the borehole without catching, scraping, or otherwise requiring great force to remove from the borehole. In other words, in the deactivated state, the downhole device may be readily inserted and/or retracted in a smooth or relatively low-drag manner compared to the downhole device in the activated state. Accordingly, the downhole device disclosed herein beneficially allows for retraction of the hole cutters to reduce friction, drag, and resistance when the tool is sliding or tripping into or out of a borehole. Thus, the tool may be easier to operate compared to other hole trimmers while maintaining the ability to cut, chip away, or otherwise remove discontinuities of the borehole when activated.

Fifth Alternative Downhole Device Configured as Selectable Hole Trimmer

FIG. 30A shows a cross sectional view of another exemplary embodiment of a downhole device configured as a selectable hole trimmer 3000. The selectable hole trimmer 3000 may be configured as a concentric device that has expandable/retractable cutters (e.g., selectable hole cutters 1401) to trim ledges, discontinuities, and the like from a borehole such as the drilled hole 130. Specifically, FIG. 30A illustrates a closeup cross sectional view of the activation mechanism 3004 (e.g., an actuator, a sliding assembly, one or more components configured to selectable activate and deactivate the selectable hole cutters 1401, etc.) of the selectable hole trimmer 3000, which may be interoperable with other downhole devices disclosed herein. For example, the activation mechanism 3004 may provide an alternative arrangement of components that allows selective activation and deactivation of selectable hole cutters 1401, actuators, cutter pistons, and the like discussed above. While selectable hole cutters 1401 are not illustrated in the section view shown in FIGS. 30A-E, the selectable hole cutters 1401 may be disposed at any suitable location along the tool body 3008 in FIGS. 30A-E. The selectable hole cutters 1401 may, for example, be disposed along the tool body 3008 like the selectable hole cutters 1401 shown in FIGS. 34A, 34C, and 34E.
As shown in FIG. 30A, the selectable hole trimmer 3000 comprises a tool body 3008. The tool body 3008 may generally have a cylindrical outer wall 3009 having an outer diameter 3010 and an inner diameter 3011 that defines a chamber 3012 through which a volume of drilling mud may flow. The tool body 3008 may have one or more connections at its ends (such as a box connection, a pin connection, or the like) to enable the tool body 3008 to sealingly couple to another tool body 3008, another downhole device, or any other suitable feature of the drill string 120. As shown in FIG. 30A, the leftmost side of the page may correspond to a drilling mud inlet 3016 of the tool body 3008 and a drilling mud outlet (not shown) of the tool body 3008 may be located in the direction of the rightmost side of the page relative to the tool body 3008 (e.g., down bore of the drilling mud inlet 3016). The activation mechanism 3004 may be disposed (e.g., concentrically located) within the tool body 3008 of the selectable hole trimmer 3000 and utilize drilling mud fluid flowing through the chamber 3012 to selectively activate or deactivate selectable hole cutters 1401, actuators, nozzles, and/or other components of the selectable hole trimmer 3000. Specifically, selectable hole cutters 1401 may be located on the tool body 3008 and may be hydraulicly and/or fluidly coupled to the activation mechanism 3004 such that the activation mechanism 3004 allows for the selectable hole cutters 1401 to toggle between an activated position and a deactivated position.
In some embodiments, the tool body 3008 may include one or more bypass nozzles 3015. In other embodiments, the tool body 3008 may include no bypass nozzles 3015 (e.g., the bypass nozzles 3015 may be omitted). The bypass nozzles 3015 may selectively allow drilling fluid to circumvent the drill bit 132 or otherwise flow from the tool body 3008 into the annulus 122. For example, if a bypass nozzle 3015 is included in the selectable hole trimmer 3000, the bypass nozzle 3015 may be covered/blocked by the sliding sleeve 3020 while the selectable hole cutters 1401 are in the deactivated position and may be uncovered/open while the selectable hole cutters 1401 are in the activated position. In this way, the bypass nozzles 3015 may divert flow and cause a change in pressure compared to flow rate of the drilling fluid while the selectable hole trimmer 3000 is in the active state as a signal to the rig floor indicating the state of the selectable hole trimmer 3000.
In some embodiments, the tool body 3008 may further comprise at least one body groove 3017. The at least one body groove 3017 may include a recess, channel, or the like formed in the inner wall of the tool body (e.g., in the wall of the chamber 3012). The body groove 3017 may have a tapered, beveled, and/or chamfered upstream edge leading into the deepest part of the groove and a downstream edge configured to engage a latch mechanism 3040 of the selectable hole trimmer 3000 until the drilling mud fluid satisfies an activation threshold (e.g., a volumetric flow rate above a designated flow rate). The downstream edge of the body groove 3017 may also be tapered, beveled, chamfered, or otherwise suited to engage with the latch mechanism 3040 (e.g., a latch, locking dog, pin, prong, ridge, protrusion, recess, or other suitable interface of the latch mechanism 3040). For example, one or more edges of the body groove 3017 may be configured to engage with one or more of a square locking dog of the latch mechanism 3040 having beveled top edges, a profile of the locking mechanism 3040 configured to interface with the body groove 3017, or the like. One or more body grooves 3017 may be arranged circumferentially around the chamber 3012, at different longitudinal lengths along the chamber 3012, or the like. For example, in one embodiment, the body groove 3017 is a circular channel extending around the entire inner circumference of the chamber 3012. In this way, the body groove 3017 may be configured to engage and/or disengage with the activation mechanism 3004 regardless of the axial rotation, if any, of the sliding sleeve 3020.
The activation mechanism 3004 may comprise one or more portions of the tool body 3008, a sliding sleeve 3020, an orifice sleeve 3024, one or more resilient members such as a sliding sleeve spring 3028 and an orifice sleeve spring 3032, a volume 3036 (e.g., defined between the sliding sleeve 3020 and the tool body 3008), a latch mechanism 3040, a groove, edge, recess, or the like configured to engage the latch mechanism 3040 (e.g., a body groove 3017), one or more hydraulic fluid ports 3044, and/or other components described below.
The activation mechanism 3004 may be configured to activate and/or deactivate the selectable hole cutters 1401 based on, for example, a sequence of changes in fluid flow or based on a predefined pattern of drilling mud fluid flow. For example, the activation mechanism 3004 may be configured to have an initial neutral or “off” position corresponding to no fluid flow and/or fluid flow below an activation threshold. In some embodiments the activation threshold may be a fluid flow of 500 gallons per minute (gpm), 600 gpm, 660 gpm, or any other suitable fluid flow metric. The neutral or “off” position may correspond to the example configuration shown in FIGS. 30A and 30B. For example, in the neutral or “off” position, the selectable hole cutters 1401 may be disengaged, the sliding sleeve 3020 may be at an upstream position 3077 (See e.g., FIG. 30B) preventing drilling mud fluid from exiting via a bypass nozzle 3015 (if present), the orifice sleeve 3024 may be in an upstream position 3078 (See, e.g., FIG. 30B) such that the latch mechanism 3040 engages with the groove (e.g., body groove 3017), and/or at least one of the sliding sleeve spring 3028 or the orifice sleeve spring 3032 may be in a fully expanded state. In this way, the neutral position or the “off” position may allow the selectable hole trimmer 3000 to slide with relatively little friction and resistance while being inserted and/or being removed from the borehole because the selectable hole cutters 1401 are withdrawn, retracted, or otherwise not actively cutting or dragging against the edges of the borehole.
Additionally, the activation mechanism 3004 may be configured to have an activated or “on” position associated with fluid flow exceeding the activation threshold and/or exceeding a deactivation threshold. The activated or “on” position may correspond to the example configuration shown in FIG. 30E. For example, in the activated or “on” position, the selectable hole cutters 1401 may be engaged, the sliding sleeve 3020 may be at a downstream position allowing drilling mud fluid to exit via the bypass nozzle 3015 (if present), the orifice sleeve 3024 may be in a downstream position such that the latch mechanism 3040 is not engaged with the groove of the selectable hole trimmer 3000 (e.g., body groove 3017), and/or at least one of the sliding sleeve spring 3028 or the orifice sleeve spring 3032 may be in a compressed state (e.g., a fully compressed state or a partially compressed state).
At least one of the sliding sleeve spring 3028 and/or the orifice sleeve spring 3032 may be a coil spring providing a biasing force corresponding to an activation threshold (e.g., a threshold trigger pressure, a pressure balancing the force applied by the respective spring to the sleeve, a threshold trigger volumetric flow rate, or the like). For example, in some embodiments, when the threshold volumetric flow rate exceeds the trigger volumetric flow rate, the orifice sleeve spring 3032 and/or the sliding sleeve spring 3028 may be moved to a position configured to engage the selectable hole cutters 1401. In some embodiments, the spring constant k of the sliding sleeve spring 3028 may be smaller than the spring constant k of the orifice sleeve spring 3032. In other words, the sliding sleeve spring 3028 may be less stiff (e.g., may require less force to compress/extend a certain distance) than the orifice sleeve spring 3032.
The activated position or the “on” position may allow the selectable hole trimmer 3000 to extend the selectable hole cutters 1401 by energizing/pressurizing cutter pistons 1402 via movement of the activation mechanism 3004 (e.g., a rapid movement or “pop” of the sliding sleeve 3020 against the sliding sleeve spring 3028 to pressurize hydraulic fluid of the volume 3036 in response to flow above the activation threshold and in response to the latch mechanism 3040 disengaging from the body groove 3017). For example, once the activation threshold is met (e.g., the drilling mud fluid volumetric flow rate meets the activation volumetric flow rate), the orifice sleeve 3024 may move within the sliding sleeve 3020 such that the latch mechanism 3040 engages with a groove of the orifice sleeve 3024 (e.g., a sleeve groove 3058), which allows for the sliding sleeve to move axially downstream in the tool body 3008.
In some embodiments, the selectable hole trimmer 3000 may remain in the activated or “on” position and/or keep the selectable hole cutters 1401 engaged until the flow falls below a deactivation threshold. At the deactivation threshold, for example, at least one of the orifice sleeve 3024, the orifice sleeve spring 3032, the sliding sleeve 3020, or the sliding sleeve spring 3028 may return to its upstream-most position, causing the latch mechanism 3040 to engage with the groove (e.g., body groove 3017) and allowing drilling mud fluid to flow through the drilling mud outlet of the tool body 3008 without energizing the cutter pistons 1402.
Focusing on FIG. 30A, the sliding sleeve 3020 may comprise a generally cylindrical outer wall 3021 configured to slidably fit within the chamber 3012 of the tool body 3008. Specifically, the outer wall 3021 of the sliding sleeve 3020 may have a first outer diameter 3049 corresponding to and/or configured to slidably engage the inner diameter 3011 of the tool body 3008. The sliding sleeve 3020 may also have a second outer diameter 3050 smaller than the first outer diameter 3049. As shown in FIG. 30A, a radial surface 3051 of the sliding sleeve 3020 may be disposed between the first outer diameter 3049 and the second outer diameter 3050. The radial surface 3051 may be configured to abut and/or receive a force from the sliding sleeve spring 3028 and may also be configured to define a portion of the volume 3036 between the sliding sleeve 3020 and the tool body 3008. In this way, movement of the sliding sleeve 3020 downstream/upstream within the tool body 3008 (e.g., to the right/left in FIG. 30A) may compress/allow expansion of the sliding sleeve spring 3028 and reduce/increase the size of the volume 3036, respectively.
Like the tool body 3008, the sliding sleeve 3020 may define a sliding sleeve chamber 3022 therein. Drilling mud may enter the sliding sleeve chamber 3022 via a drilling mud inlet 3023 of the sliding sleeve 3020 and flow through at least a portion of the sliding sleeve chamber 3022. The sliding sleeve chamber 3022 may comprise a first portion 3025 and a second portion 3026. The first portion 3025 of the sliding sleeve chamber 3022 may be defined by a first inner diameter 3027 of the sliding sleeve 3020. The second portion 3026 of the sliding sleeve chamber 3022 may be defined by a second inner diameter 3029 of the sliding sleeve 3020. The second inner diameter 3029 may be smaller than the first inner diameter 3027 such that one or more pressure drops occur as the drilling mud flows across the length of the of the sliding sleeve 3020. The pressure drop, in turn, may cause a force to urge the sliding sleeve 3020 downstream within the tool body 3008.
The first portion 3025 of the sliding sleeve chamber 3022 may be configured to receive the orifice sleeve 3024, the orifice sleeve spring 3032, and/or at least a portion of the latch mechanism 3040. In this way, the first portion 3025 of the sliding sleeve chamber 3022 may form an orifice sleeve recess 3030 configured to slidably receive the orifice sleeve 3024. The orifice sleeve recess 3030 may define the upstream and downstream limits of the movement of the orifice sleeve 3024 within the sliding sleeve 3020. As shown in FIG. 30A, in some embodiments, the orifice sleeve recess 3030 may be continuous with, integral with, or entirely contained within the first portion 3025 of the sliding sleeve chamber 3022 (e.g., the first portion 3025 may form the orifice sleeve recess 3030 such that the orifice sleeve 3024 is not configured to slidably move along the entire length of the first portion 3025). For example, and as explained below, the orifice sleeve 3024 may move from a neutral position (e.g., an upstream position) when no drilling mud flows through the sliding sleeve chamber 3022 to a compressed position (e.g., a downstream position) when drilling mud flows through the sliding sleeve chamber 3022. However, in some embodiments, the orifice sleeve 3024 may not be configured to move further upstream from the neutral position or exit the first portion 3025 of the sliding sleeve 3020 (e.g., in some embodiments, the orifice sleeve 3024 may not be permitted to slide through the drilling mud inlet 3023 of the sliding sleeve 3020 by a groove, stop block, edge of the orifice sleeve recess 3030, etc.).
For example, turning briefly to FIG. 30B, orifice sleeve stops 3033 are represented by black boxes at an illustrative example for a location of a stop block, stopping protrusion, or other edge which may abut and prevent further upstream movement of the orifice sleeve 3024 within the sliding sleeve 3020. For example, the orifice sleeve spring 3032 may apply a force to the orifice sleeve 3024 and slide the orifice sleeve 3024 upstream within orifice sleeve recess 3030 of the sliding sleeve 3020 until the orifice sleeve 3024 contacts the orifice sleeve stops 3033. In this way, the orifice sleeve stops 3033 may define the location of the orifice sleeve recess 3030 and limit the movement of the orifice sleeve 3024 within the sliding sleeve 3020.
Focusing again on FIG. 30A, the orifice sleeve recess 3030 may be defined by a recess length 3031, the first inner diameter 3027 of the sliding sleeve 3020, and/or the orifice sleeve stops 3033. The recess length 3031 may correspond to the maximum distance that the orifice sleeve 3024 may travel/slide within the sliding sleeve 3020. In some embodiments, the orifice sleeve recess 3030 may be defined by a diameter larger or smaller than the first inner diameter 3027 (e.g., the orifice sleeve recess 3030 may be formed by narrowing or widening a section of the sliding sleeve chamber 3022). In some embodiments, the ends of the orifice sleeve recess 3030 may act as stop blocks that prevent further upstream movement of the orifice sleeve 3024, further downstream movement of the orifice sleeve spring 3032, or the like. In some embodiments, the inlet of the second portion 3026 of the sliding sleeve 3020 may form and/or act as a stop block configured to prevent further downstream movement of the orifice sleeve spring 3032. In other embodiments, a stop block, channel, groove, or other feature (e.g., the orifice sleeve stops 3033) may be located proximate to the second portion 3026 or in the first portion 3025 in order to secure a downstream end of the orifice sleeve spring 3032.
As best shown in FIG. 30C, the orifice sleeve 3024 may comprise a generally cylindrical outer wall 3054 having an outer diameter 3055 corresponding to and/or configured to slidably engage an inner wall of the sliding sleeve chamber 3022 (e.g., the first inner diameter 3027) of the sliding sleeve 3020. Specifically, the outer diameter 3055 of the orifice sleeve 3024 may be configured to slide within the orifice sleeve recess 3030 of the sliding sleeve 3020 (See e.g., FIGS. 30A and 30C). The orifice sleeve 3024 may have an orifice chamber 3056 defined therein and extending through the orifice sleeve 3024. The orifice chamber 3056 may be configured to alter the flow of drilling mud fluid such that a pressure drop occurs between a drilling mud inlet 3062 of the orifice chamber 3056 and a drilling mud outlet 3063 of the orifice chamber 3056. For example, the cross-sectional area of the orifice chamber 3056 may decrease, the flow of the drilling mud fluid may increase in velocity, etc., resulting in a pressure drop across the orifice chamber 3056 and a corresponding force acting to direct the orifice sleeve 3024 downstream, compress the orifice sleeve spring 3032, and the like.
The orifice sleeve 3024 may include an orifice 3070 defined by an orifice diameter 3071 which narrows the flow path of drilling mud fluid. Specifically, in some embodiments, the orifice diameter 3071 may be the smallest diameter of the orifice chamber 3056. The orifice 3070 and/or the orifice diameter 3071 may be disposed between an inlet chamber 3066 and an outlet chamber 3074 of the orifice sleeve 3024. As shown in FIG. 30C, the inlet chamber 3066 may have an inner wall having a variable inner diameter (e.g., having a flow constricting portion followed by a flow expanding portion) between the drilling mud inlet 3062 and the orifice 3070. Further, the inlet chamber 3066 may include a tapered edge 3072 (e.g., a bevel, an insert, or the like) to transition and narrow the flow of drilling mud fluid from the inlet chamber 3066 through the orifice 3070 while reducing erosion of the orifice 3070. The outlet chamber 3074 may be defined by an outlet chamber diameter which may remain constant over a length of the outlet chamber 3074. In some embodiments, an outlet insert, sleeve, protecting wall, or the like may be configured to extend downstream such that the orifice sleeve 3024 may slide within the sliding sleeve 3020 and allow expansion/contraction of the orifice sleeve spring 3032 while preventing or limiting the amount of drilling mud fluid from contacting the orifice sleeve spring 3032.
The outer wall 3054 of the orifice sleeve 3024 may comprise a sleeve groove 3058 configured to engage the latch mechanism 3040. For example, the sleeve groove 3058 may extend around the circumference of the orifice sleeve 3024 such that the latch mechanism 3040 is generally unaffected by axial rotation of the orifice sleeve 3024, if any. The sleeve groove 3058 may begin proximate to or at the downstream edge of the outer wall 3054 of the orifice sleeve 3024. The depth of the sleeve groove may increase gradually as the length of the sleeve groove 3058 proceeds in an upstream direction along the outer wall 3054 of the orifice sleeve 3024. The sleeve groove 3058 may further include a well 3059 (e.g., a deepest part of the sleeve groove 3058 at an upstream most side of the sleeve groove 3058). The well 3059 may be defined by a channel, a recess, or another suitable increase in depth of the sleeve groove 3058 that is relatively rapid compared to the downstream edge and/or the downstream portion of the sleeve groove 3058. An edge 3060 (e.g., a chamfered edge, a beveled edge, etc.) may separate the gradual downstream portion of the sleeve groove 3058 from the deeper well 3059 of the sleeve groove 3058. In this way and as explained below, increasing the fluid flow may gradually move the orifice sleeve 3024 in a downstream direction. Correspondingly, the latch mechanism 3040 may gradually extend further inward against the incline of the sleeve groove 3058 as the upstream edge of the sleeve groove 3058 and the edge 3060 approaches the latch mechanism 3040. When the flow is great enough such that the edge 3060 of the orifice sleeve reaches the latch mechanism 3040 (e.g., when the flow level meets the activation threshold), the latch mechanism 3040 or a portion thereof may enter the well 3059. As a result, the latch mechanism 3040 may no longer be located within body groove 3017 of the selectable hole trimmer 3000. When the latch mechanism 3040 disengages from the body groove 3017, the sliding sleeve 3020 may be free to move downstream and compress the sliding sleeve spring 3028.
Turning to FIG. 30D, the orifice sleeve 3024 and the latch mechanism 3040 are shown in a position corresponding to the flow of drilling mud fluid nearly approaching and/or reaching the activation threshold. As shown in FIG. 30D, the orifice sleeve 3024 is located at and/or proximate to the downstream most position of the recess length 3031 of the orifice sleeve recess 3030. In other words, the volumetric flow rate of the drilling mud fluid has increased such that the orifice sleeve 3024 moves downstream within the orifice sleeve recess 3030 of the sliding sleeve 3020, and the orifice sleeve 3024 compresses the orifice sleeve spring 3032. As the orifice sleeve 3024 moves downstream, the distance between the latch mechanism 3040 and the well 3059 decreases. The orifice sleeve 3024 may be located at a compressed position 3079 where the orifice sleeve spring 3032 is at or near its most compressed state.
An example latch mechanism 3040 is also shown disposed in the outer wall 3021 of the sliding sleeve 3020 in FIGS. 30A-E. Notably, in FIGS. 30A-C, the latch mechanism 3040 is shown engaged with the body groove 3017. When the latch mechanism 3040 is engaged with the body groove 3017, the latch mechanism 3040 prevents the sliding sleeve 3020 from moving axially within the chamber 3012 of the tool body 3008. Accordingly, the sliding sleeve 3020 may not compress the volume 3036 and the selectable hole cutters 1401 will remain in the disengaged state while the latch mechanism 3040 remains engaged with the body groove 3017.
However, when the latch mechanism 3040 disengages from the body groove 3017 and engages with the well 3059 of the sleeve groove 3058, the latch mechanism 3040 no longer prevents axial movement of the sliding sleeve 3020 within the chamber 3012 of the tool body 3008. For example, in FIG. 30D-E, the latch mechanism 3040 is shown disengaged from the body groove 3017 in two example positions.
In FIG. 30D, the volumetric flow rate of drilling mud has just reached the activation threshold (e.g., has caused the orifice sleeve 3024 to compress the orifice sleeve spring 3032 such that the latch mechanism 3040 moves into the well 3059 of the sleeve groove 3058 via the edge 3060). At the activation threshold, the latch mechanism 3040 engages the sleeve groove 3058 to the extent that the latch mechanism 3040 disengages from the body groove 3017. When the latch mechanism 3040 disengages from the body groove 3017, and in the presence of volumetric drilling mud flow at the activation threshold or at a rate high enough to compress the orifice sleeve spring 3032 (which may be stiffer than the sliding sleeve spring 3028), the sliding sleeve spring 3028 will compress as the drilling mud urges the sliding sleeve 3020 downstream. In other words, the sliding sleeve 3020 will move downstream, compressing the volume 3036 and energizing the selectable hole cutters 1401 into the engaged state (e.g., extending the cutter pistons 1402).
In FIG. 30E, the latch mechanism 3040 is shown engaging the well 3059 and/or the edge 3060 of the sleeve groove 3058. Further, the latch mechanism 3040 no longer extends into the body groove 3017 and the sliding sleeve 3020 has moved downstream (e.g., the sliding sleeve 3020 have moved downstream in response to the flow of drilling mud at or above the activation threshold, above 600 gpm, greater than the deactivation threshold, greater than 300 gpm, etc.). The movement of the sliding sleeve 3020 downstream may compress the volume 3036. Specifically, the sliding sleeve 3020 may move to its most downstream position, the compressed position 3087 of the sliding sleeve 3020, wherein the sliding sleeve spring 3028 and the volume 3036 are at their most compressed states. In one embodiment, the volume 3036 may include an annular space (e.g., disposed between the sliding sleeve 3020 and the tool body 3008) containing hydraulic fluid (e.g., oil). Movement of the sliding sleeve 3020 may compress the annular space such that the volume 3036 energizes the cutter pistons 1402. In some embodiments, hydraulic fluid (e.g., oil) in the compressed volume 3036 may pressurize/activate the cutter pistons 1402 via one or more hydraulic fluid ports 3044, by applying pressure to a piston, chamber, membrane, etc. For example, the hydraulic fluid ports 3044 (if present) may include and/or be similar to hydraulic fluid ports 2414, the channels/ports/volumes of the hydraulic fluid system 2200, the volume 2122, or any other suitable hydraulic system such as those disclosed herein (See e.g., FIGS. 3-5 and 14A).
Turning back to FIG. 30D, in some embodiments, the latch mechanism 3040 may comprise a recess 3080, a through-hole 3081, a latch 3082, a latch spring 3083, and/or a cap 3084. As explained herein, the latch mechanism 3040 is configured to selectively engage and disengage the body groove 3017 and/or the sleeve groove 3058 to cause selective activation and deactivation of the selectable hole cutters 1401 (e.g., in response to variations in the volumetric flow rate of the drilling mud). While one embodiment of the latch mechanism 3040, body groove 3017, and sleeve groove 3058 is shown in FIGS. 30A-E, it should be understood that other latch mechanisms 3040 and components thereof are possible and are contemplated by this disclosure.
For example, in another embodiment, the latch mechanism 3040 may include a square and/or rectangular shaped locking dog, latch, bar, engagement member, or the like such as the latch key 3085 shown in FIG. 37 . The latch key, locking dog, latch 3085 or the like, may include beveled, tapered, rounded, and/or chamfered edges 3091 at one or more of the top or bottom of the locking dog. For example, one or more of the top upstream edge, the top downstream edge, the bottom upstream edge, the bottom downstream edge, the top surface, and/or the bottom surface may be slanted, angled, and/or otherwise configured to selectively engage and disengage the body groove 3017 and the sleeve groove 3058. Similarly, one or more corners 3092 may be rounded, beveled, or otherwise profiled to allow the locking dog to slidably engage and disengage from the body groove 3017. In some embodiments, downstream movement of the orifice sleeve 3024 may cause the locking dog 3085 to engage with the upstream and/or downstream surface of the sleeve groove 3058 such that the locking dog 3085 slides into or is otherwise directed away from the body groove 3017 and toward the sleeve groove 3058. For example, the locking dog 3085 in FIG. 37 includes a slanted engagement surface 3093 at its downstream side configured to engage and urge the locking dog 3017 towards the sleeve groove 3058 as the orifice sleeve 3024 moves downstream. Additionally, the upstream, downstream, or another suitable face 3094 of the locking dog 3085 may be concave, convex, or the like. In this way, the locking dog 3085 may include one or more curvilinear (e.g., straight, curved, having both curved portions and straight portions, etc.) edges, surfaces, faces, or the like configured to extend through the intermediate sleeve 3020 and/or engage/disengage from the body groove 3017 and the sleeve groove 3058. As the orifice sleeve 3024 moves to its furthest downstream position, the locking dog may be urged into the well 3059, disengaging from the body groove 3017 and allowing downstream movement of the sliding sleeve 3020. Similarly, upstream movement of the orifice sleeve 3024 may urge the locking dog in a direction out of the well 3059 and/or the sleeve groove 3058 and/or into the body groove 3017. In some embodiments, the locking dogs may be arranged circumferentially and/or at different longitudinal locations around the orifice sleeve 3024 such that one or more locking dogs engage with one or more body grooves 3017 and/or sleeve grooves 3058. Further, the activation mechanism 3004 and the components thereof may be combined and/or may include components of other activations mechanisms disclosed herein, such as components discussed with respect to FIGS. 1-29C and 32-34E. As a non-limiting example, the tool body 3008 may include a radial housing 350, 450, 550 having the features disclosed in FIGS. 3-5, 14A to assist in the actuation of the sliding sleeve 3020.
In some embodiments, the recess 3080 is formed in the outer wall 3021 of the sliding sleeve 3020. For example, the recess 3080 may be formed in the first portion 3025 of the sliding sleeve 3020 defined by the first outer diameter 3049. In some embodiments, the sliding sleeve 3020 may have additional diameters and additional portions (e.g., a third portion, a fourth portion, etc.) and the recess 3080 and/or the latch mechanism 3040 may be defined therein. The recess 3080 is configured to house at least a portion of the components of the latch mechanism 3040. For example, in some embodiments, the latch spring 3083 may be wholly disposed within the recess 3080. The recess 3080 may further comprise the through-hole 3081. In this way, the recess 3080 may extend through the outer wall 3021 of the sliding sleeve 3020 (e.g., extend from the outer wall 3021 to the sliding sleeve chamber 3022). The recess may be any suitable shape (e.g., a circular recess, a square recess, an elongated recess, etc.). In some embodiments, multiple recesses 3080 are defined in the sliding sleeve 3020 (e.g., radially around the circumference of the sliding sleeve 3020, at varying longitudinal lengths along the sliding sleeve 3020, etc.). For example, in some embodiments, the tool body 3008 may include a first and second body groove 3017 disposed at different longitudinal lengths along the tool body 3008. Accordingly, the sliding sleeve 3020 may include two recesses 3080, each configured to selectively align with a respective body groove 3017.
The latch key 3082 may be partially disposed within the recess 3080 and may be configured to move into and/or out of the body groove 3017 and/or the sleeve groove 3058 (e.g., in response to changes in the volumetric flow rate of the drilling mud, movement of the sliding sleeve 3020, and/or movement of the orifice sleeve 3024. In some embodiments, the latch key 3082 may be other suitable latches, protrusions, and/or engagement members configured to engage and disengage the body groove 3017 and/or the sleeve groove 3058. For example, in some embodiments, locking dogs, catch keys, pressure-actuated rods, or the like may be used in addition to and/or in place of the latch key 3082. Further, the latch key 3082 may vary in shape, size, and location. As shown in FIGS. 30A-E, the latch key 3082 has a central cylindrical core 3085 (See, e.g., FIG. 30C) with a collar ring 3086 (See FIG. 30C) configured to prevent the latch key 3082 from extending beyond a set distance through the through-hole 3081. Further the collar ring 3086 is configured to receive a force from the latch spring 3083 urging the latch key 3082 away from the cap 3084 and towards the through-hole 3081.
In some embodiments, the collar ring 3086 may instead be replaced by radial arms around the core 3085. In some embodiments, the core 3085 of the latch may be square, have multiple portions configured to extend into the body groove 3017, the sleeve groove 3058, or the like. One or more latch keys 3082, locking dogs, or other suitable latches may be disposed within the one or more recesses 3080. For example, three, four, five, etc. latch keys 3082 and related components may be arranged around the circumference of the sliding sleeve 3020.
The latch spring 3083 is configured to urge the latch key 3082 or other suitable latch towards the orifice sleeve 3024 and/or towards the tool body 3008. In some embodiments, multiple latch springs 3083 may be used and may have varying spring constants. For example, in an alternative embodiment, a first latch spring may be disposed between the cap 3084 and the collar ring 3086 and a second latch spring may be disposed between the collar ring 3086 and the inner radial surface of the recess 3080. In the embodiment of FIGS. 30A-E, the latch spring 3083 is configured to urge the latch key 3082 away from the body groove 3017 and towards the sleeve groove 3058. As the orifice sleeve 3024 slides towards the compressed position 3079, the depth of the sleeve groove 3058 increases and the latch spring 3083 may cause more of the latch key 3082 to extend through the through-hole 3081, into the sleeve groove 3058, and/or out of the body groove 3017. In this way, based on the movement of the orifice sleeve 3024 in response to the volumetric flow rate of the drilling mud, the latch spring 3083 may cause the latch key 3082 to fully disengage from the body groove 3017 and enter the well 3059 of the sleeve groove 3058. When the latch key 3082 disengages from the body groove 3017, the latch mechanism 3040 may no longer restrict movement of the sliding sleeve 3020 within the tool body 3008 and the sliding sleeve 3020 may actuate upstream and/or downstream within the chamber 3012 in response to variations in the volumetric flow rate of the drilling mud.
The cap 3084 is configured to retain the latch spring 3083 (or any other suitable biasing member) within the recess 3080. Further, the cap 3084 may have an aperture therein to direct the latch key 3082 towards the inner wall of the tool body 3008 and/or towards the body groove 3017. For example, the cap 3084 may abut a portion of the core 3085 of the latch key 3082 such that the latch key 3082 remains perpendicular to the outer wall 3021 of the sliding sleeve 3020, does not become angled, dislodged from the recess 3080, or the like. The cap 3084 may be removably coupled to the recess or may be permanently coupled to the recess (e.g., via weld). In some embodiments, the cap 3084 may be integrally formed with the outer wall 2021 of the sliding sleeve 3020 such that the latch key 3082 extends through an aperture formed in the outer wall 2021.
As best shown in FIG. 30E, the selectable hole trimmer 3000 may also include one or more sealing grooves 3090. The sealing grooves 3090 may be configured to receive an O-ring or other suitable seal to prevent drilling mud fluid from flowing between the tool body 3008 and sliding sleeve 3020, the sliding sleeve 3020 and the orifice sleeve 3024, and/or otherwise circumventing the orifice 3070 and/or hindering operation of the activation mechanism 3004 (e.g., by entering the body groove 3017). The sealing grooves 3090 and/or the seals therein may further keep the area between the sleeves clear of drilling mud, grit, and/or other abrasive material. By preventing grit, abrasive material, or the like from flowing/entering the area between the sleeves, the sealing grooves 3090 and/or the seals therein may prevent the sleeves from locking up (e.g., one sleeve becoming unable to slide upstream and/or downstream relative to another sleeve caused by drilling fluid or the like located between the sleeves). Additionally, the sealing grooves 3090 and/or the seals therein may prevent the drilling fluid from mixing with and/or polluting the hydraulic fluid (e.g., in the volume 3036).
In an embodiment, the one or more selectable hole cutters 1401 comprises one or more cutter pistons 1402. In an embodiment, the cutter piston 1402 has one or more cutters 1406 affixed to the cutter piston 1402. In an embodiment, the one or more selectable hole cutters 1401 comprises a cutter blade 1406 a and one or more cutter pistons 1402. In an embodiment, the cutter blade 1406 a has one or more cutter pistons 1402 affixed to the cutter blade 1406 a. In an embodiment, the cutter blade 1406 a has one or more cutters 1406 affixed to the cutter blade 1406 a.
When the selectable hole trimmer 3000 is sliding or tripping into or out of a borehole, the selectable hole trimmer 3000, namely the one or more selectable hole cutters 1401 are in a deactivated position. The one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also the deactivated position.
Until the selectable hole trimmer 3000 is signaled to activate, the one or more selectable hole cutters 1401 will remain in the deactivated position. In other words, the one or more cutter pistons 1402 will remain in the deactivated position with the one or more cutters 1406 also in the deactivated position. The selectable hole trimmer 3000 may be activated automatically by receiving a volumetric flow rate of drilling mud equal to or above an activation threshold, by pressure or by other means.
This pressurized hydraulic fluid activates the one or more cutter pistons 1402 of the selectable hole cutters 1401, which extends the one or more cutter pistons 1402 and the one or more cutters 1406 outward radially to engage and cut a side surface of the drilled hole 130.
After the selectable hole trimmer 3000 activates, (e.g., after the flow rate of drilling mud fluid exceeds the activation threshold), the selectable hole trimmer 3000 may be configured to remain activated until the selectable hole trimmer 3000 is signaled to deactivate. In other words, once activated, the one or more selectable hole cutters 1401 will remain in the activated position until deactivated. The signal to deactivate may be by lowering the volumetric flow rate of the drilling mud fluid to and/or below a deactivation threshold (e.g., a flow rate lower than the activation threshold). The deactivation threshold may be 0 gpm, 300 gpm, or another suitable fluid flow metric.
When the one or more selectable hole cutters 1401 are deactivated, the selectable hole trimmer 3000 may return the one or more cutter pistons 1402 back to the deactivated position via a spring 1410 and return the pressurized hydraulic fluid back to a starting volume (e.g., the volume 3036 defined between the sliding sleeve 3020 and the tool body 3008).

Method of Using Fifth Alternative Downhole Device Configured as Selectable Hole Trimmer

FIG. 31 shows a flow diagram of a method 3500 of using the selectable hole trimmer 3000 of FIGS. 30A-E. As shown in FIG. 31 , the method 3500 of using the selectable hole trimmer 3000 may include step 3502 of providing a selectable hole trimmer 3000, for example, in a borehole, in a drill string having a drill bit receiving a flow of drilling fluids, or the like; step 3506 of receiving, by the selectable hole trimmer 3000, a flow of drilling fluids above an activation threshold; step 3508 of, in response to receiving the flow above the activation threshold, disengaging a latch mechanism 3040 from a body groove 3017 of a tool body 3008 via a movement of an orifice sleeve 3024; step 3510 of, after disengaging the latch mechanism 3040 from the body groove 3017, pressurizing a hydraulic fluid (e.g., in a volume 3036) via a first movement of a sliding sleeve 3020 to activate a selectable hole cutter 1401; step 3512 of receiving, by the selectable hole trimmer 3000, a flow of drilling fluids that meets (or falls below) a deactivation threshold; step 3514 of, in response to receiving the flow that meets (or falls below) the deactivation threshold, engaging the body groove 3017 with the latch mechanism 3040 via a second movement of the sliding sleeve 3020; and step 3516 of, in response to the second movement of the sliding sleeve 3020, deactivating the selectable hole cutter 1401.
Turning back to FIGS. 30A-E, one example of using the selectable hole trimmer 3000 may proceed as follows. The method 3500 may include providing a selectable hole trimmer 3000 on a downhole device. For example, the selectable hole trimmer 3000 may slide or trip into a borehole with the selectable hole cutters 1401 in the retracted position (e.g., in a disengaged state). Accordingly, the selectable hole trimmer 3000 may slide in and/or out of the borehole with relatively little friction and without the selectable hole cutters 1401 dragging/cutting at the walls of the borehole. The selectable hole trimmer 3000 may receive a flow of drilling mud below the activation threshold. While the flow of drilling mud remains below the activation threshold, the activation mechanism 3004 of the selectable hole trimmer 3000 may resemble the selectable hole trimmer 3000 of FIG. 30A. That is, the latch mechanism 3040 may be aligned and extending into the body groove 3017 of the tool body 3008 and not into the sleeve groove 3058 in the orifice sleeve 3024. In other words, the selectable hole trimmer 3000 may remain in the “off” and/or neutral position with the selectable hole cutters 1401 deactivated until the flow of drilling mud fluid meets and/or exceeds the activation threshold (e.g., 600 gpm).
Comparing FIG. 30A and FIG. 30D, the effect of increasing the flow towards the activation threshold is illustrated. For example, at no flow or relatively little flow (e.g., flow below the deactivation threshold), the selectable hole trimmer 3000 may resemble the configuration shown in FIG. 30A. In FIG. 30A, sliding sleeve 3020 may be located at its further upstream position (e.g., upstream position 3077). The sliding sleeve spring 3028 may likewise be positioned at its most expanded state. The latch mechanism 3040 (e.g., the latch key 3082) may be inserted into the body groove 3017 and may prevent downstream movement of the sliding sleeve 3020. The orifice sleeve 3024 may be located at its furthest upstream position 3078 (e.g., at the upstream most edge of the recess length 3031 of the orifice sleeve recess 3030). The orifice sleeve spring 3032 may likewise be positioned at its most expanded state. Accordingly, the volume 3036 may be at its most expanded state, drilling mud may be prevented from exiting via the bypass nozzles 3015, and the selectable hole cutters 1401 may be deactivated.
However, as the flow rate of the drilling mud increases towards the activation threshold, the selectable hole trimmer 3000 may transition from the configuration of FIG. 30A to the configuration of FIG. 30D. For example, the increase in the flow of drilling mud moves the orifice sleeve 3024 downstream against the orifice sleeve spring 3038 (which may be notably stiffer than the sliding sleeve spring 3028). As the orifice sleeve 3024 moves downstream and the orifice sleeve spring 3032 begins to compress, the sliding sleeve 3020 may not move and the sliding sleeve spring 3028 may not compress because the latch mechanism 3040 (e.g., via the latch key 3082) holds the sliding sleeve 3020 in place against the tool body 3008 via engagement with the body groove 3017.
When the flow rate of the drilling mud fluid meets and/or exceeds the activation threshold, the orifice sleeve 3024 may be located in the configuration shown in FIG. 30D (e.g., the orifice sleeve 3024 moves downstream and compresses the orifice sleeve spring 3032 such that the latch mechanism 3040 aligns with the well 3059 and/or the edge 3060 of the sleeve groove 3058 in the orifice sleeve 3024). When the latch mechanism 3040 aligns with the well 3059 and/or the edge 3060 of the sleeve groove 3058, the latch spring 3083 urges the latch key 3082 through the through-hole 3081 a sufficient distance to disengage the latch key 3082 and/or the latch mechanism 3040 from the body groove 3017. Thereupon and/or shortly thereafter, the activation threshold flow rate (e.g., 600 gpm) causes a large force on the sliding sleeve 3020 and the sliding sleeve spring 3028 to release the sliding sleeve 3020 to “pop” (from the force of the flow) or move rapidly against the sliding sleeve spring 3028. The increased stiffness of the orifice sleeve spring 3032 compared to the decreased stiffness of the sliding sleeve spring 3028 may contribute to the “pop” and increase the rapidity of the first movement of the sliding sleeve 3020 depending on the magnitude of the difference between the orifice sleeve spring 3032 constant k and the smaller sliding sleeve spring 3028 constant k. The first movement of the sliding sleeve 3020 pressurizes the hydraulic fluid around the sliding sleeve spring 3028 and energizes the cutter pistons 1402 to activate/extend the selectable hole cutters 1401.
The first movement of the sliding sleeve 3020 is best shown by comparing FIG. 30D and FIG. 30E. In FIG. 30E, the sliding sleeve 3020 is positioned in its downstream-most position (e.g., the compressed position 3087) and the sliding sleeve spring 3028 is at its most compressed state. Further, if the drilling mud flow rate is above the deactivation threshold (e.g., above 300 gpm for example), the sliding sleeve 3020 may be held by the force of the drilling mud flow against the sliding sleeve spring 3028 and a stop block (not shown but, for example, at the downstream end of the sliding sleeve 3020). In other words, the sliding sleeve 3020 may stay in the compressed position 3087 and the cutter pistons 1402 may remain fully extended until the drilling mud flow rate falls below the deactivation threshold.
Additionally, following the first movement of the sliding sleeve 3020, the sliding sleeve 3020 may uncover the bypass nozzles 3015. Accordingly, in some embodiments, the method 3500 may include the step of uncovering the bypass nozzles 3015 to allow a bypass flow as a signal to the rig floor of a slightly lower pressure. Specifically, the flow rate compared to the pressure may be used to determine whether the selectable hole trimmer 3000 is in the active state or in the deactivated state.
The selectable hole trimmer 3000 can operate with drilling mud flow rates above the deactivation threshold (e.g., 300 gpm) and as high as desired. Once the latch mechanism 3040 disengages from the body groove 3017 (e.g., once the flow rate meets and/or exceeds the activation threshold), upward or downward variation of the flow rate may not allow the sliding sleeve 3020 to move from the stop unless and/or until the flow rate falls below and/or meets the deactivation threshold. In this way, when it is desired to deactivate the selectable hole cutters 1401, the flow rate may be reduced to below the deactivation threshold (e.g., 300 gpm). In response to receiving the flow rate that meets and/or falls below the deactivation threshold, a second movement of the sliding sleeve 3020 may occur to cause the latch mechanism 3040 to engage the body groove 3017. For example, upon and/or shortly after the flow rate meets and/or falls below the deactivation threshold, the sliding sleeve spring 3028 may urge the sliding sleeve 3020 upstream (e.g., the second movement) until the sleeve groove 3058 of the orifice sleeve 3024 again aligns with the body groove 3017 and allows the latch key 3082 to engage with (e.g., snap back to the original position inside) the body groove 3017. Because the flow rate is below the activation threshold (e.g., 600 gpm) the orifice sleeve 3024 may be urged back to (e.g., by the stiff orifice sleeve spring 3032) and stay in its upstream position 3078 relative to the sliding sleeve 3020, and the cutter pistons 1402 may deactivate. In short, upon lowering the drilling mud flow rate to and/or below the deactivation threshold, the selectable hole trimmer 3000, via the second movement of the sliding sleeve 3020, may return to the configuration of FIG. 30A and deactivate the cutter pistons 1402.
In some embodiments, the steps of the method 3500 may be repeated, performed in a different order, or have intermittent and/or intervening steps. In other embodiments, some steps of the method 3500 may be omitted, replaced with varied steps, or the like.

Sixth Alternative Downhole Device Configured as Selectable Hole Trimmer

FIG. 32 shows a schematic view of another exemplary embodiment of a downhole device configured as a selectable hole trimmer 4000. The selectable hole trimmer 4000 may be configured as a concentric device that has expandable/retractable cutters (e.g., selectable hole cutters 1401) to trim ledges, discontinuities, and the like from a borehole such as the drilled hole 130. Specifically, FIG. 32 illustrates a schematic view of one embodiment of an activation mechanism 4004 (e.g., an actuator, a sliding assembly, one or more components configured to selectable activate and deactivate the selectable hole cutters 1401, etc.) of the selectable hole trimmer 4000 which may utilize a sleeve groove 4058 and a guide pin 4059 to selectively activate and deactivate the cutter pistons 1402 of the tool. For example, the activation mechanism 4004 may allow the selectable hole cutters 1401 to activate and deactivate based on a predefined pattern of changes in the volumetric flow rate of drilling mud flowing through the drill string 120.
In some embodiments, the sleeve groove 4058 may be in the form of a track that loops circumferentially around at least one surface of the selectable hole trimmer 4000 (e.g., the track may span the circumference of a sleeve such that the end of the track loops back to the beginning of the track, so that the guide pin 4059 may repetitively complete a circuit of the track, etc.). In this way, the track may direct the axial displacement and axial rotation of a sleeve based on the length and geometry (e.g., angled edges, curved edges, etc.) of one or more grooves in the track. Accordingly, as the guide pin 4059 moves along the sleeve groove 4058 (e.g., the track) in response to changes in the flow rate of drilling mud, the sleeve may move upstream and/or downstream guided by the track to compress hydraulic fluid and to selectively activate and/or deactivate cutter pistons 1402.
The activation mechanism 4004 may be interoperable with other downhole devices disclosed herein. For example, the activation mechanism 4004 may provide an alternative arrangement of components that allows selective activation and deactivation of selectable hole cutters 1401, actuators, cutter pistons, and the like discussed above.
As shown in FIG. 32 , the selectable hole trimmer 4000 comprises a tool body 4008. The tool body 4008 may generally have a cylindrical outer wall 4009 having an outer diameter 4010 and an inner diameter 4011 that defines a chamber 4012 through which drilling mud fluid may flow. The tool body 4008 may include one or more bypass nozzles 4015 extending from the outer wall 4009 towards the chamber 4012. Like the bypass nozzles 3015, the bypass nozzles 4015 may not be included in the tool body 4008 and/or may be omitted. The bypass nozzles 4015 (if present) may be configured to selectively allow drilling mud to flow from the tool body into the borehole, which may be used to send a signal (e.g., via a pressure drop compared to fluid flow rate) to the rig floor, operators of the selectable hole trimmer 4000, etc. The tool body 4008 may have one or more connections at its ends (such as a box connection, a pin connection, or the like) to enable the tool body 4008 to sealingly couple to another tool body 4008, another downhole device, or any other suitable feature of the drill string 120.
The outer wall 4009 of the tool body 4008 may include one or more selectable hole cutters 1401 disposed therein. Further, the tool body 4008 may include one or more hydraulic fluid ports 4017 configured energize (e.g., selectively activate and/or deactivate) the selectable hole cutters 1401 via a pressure increase or decrease of the hydraulic fluid therein. Specifically, the activation mechanism 4004 of the selectable hole trimmer 4000 may selectively energize the hydraulic fluid of the hydraulic fluid ports 4017 to extend and/or retract the selectable hole cutters 1401.
The left side of FIG. 32 may correspond to a drilling mud inlet 4016 of the tool body 4008 and a drilling mud outlet (not shown) of the tool body 4008 may be located in the direction of the right-side FIG. 32 relative to the tool body 4008 (e.g., down bore of the drilling mud inlet 4016). The activation mechanism 4004 may be disposed (e.g., concentrically located) within the tool body 4008 of the selectable hole trimmer 4000 and utilize drilling mud fluid flowing through the chamber 4012 to selectively activate or deactivate selectable hole cutters 1401, actuators, nozzles, and/or other components of the selectable hole trimmer 4000. Specifically, selectable hole cutters 1401 may be located on the tool body 4008 and may be hydraulicly and/or fluidly coupled to the activation mechanism 4004 such that the activation mechanism 4004 allows for the selectable hole cutters 1401 to toggle between an activated position and a deactivated position.
The tool body 4008 and the chamber 4012 thereof may include an inner wall 4019 defined by the inner diameter 4011. The chamber 4012 may include a drilling mud volume flowing therethrough. A centerline 4018 may pass through the center of the chamber 4012 and/or the tool body 4008. As shown in FIG. 32 , the inner diameter 4011 may vary (e.g., the tool body 4008 may include a first inner diameter, a second inner diameter, or the like as shown by the increases in size of the inner diameter 4011 as the tool body 4008 extends from the upstream side to the downstream side, or left to right in FIG. 32 ). Specifically, in some embodiments, the inner diameter 4011 may form a portion of the inner wall 4019 (e.g., a channel, a recess, a receiving slot, etc.) of the chamber 4012 configured to engage with and/or receive an intermediate sleeve 4020. In some embodiments, the intermediate sleeve 4020 may be configured to remain at a fixed location within the tool body 4008. For example, as shown in FIG. 32 , the intermediate sleeve 4020 is disposed within the tool body 4008 between ledges, stop blocks, or the like to prevent upstream or downstream movement and/or axial rotation of the intermediate sleeve 4020.
The intermediate sleeve 4020 may comprise a generally cylindrical outer wall 4021 having one or more outer diameters such as a first outer diameter 4022 and a second outer diameter 4023 (illustrated in FIG. 32 as a first and second outer radius, respectively). The outer wall 4021 of the intermediate sleeve 4020 may be configured to engage the inner wall 4019 of the tool body 4008 at one or more of the first outer diameter 4022 and/or the second outer diameter 4023. As shown in FIG. 32 , both the first outer diameter 4022 and the second outer diameter 4023 of the intermediate sleeve 4020 are configured to engage the inner wall 4019 of the tool body 4008 (e.g., of the chamber 4012) to prevent the intermediate sleeve 4020 from sliding within the tool body 4008 (e.g., via one or more shoulders at abutting surfaces of the tool body 4008 and the intermediate sleeve 4020).
Turning briefly to FIG. 34A, in other embodiments, only one of the first outer diameter 4022 and/or the second outer diameter 4023 of the intermediate sleeve 4020 may engage the inner wall 4019 of the tool body 4008. In this way, a pressurized volume 4065 may be formed between the intermediate sleeve 4020 and the tool body 4008. As explained herein, and similar to the pressurized volumes (e.g., volumes 1922, 2122) discussed above, the pressurized volume 4065 may act as a hydraulic fluid chamber wherein hydraulic fluid is pressurized by the activation mechanism 4004 to selectively activate selectable hole cutters 1401.
Turning back to FIG. 32 , the intermediate sleeve 4020 may also include an inner wall 4024 defined by one or more inner diameters of the intermediate sleeve 4020. The inner wall 4024 may be configured to engage a sliding sleeve 4030 disposed inside the tool body 4008 and/or disposed inside the intermediate sleeve 4020. Specifically, the inner wall 4024 of the intermediate sleeve 4020 may include at least one of the sleeve groove 4058 and/or the guide pin 4059 to facilitate axial displacement of the sliding sleeve 4030 based on, for example, variations in the flow rate of drilling mud fluid.
The sliding sleeve 4030 may comprise a generally cylindrical outer wall 4031 configured to slidably fit within the chamber 4012 of the tool body 3008 and/or within the inner wall 4024 of the intermediate sleeve 4020. For example, the outer wall 4031 of the sliding sleeve 4030 may have a varying outer diameter 4032 (e.g., a first outer diameter, a second outer diameter, etc.) corresponding to and/or configured to slidably engage at least one of the inner wall 4019 of the tool body 4008 and/or the inner wall 4024 of the intermediate sleeve 4020. Specifically, the outer wall 4031 of the sliding sleeve 4030 may have an outer diameter 4032 corresponding to and/or configured to slidably engage the inner wall 4024 of the intermediate sleeve 4020 to form an interface therebetween. The sleeve groove 4058 and/or the guide pin 4059 may be located at the interface between the sliding sleeve 4030 and the intermediate sleeve 4020 such that the movement of the sliding sleeve 4030 relative to the intermediate sleeve 4020 allows for the activation mechanism 4004 to selectively control the activation and deactivation of the selectable hole cutters 1401.
The outer wall 4031 of the sliding sleeve 4030 may also include a piston portion 4033 such as a protrusion, a ring collar, or the like. The piston portion 4033 may be configured to pressurize hydraulic fluid in response to axial movement of the sliding sleeve 4030. As shown in FIG. 32 , the piston portion 4033 of the sliding sleeve 4030 may extend beyond the outer diameter 4032 and/or the outer wall 4031 of the sliding sleeve 4030. Further, the piston portion 4033 may be configured to sealingly engage the inner wall 4019 of the tool body 4008. For example, as shown in FIG. 32 , a seal 4068 may be disposed between the piston portion 4033 and the tool body 4008.
In this way, in some embodiments, a volume 4066 of the activation mechanism 4004 may be defined by one or more of the piston portion 4033 of the sliding sleeve 4030, the outer wall 4031 of the sliding sleeve 4030, the inner wall 4019 of the tool body 4008, one or more seals 4068, and/or at least one surface of the intermediate sleeve 4020. The volume 4066 may contain hydraulic fluid (e.g., oil) and may be fluidly and/or hydraulicly coupled to the one or more hydraulic fluid ports 4017 (e.g., defined in the tool body 4008). The hydraulic fluid ports 4017 may, in turn, be hydraulicly and/or fluidly coupled to the one or more selectable hole cutters 1401 such that pressurization/compression of the volume 4066 may selectively activate/deactivate the cutter pistons 1402 thereof. (See, e.g., 14B).
The volume 4066 may include a sliding sleeve spring 4067 configured to abut and/or apply a force to the piston portion 4033 of the sliding sleeve 4030. In some embodiments, an upstream end of the sliding sleeve spring 4067 abuts the piston portion 4033 of the sliding sleeve 4030. The sliding sleeve spring 4067 may also be configured to abut the intermediate sleeve 4020, which may act as a stop block for the sliding sleeve spring 4067. In this way, movement of the sliding sleeve 4030 downstream/upstream within the tool body 4008 (e.g., to the right/left in FIG. 32 ) may compress/allow expansion of the sliding sleeve spring 4067 and reduce/increase the size of the volume 4066, respectively. When the sliding sleeve 4030 moves downstream, the piston portion 4033 may compress the sliding sleeve spring 4067 and the volume 4066, pressurizing the volume 4066 and the hydraulic fluid therein. The compressed sliding sleeve spring 4067 may act to urge the sliding sleeve 4030 back in the upstream direction. However, when the force of the sliding sleeve spring 4067 is overcome (e.g., by a fluid flow rate of drilling mud exceeding an activation threshold such as a predefined flow rate), the force on the sliding sleeve 4030 from the drilling mud flow may exceed the force of the sliding sleeve spring 4067 and compress the volume 4066. Accordingly, the downstream movement of the sliding sleeve 4030 may energize the hydraulic fluid in the volume 4066 and convey energy through the hydraulic fluid ports 4017 to activate (e.g., extend) the selectable hole cutters 1401.
In contrast, when the force of the sliding sleeve spring 4067 overcomes the force of the drilling mud flow, the sliding sleeve spring 4067 may urge the sliding sleeve 4030 back upstream to expand the volume 4066, lower the pressure therein, and deactivate/retract the selectable hole cutters 1401.
However, as explained herein, the movement of the sliding sleeve 4030 may be guided, controlled, and/or otherwise directed by an engagement of the sleeve groove 4058 and the guide pin 4059. In short, the interface between the sliding sleeve 4030 and the intermediate sleeve 4020 (e.g., the engagement of the guide pin 4059 in the sleeve groove 4058) may selectively prevent/allow upstream and downstream movement of the sliding sleeve 4030.
For example, the sleeve groove 4058 may include a portion of the track that allows only limited upstream displacement of the sliding sleeve 4030 and thus prevents the sliding sleeve spring 4067 from urging the sliding sleeve 4030 fully upstream, allowing the volume 4066 to remain compressed and the cutter pistons 1402 to remain engaged even at fluid flow rates below the activation threshold and/or a locking threshold. The activation threshold may include a designated volumetric flow rate of drilling mud fluid at which the sliding sleeve 4030 is urged to its downstream-most position, at which the cutter pistons 1402 may be active, and which may allow for toggling the selectable hole trimmer 4000 between the activated and deactivate state. The locking threshold may include a designated volumetric flow rate, smaller than the activation threshold. Specifically, after reaching the activation threshold and lowering the flowrate to the locking threshold, the selectable hole trimmer 4000 will operate with either the selectable hole cutters 1401 locked in the extended state or locked in the retracted state for fluid flow rates between 0 gpm and the locking threshold flow rate. In some embodiments, to toggle from the extended state to the retracted state or vice versa, the fluid flow rate must increase to or above the activation threshold then decrease below the locking threshold. In some embodiments, the activation threshold may be 660 gpm and the locking threshold may be 600 gpm.
By varying the fluid flow rate (e.g., by increasing the fluid flow rate above the activation threshold a second time), the sliding sleeve 4030 may again move downstream and the position of the guide pin 4059 may shift along the sleeve groove 4058, in some embodiments, causing a rotation of the sliding sleeve 4030 as the guide pin 4059 is directed to a portion of the track which may allow greater upstream displacement of the sliding sleeve 4030. Accordingly, the sliding sleeve spring 4067 may then act to urge the sliding sleeve 4030 back upstream when the flow rate of the drilling mud fluid falls below the activation threshold and/or the deactivation threshold. In other words, the track may vary in geometry (e.g., may have a J-lock configuration or other suitable geometry) such that the sliding sleeve 4030 may alternate between relatively small and relatively large lengths of axial displacement in response to predefined variations in and/or patterns of fluid flow rate.
Like the tool body 4008, the sliding sleeve 4030 may define a sliding sleeve chamber 4034 therein. Drilling mud may enter the sliding sleeve chamber 4034 via a drilling mud inlet 4035 such as an orifice of the sliding sleeve 4030 and flow through at least a portion of the sliding sleeve chamber 4034. The drilling mud inlet 4035 may include an orifice diameter 4036 that may be smaller than an inner diameter 4011 of the tool body 4008 or may otherwise constrict the flow of drilling mud fluid such that one or more pressure drops occur as the drilling mud flows across the length of the of the sliding sleeve 4030. The pressure drop, in turn, may cause a force to urge the sliding sleeve 4030 downstream within the tool body 4008.
The sliding sleeve chamber 4034 and/or the sliding sleeve 4030 may include drilling mud ports 4039 that may selectively align with one or more ports, chambers, or the like defined in the intermediate sleeve 4020, in the tool body 4008, or in another component of the selectable hole trimmer 4000. Accordingly, upstream and/or downstream movement of the sliding sleeve 4030 may align the one or more drilling mud ports 4039 with corresponding components and divert drilling mud from the sliding sleeve chamber 4034 through the drilling mud ports 4039.
For example, as shown in FIG. 32 , downstream movement of the sliding sleeve 4030 may align the drilling mud port 4039 with the bypass nozzle 4015 of the tool body 4008. In this way, when the volume 4066 is compressed and the selectable hole cutters 1401 are extended, a signal may be sent (e.g., via the pressure drop caused by allowing fluid flow through the bypass nozzle 4015) indicating that the selectable hole cutters 1401 are in an activated state. In other embodiments, the drilling mud ports 4039 may align with chambers to pressurize fluid therein, cutter pistons 1402 to energize/extend cutter pistons 1402, nozzles (e.g., nozzle 1404) to direct drilling fluid towards active selectable hole cutters 1401, and/or other components for other suitable purposes.
The sleeve groove 4058 and the guide pin 4059 may be arranged in various locations and in varied configurations within the selectable hole trimmer 4000. For example, in some embodiments, multiple sleeve grooves 4058, guide pins 4059, sliding sleeves 4030, and/or intermediate sleeves 4020 may be disposed within the tool body 4008. For example, a first sliding sleeve 4030 and intermediate sleeve 4020 may selectively control cutter pistons 1402 on an upstream side of the tool body 4008 while a second sliding sleeve 4030 and a second intermediate sleeve 4020 may selectively control cutter pistons 1402 on a downstream side of the tool body 4008. Other variations and combinations with the other activation mechanisms (e.g., activation mechanism 3004) and downhole devices are contemplated by this disclosure.
In some embodiments, the inner wall 4024 of the intermediate sleeve 4020 and/or the outer wall 4031 of the sliding sleeve 4030 may comprise the sleeve groove 4058 (e.g., a track, channel, connection of recesses, etc.) configured to engage the guide pin 4059. For example, the sleeve groove 4058 may extend around the circumference of at least one of the intermediate sleeve 4020 and/or the sliding sleeve 4030. Similarly, the guide pin 4059 may be coupled to at least one of the intermediate sleeve 4020 and/or the sliding sleeve 4030 such that movement of the sliding sleeve 4030 is directed, controlled, and/or otherwise guided by the engagement of the guide pin 4059 and the sleeve groove 4058. For example, in the embodiment shown in FIG. 32 , the sleeve groove 4058 is defined in the inner wall 4024 of the fixed intermediate sleeve 4020. The guide pin 4059 is coupled to the sliding sleeve 4030 such that, as the sliding sleeve 4030 moves, its axial displacement and/or axial rotation is affected by the contact between the guide pin 4059 traveling in the sleeve groove 4058 of the intermediate sleeve 4020.
Turning to FIG. 33 , the sliding sleeve 4030 is shown disposed inside a (semi-transparent) intermediate sleeve 4020, which in turn is disposed inside the tool body 4008. As shown in FIG. 33 , the sleeve groove 4058 (e.g., the track, channel, structure configured to guide the movement of the sliding sleeve 4030) may be defined in the outer wall 4031 of the sliding sleeve 4030. Similarly, the guide pin 4059 may be coupled (e.g., fixed) to the inner wall 4024 of the intermediate sleeve 4020 and may extend into the sleeve groove 4058. In this way, as the sliding sleeve 4030 is displaced (e.g., moves upstream and/or downstream within intermediate sleeve 4020, the tool body 4008, etc.), its axial position within the tool body 4008 and/or axial rotation are affected by the interface between the sleeve groove 4058 traveling and contacting the guide pin 4059 of the fixed intermediate sleeve 4020. Specifically, the geometry of the sleeve groove 4058 may be defined such that the guide pin 4059 comes to rest at various positions that allow different axial displacements of the sliding sleeve 4030 as the drilling mud fluid flow repeatedly raises above then falls below the activation threshold (e.g., 660 gpm, 700 gpm, etc.).
For example, in FIG. 33 , the sleeve groove 4058 and the guide pin 4059 are shown with the guide pin 4059 at a first position F in the sleeve groove 4058. Compared to a second position G of the guide pin 4059 within the sleeve groove 4058, the position F allows a smaller amount of upstream movement of the sliding sleeve 4030 while the position G allows a larger amount of upstream movement of the sliding sleeve 4030. In other words, in the embodiment of FIG. 33 , the sliding sleeve 4030 is located further upstream while the guide pin 4059 is located at position G than when the guide pin 4059 is located at position F.
In some embodiments (e.g., where a sliding sleeve spring 4067 (not shown) is positioned downstream of the sliding sleeve 4030 and urges the sliding sleeve 4030 upstream), the first position F may correspond to flow below the activation threshold, which may include relatively little or no flow of drilling mud through the selectable hole trimmer 4000. For example, for an activation threshold of 660 gpm, drilling mud fluid flowing at 300 gpm (or other flow rates below the activation threshold) would not overcome the spring force of the sliding sleeve spring 4067 urging the sliding sleeve 4030 upstream. Accordingly, even though drilling mud fluid below the activation threshold may be flowing through the selectable hole trimmer 4000, the sliding sleeve 4030 may be positioned upstream/to the left via the force of the sliding sleeve spring 4067 and the guide pin 4059 may come to rest in the downstream position F of the sleeve groove 4058.
In this way, when the flow is below the activation threshold, the sliding sleeve 4030 displaces in an upstream direction, and the fixed guide pin 4059 of the intermediate sleeve 4020 effectively “moves” downstream (e.g., to the right) relative to the sleeve groove 4058. Similarly, when the flow meets or exceeds the activation threshold, the force from the flow on the sliding sleeve 4030 may overcome the upstream force acting on the sliding sleeve (e.g., a spring force). Accordingly, the sliding sleeve 4030 may displace in a downstream direction, and the fixed guide pin 4059 of the intermediate sleeve 4020 effectively “moves” upstream (e.g., to the left) relative to the sleeve groove 4058.
For example, increasing the fluid flow above the activation threshold in the configuration shown in FIG. 33 may result in axial displacement of the sliding sleeve 4030 in the direction of arrow AD and may result in axial rotation of the sliding sleeve 4030 in the direction of the arrow AR. Specifically, the axial rotation may result from the sliding sleeve 4030 moving downstream such that the first slanted surface 4041 contacts the guide pin 4059. As the force from the drilling mud fluid continues to urge the sliding sleeve 4030 downstream, the guide pin 4059 may cause the sliding sleeve 4030 to rotate in the direction AR to allow further downstream displacement. Accordingly, the sliding sleeve 4030 may move downstream until a trigger position T moves along the path 4050, guided by the contact of the guide pin 4059 against the edges (e.g., the first slanted surface 4041) of the sleeve groove 4058. While the fluid flow remains at and/or above the activation threshold, the force from the fluid flow will overpower the sliding sleeve spring 4067 and the trigger position T will remain located at the guide pin 4059.
However, when the fluid flow rate drops below the activation threshold, the force of the sliding sleeve spring 4067 may overcome the force of the fluid flow and cause displacement of the sliding sleeve 4030 in the upstream direction. Accordingly, the sliding sleeve 4030 may move such that the trigger position T moves upstream until the sleeve groove 4058 contacts the guide pin 4059 at the second slanted surface 4042. While the flow of drilling mud fluid remains below the activation threshold, the spring force may continue to displace the sliding sleeve 4030 further upstream (e.g., in the opposite direction of the arrow AD). Accordingly, the contact between the second slanted surface 4042 and the guide pin 4059 may cause the sliding sleeve 4030 to further rotate in the axial direction AR until the sliding sleeve comes to rest with the second position G located at the guide pin 4059.
As the volumetric flow rate of drilling mud fluid cycles between exceeding the activation threshold and falling below the activation threshold, the sliding sleeve 4030 may continue to move upstream and/or downstream and rotate in the direction AR. For example, the sliding sleeve 4030 may rotate in the direction AR responsive to the changes in fluid flow rate until the sleeve groove 4058 reaches the additional second position G′, then the additional trigger position T′, before returning to its starting location with the first position F located at the guide pin 4059.
Turning to FIGS. 34A-E, in some embodiments, selective movement of the sliding sleeve 4030 via cycling the flow rate of drilling mud fluid above and below the activation threshold may allow for selective activation and deactivation of the selectable hole cutters 1401.
In FIG. 34A, an embodiment of the selectable hole trimmer 4000 is shown having a tool body 4008, an intermediate sleeve 4020, a sliding sleeve 4030, and an activation mechanism 4004 comprising at least a guide pin 4059 (See FIGS. 30B and 30D), and a sleeve groove 4058.
The intermediate sleeve 4020 is disposed within the tool body 4008 and may be fixed in place (e.g., via one or more stop blocks, by an interface between a ledge, stop collar, or the like). In the embodiment shown in FIGS. 34A-E, the intermediate sleeve 4020 includes the guide pin 4059 coupled to the inner wall 4024 and extending into (e.g., engaging) the sleeve groove 4058 of the sliding sleeve 4030. Accordingly, the sliding sleeve 4030 is disposed within the intermediate sleeve 4020 and may displace upstream and/or downstream based on at least the flow rate of drilling mud (e.g., tending to urge the sliding sleeve 4030 downstream), the force of the sliding sleeve spring 4067 (e.g., tending to urge the sliding sleeve 4030 upstream), and the engagement between the sleeve groove 4058 and the guide pin 4059.
The at least one sleeve groove 4058 includes a track, recess, channel, or the like formed in the outer wall 4031 of the sliding sleeve 4030 (e.g., at an interface between outer wall 4031 of the sliding sleeve 4030 and the inner wall 4024 of the intermediate sleeve 4020). The sleeve groove 4058 may include one or more slanted, curved, straight, tapered, beveled, chamfered, etc. edges and a groove bottom and/or floor. The bottom/floor of the groove may comprise the material of the sliding sleeve 4030. In other words, the sleeve groove 4058 may be formed by machining, carving, or otherwise removing material from the outer wall 4031 of the sliding sleeve 4030. In some embodiments, the sleeve groove 4058 may be formed with the sliding sleeve 4030 (e.g., the sliding sleeve 4030 may be cast having an indention in the desired shape of the sleeve groove 4058). In some embodiments, the bottom/floor and/or the edges of the sleeve groove 4058 may be coated with a wear resistant material, a friction reducing material, or the like. The sleeve groove 4058 may be configured such that the one or more guide pins 4059 may extend into the sleeve groove 4058 (e.g., to slidably engage the edges and/or groove bottom/floor).
As shown in FIG. 34A, the sleeve groove 4058 may be arranged circumferentially around the sliding sleeve 4030 such that portions of the sleeve groove 4058 reach and/or extend to different axial lengths along the outer wall 4031 of the sliding sleeve 4030. For example, the sleeve groove 4058 may define at least one first position 4078, at least one trigger position 4079, and at least one second position 4080, each disposed at different respective axial lengths from the drilling mud inlet 4035 of the sliding sleeve 4030.
The first position 4078 may be located at the furthest downstream end of the sleeve groove 4058. The first position 4078 may be associated with a neutral or “off” position of the selectable hole trimmer 4000. In the neutral or “off” position, the selectable hole cutters 1401 may remain retracted and allow entry and removal of the selectable hole trimmer 4000 from the borehole with relatively little drag.
For example, when the guide pin 4059 is engaged with the first position 4078, the sliding sleeve 4030 may be at its furthest upstream location within the tool body 4008 and/or the intermediate sleeve 4020, and the sliding sleeve spring 4067 may be at its most expanded state. Further, while the guide pin 4059 is engaged with the first position 4078, the sliding sleeve 4030 may cover and prevent drilling mud from flowing through the bypass nozzles 4015 (e.g., the drilling mud ports 4039 of the sliding sleeve 4030 may be unaligned with the bypass nozzles 4015). In this way, pressurized volume 4065 (e.g., a hydraulic fluid chamber) may be in an expanded or unenergized state such that the cutter pistons 1402 are retracted.
The trigger position 4079 may be located at a furthest upstream end of the sleeve groove 4058. As shown in FIG. 34B, the sliding sleeve 4030 may move such that the trigger position 4079 engages the guide pin 4059 when the flow rate of the drilling mud reaches the activation threshold (e.g., 660 gpm). Specifically, as indicated by path 4045 in FIG. 34B, the sliding sleeve 4030 may begin (e.g., at no flow of drilling mud) with the first position 4078 engaging the guide pin 4059. The flow rate may then increase to the activation threshold (e.g., 660 gpm) and the sliding sleeve 4030 may displace downstream in the direction of arrow AD until a first slanted surface 4041 contacts the guide pin 4059. As the sliding sleeve 4030 continues to displace downstream, contact between the first slanted surface 4041 and the guide pin 4059 may also cause axial rotation of the sliding sleeve 4030 in the direction of arrow AD before the trigger position 4079 engages the guide pin 4059.
The trigger position 4079 may be associated with an active or “on” position of the selectable hole trimmer 4000. In the active or “on” position, the selectable hole cutters 1401 may extend and trim or remove material, discontinuities, or the like from the borehole. Further, the trigger position 4079 may allow selective transitioning of the selectable hole trimmer 4000 between the active/“on” state and the neutral/“off” state.
For example, an illustrative configuration of the selectable hole trimmer 4000 where the trigger position 4079 engages the guide pin 4059 is shown in FIG. 34C. When the guide pin 4059 is engaged with the trigger position 4079, the sliding sleeve 4030 may be at its furthest downstream location within the tool body 4008 and/or the intermediate sleeve 4020, and the sliding sleeve spring 4067 may be at its most compressed state. The downstream movement of the sliding sleeve 4030 may pressurize and/or energize the hydraulic fluid in the pressurized volume 4065, for example, through one or more annular rings 4085 which may move to compress the volume of the hydraulic fluid. Accordingly, while the guide pin 4059 is engaged with the trigger position 4079, the selectable hole cutters 1401 may engage or otherwise enter the active state such that the cutter pistons 1402 are extended in the direction of arrows 4086. Further, while the guide pin 4059 is engaged with the trigger position 4079, the drilling mud ports 4039 of the sliding sleeve 4030 may align with the bypass nozzles 4015 extending through the tool body 4008 and/or the intermediate sleeve 4020. Accordingly, drilling mud may flow or spray through the bypass nozzles 4015 (e.g., through a signal vent and as a signal to the rig floor indicating activation of the cutter pistons 1402) as the cutter pistons 1402 extend/activate.
The second position 4080 may be located at a position along the length of the sleeve groove 4058 upstream of the first position 4078 and downstream of the trigger position 4079. As shown in FIG. 34D, the sliding sleeve 4030 may move such that the second position 4080 engages the guide pin 4059 when the flow rate of the drilling mud falls below the activation threshold (e.g., 660 gpm) and/or the locking threshold (e.g., 600 gpm). As an example and as indicated by path 4046 in FIG. 34D, after following the path 4045 in FIG. 32B (e.g., starting with the guide pin 4059 engaging the first position 4078 then increasing the flow rate to the activation threshold), the flow rate may fall below the activation threshold (e.g., 660 gpm) and/or the locking threshold (e.g., 600 gpm) and the sliding sleeve 4030 may displace upstream (e.g., in the direction of arrow AD′) until a second slanted surface 4042 contacts the guide pin 4059. As the sliding sleeve 4030 continues to displace upstream, contact between the second slanted surface 4042 and the guide pin 4059 may also cause axial rotation of the sliding sleeve 4030 in the direction of arrow AD before the second position 4080 engages the guide pin 4059 and stops further rotation or upstream displacement of the sliding sleeve 4030.
The second position 4080 may be associated with an active or “on” position of the selectable hole trimmer 4000. Specifically, the selectable hole trimmer 4000 may be “locked” in the active or “on” position while the second position 4080 engages the guide pin 4059.
An illustrative configuration of the selectable hole trimmer 4000 where the second position 4080 engages the guide pin 4059 is shown in FIG. 34E. When the sliding sleeve 4030 moves from the trigger position 4079 to the second position 4080, the upstream displacement of the sliding sleeve 4030 may be relatively small compared to the larger downstream displacement of the sliding sleeve 4030 between the first position 4078 and the trigger position 4079. Accordingly, the sliding sleeve spring 4067 and the pressurized volume 4065 (e.g., a hydraulic fluid chamber) may remain in an energize/compressed state. Specifically, the cutter pistons 1402 of the selectable hole cutters 1401 may remain extended even if the flow rate drops below the activation threshold and/or the locking threshold because the guide pin 4059 engaged with the second position 4080 prevents further upstream displacement of the sliding sleeve 4030. Accordingly, the cutter pistons 1402 may remain in the active or “on” position (e.g., the hydraulic fluid may remain compressed, pressurized, etc. by the net downstream displacement of the sliding sleeve 4030) and the selectable hole cutters 1401 may trim material, remove discontinuities, or the like from the borehole until the flow rate of drilling mud is again increased to the activation threshold and/or above the locking threshold.
Turning back to FIG. 34D, increasing the drilling mud flow rate to the activation threshold a second time may displace the sliding sleeve 4030 downstream (e.g., in a direction opposite of arrow AD′) until a third slanted surface 4043 contacts the guide pin 4059. As the sliding sleeve 4030 continues to displace downstream, contact between the third slanted surface 4043 and the guide pin 4059 may also cause axial rotation of the sliding sleeve 4030 in the direction of arrow AD before the next trigger position 4079 engages the guide pin 4059, stopping further displacement of the sliding sleeve 4030. The flow rate may then be lowered below the activation threshold and/or the locking threshold and the sliding sleeve 4030 may displace upstream in the direction of arrow AD′ until a fourth slanted edge 4044 contacts the guide pin 4059. As the sliding sleeve 4030 continues to displace upstream, contact between the fourth slanted surface 4044 and the guide pin 4059 may also cause axial rotation of the sliding sleeve 4030 in the direction of arrow AD before the next first position 4078 engages the guide pin 4059 and stops further upstream displacement of the sliding sleeve 4030, returning the sliding sleeve 4030 to its upstream-most position and deactivating the selectable hole cutters 1401.
Accordingly, the sliding sleeve 4030 may repetitively displace within the tool body 4008 and/or the intermediate sleeve 4020. The first slanted surface 4041 may direct the guide pin 4059 between the first position 4078 and the trigger position 4079. The second slanted surface 4042 may direct the guide pin 4059 between the trigger position 4079 and the second position 4080. The third slanted surface 4043 may direct the guide pin 4059 between the second position 4080 and the next trigger position 4079. The fourth slanted surface 4044 may direct the guide pin 4059 between the (second) trigger position and the (second) first position 4078. Raising and lowering the flow rate above/below the activation threshold and the locking threshold may continue to cause upstream/downstream displacement of the sliding sleeve 4030 and rotation in the direction AR in this pattern (e.g., first position, trigger position, second position, trigger position, first position, trigger position, second position, trigger position, etc.) as the guide pin 4059 cycles through the looped track of the sleeve groove 4058.
While the embodiments in FIGS. 34A-E is illustrated such that the first position 4078 is located at the furthest downstream end of the sleeve groove 4058, the trigger position 4079 is located at a furthest upstream end of the sleeve groove 4058, and the second position 4080 is located at a position along the length of the sleeve groove 4058 upstream of the first position 4078 and downstream of the trigger position 4079, other configurations are possible and are contemplated by this disclosure. For example, in some embodiments, the first position 4078 may be located at the furthest upstream end of the sleeve groove 4058, the trigger position 4079 may be located at the furthest downstream end of the sleeve groove 4058, and the second position 4080 may be located therebetween.
In some embodiments, the sliding sleeve 4030 may include a sliding sleeve insert 4081 at the drilling mud inlet 4035. (See, e.g., FIG. 34C). The sliding sleeve insert 4081 may include a constriction 4082 such as an orifice, a tapered down inner diameter, a protrusion extending into the sliding sleeve chamber 4034, or the like. Similarly, in some embodiments, as shown in FIG. 34A, the intermediate sleeve 4020 may include an intermediate insert 4083 at a drilling mud inlet 4084 of the intermediate sleeve 4020. The sliding sleeve insert 4081 and/or the intermediate insert 4083 may narrow the flow path and cause a corresponding pressure drop in the flow of drilling mud and/or may be configured to create a flow entry angle that reduces wear of the respective sleeve. Additionally, the intermediate insert 4083 may act as a stop block and prevent upstream movement of the sliding sleeve 4030 (e.g., in the event the guide pin 4059 fractures, in the event of wearing of the sleeve groove 4058, etc.).
While embodiments of the activation mechanism 4004 having the sleeve groove 4058 and the guide pin 4059 are shown in FIGS. 32-34E, it should be understood that other embodiments are contemplated by this disclosure. For example, the activation mechanism 4004 and the components thereof may be combined and/or may include components of other activations mechanisms disclosed herein, such as components discussed with respect to FIGS. 1-29C and 30A-E. As a non-limiting example, the tool body 4008 may include a radial housing 350, 450, 550 having the features disclosed in FIGS. 3-5, 14A to assist in the actuation of the sliding sleeve 4030.
As best shown in FIG. 34A, the selectable hole trimmer 4000 may also include one or more sealing grooves 4090. The sealing grooves 4090 may be configured to receive an O-ring or other suitable seal to prevent drilling mud fluid from flowing between the sliding sleeve 4030 and intermediate sleeve 4020, the intermediate sleeve 4020 and the tool body 4008, and/or otherwise circumventing the sliding sleeve chamber 4034 and/or hindering operation of the activation mechanism 4004 (e.g., by entering the sleeve groove 4058).
When the selectable hole trimmer 4000 is sliding or tripping into or out of a borehole, the selectable hole trimmer 4000, namely the one or more selectable hole cutters 1401 are in a deactivated position. The one or more cutter pistons 1402 are in a deactivated position with the one or more cutters 1406 also the deactivated position.
Until the selectable hole trimmer 4000 is signaled to activate, the one or more selectable hole cutters 1401 will remain in the deactivated position. In other words, the one or more cutter pistons 1402 will remain in the deactivated position with the one or more cutters 1406 also in the deactivated position. The selectable hole trimmer 4000 may activated automatically by receiving a volumetric flow rate of drilling mud equal to or above an activation threshold, by pressure or by other means.
This pressurized hydraulic fluid activates the one or more cutter pistons 1402 of the selectable hole cutters 1401, which extends the one or more cutter pistons 1402 and the one or more cutters 1406 outward radially to engage and cut a side surface of the drilled hole 130.
After the selectable hole trimmer 4000 activates, (e.g., after the flow rate of drilling mud fluid exceeds the activation threshold), the selectable hole trimmer 4000 may be configured to remain activated until the selectable hole trimmer 4000 is signaled to deactivate. In other words, once activated, the one or more selectable hole cutters 1401 will remain in the activated position until deactivated. The signal to deactivate may be by increasing the volumetric flow rate of the drilling mud fluid to and/or above the activation threshold a second time. The activation threshold may be 400 gpm, 600 gpm, 660 gpm, or another suitable fluid flow metric.
When the one or more selectable hole cutters 1401 are deactivated, the selectable hole trimmer 4000 may return the one or more cutter pistons 1402 back to the deactivated position via a spring 1410 and return the pressurized hydraulic fluid back to a starting volume (e.g., the pressurized volume 4065 defined between the intermediate sleeve 4020 and the tool body 4008).

Method of Using Sixth Alternative Downhole Device Configured as Selectable Hole Trimmer

FIG. 35 shows a flow diagram of a method 4500 of using the selectable hole trimmer 4000 of FIGS. 32-34E. As shown in FIG. 35 , the method of using the selectable hole trimmer 4000 may include step 4502 of providing a flow of drilling fluids having a flow rate to a selectable hole trimmer 4000; step 4506 of increasing the flow rate above an activation threshold to set the selectable hole trimmer 4000 to an active state and to set a selectable hole cutter 1401 to an extended state; step 4508 of decreasing the flow rate below the activation threshold and below a locking threshold to maintain the selectable hole cutter 1401 in the extended state; step 4510 of increasing the flow rate above the activation threshold to adjust the selectable hole trimmer 4000 towards an inactive state; and step 4512 of decreasing the flow rate below the activation threshold and the locking threshold to set the selectable hole trimmer 4000 to the inactive state and to set the selectable hole cutter 1401 to a retracted state.
FIG. 36 shows a flow diagram including additional steps, one or more of which may be included in the method 4500 of operating the selectable hole trimmer 4000. As shown in FIG. 36 , the method 4500 may also include step 4514 of receiving, by the selectable hole trimmer 4000, a first flow of drilling fluids above an activation threshold; step 4516 of, in response to receiving the first flow above the activation threshold, displacing a sliding sleeve 4030 such that a guide pin 4059 disengages from a first position 4078 and engages a trigger position 4079 of a sleeve groove 4058; step 4518 of receiving, by the selectable hole trimmer 4000, a second flow of drilling fluids below the activation threshold and below a locking threshold; step 4520 of, in response to receiving the second flow below the activation threshold and the locking threshold, displacing the sliding sleeve 4030 such that the guide pin 4059 disengages from the trigger position 4079 and engages a second position 4080 of the sleeve groove 4058; step 4522 of receiving, by the selectable hole trimmer 4000, a third flow of drilling fluids above the activation threshold; step 4524 of in response to receiving the third flow above the activation threshold, displacing the sliding sleeve 4030 such that the guide pin 4059 disengages from the second position 4080 and engages an additional trigger position 4079 of the sleeve groove; step 4526 of receiving, by the selectable hole trimmer 4000, a fourth flow of drilling fluids below the activation threshold and below the locking threshold; and step 4528 of, in response to receiving the fourth flow below the activation threshold and the locking threshold, displacing the sliding sleeve 4030 such that the guide pin 4059 disengages from the additional trigger position 4079 and engages the first position 4078 of the sleeve groove 4058.
The method 4500 may include step 4502 of providing a flow of drilling fluids having a flow rate to a selectable hole trimmer 4000. The flow may have any suitable flow rate (e.g., 1 gpm, 100 gpm, 300 gpm, 500 gpm, 600 gpm, 660 gpm, etc.), multiple flow rates, a variable flow rate, or the like. Step 4502 may include providing the selectable hole trimmer 4000 on a downhole device, for example, approximately 180 ft (two stands) above other bottom hole assembly (BHA) components of the drill string 120. The method 4500 may also include providing a flow of drilling fluids to a drill bit of the downhole device, and/or lowering the selectable hole trimmer 4000 in a borehole. For example, the selectable hole trimmer 4000 may slide or trip into a borehole with the selectable hole cutters 1401 in the retracted position (e.g., in a disengaged/retracted state). Accordingly, the selectable hole trimmer 4000 may slide in and/or out of the borehole with relatively little friction and without the selectable hole cutters 1401 dragging/cutting at the walls of the borehole. The selectable hole trimmer 4000 may receive a flow of drilling fluid (e.g., drilling mud) below the activation threshold and/or at or below the locking threshold. While the flow of drilling mud remains below the activation threshold, the activation mechanism 4004 of the selectable hole trimmer 4000 may remain in an inactive state. That is, the sleeve groove 4058 may engage the guide pin 4059 at the first position 4078 or along the track extending from the first position 4078 (e.g., without causing axial rotation of the sliding sleeve via the first slanted surface 4041 such that lowering the fluid flow rate will cause the sliding sleeve 4030 to displace back to the first position 4078. In other words, the selectable hole cutter 1401 may remain in the “off” and/or neutral position with the selectable hole cutters 1401 at least partially retracted until the flow of drilling mud fluid meets and/or exceeds the activation threshold (e.g., 660 gpm).
The activation mechanism 4004 may be configured to activate and/or deactivate the selectable hole trimmer 4000 based on, for example, a sequence of changes in fluid flow or based on a predefined pattern of drilling fluid flow (e.g., alternating flow above and below the activation threshold and/or the locking threshold).
The method 4500 may include step 4506 of increasing the flow rate to and/or above an activation threshold to set the selectable hole trimmer 4000 to an active state and to set a selectable hole cutter 1401 to an extended state. For example, the selectable hole trimmer 4000 may be lowered into a borehole in the inactive state (e.g., with the selectable hole cutters 1401 retracted, with the first position 4078 engaging the guide pin 4059, etc.). The method 4500 may include receiving, by the selectable hole trimmer 4000, a first flow of drilling fluids at and/or above the activation threshold (e.g., 660 gpm). The method 4500 may also include, in response to receiving the first flow at and/or above the activation threshold, displacing the sliding sleeve 4030 such that the guide pin 4059 disengages from the first position 4078 and engages the trigger position 4079 of the sleeve groove 4058 (e.g., causing rotation of the sliding sleeve 4030 via contact between the guide pin 4059 and the first slanted surface 4041). In this way, the sliding sleeve 4030 may displace downstream and radially rotate, drilling fluids may flow through the bypass nozzles 4015, and the pressurized volume 4065 may cause the selectable hole cutters 1401 to extend such that the selectable hole trimmer 4000 enters the active state (e.g., operating with the cutter pistons 1402 fully extended, locked in the extended state, configured such that the guide pin 4059 is located between the trigger position 4079 and the second position 4080, etc.).
The method 4500 may also include step 4508 of decreasing the flow rate below the activation threshold (e.g., 660 gpm) and below a locking threshold (e.g., 600 gpm) to maintain the selectable hole cutter 1401 in the extended state. For example, the method 4500 may include receiving, by the selectable hole trimmer 4000, a second flow of drilling fluids below the activation threshold and/or at or below the locking threshold such as a drilling flow rate of 300 gpm, 200 gpm, no flow rate (e.g., 0 gpm), a variable flow rate, etc. In response to receiving the second flow below the activation threshold and/or the locking threshold, the method 4500 may include displacing the sliding sleeve 4030 such that the guide pin 4059 disengages from the trigger position 4079 and engages the second position 4080 of the sleeve groove 4058 (e.g., causing rotation of the sliding sleeve 4030 via contact between the guide pin 4059 and the second slanted surface 4042). In other words, the method 4500 may include locking the selectable hole trimmer 4000 in the active state such that the selectable hole cutters 1401 remain extended (e.g., for any fluid flow below the activation threshold and/or the locking threshold).
In some embodiments, the method 4500 may include step 4510 of increasing the flow rate above the activation threshold to adjust the selectable hole trimmer 4000 towards an inactive state. The method 4500 may include receiving, by the selectable hole trimmer 4000, a third flow of drilling fluids at or above the activation threshold. In response to receiving the third flow at or above the activation threshold, the method 4500 may include displacing the sliding sleeve 4030 such that the guide pin 4059 disengages from the second position 4080 and engages an additional trigger position 4079 of the sleeve groove 4058 (e.g., causing rotation of the sliding sleeve 4030 by contact between the guide pin 4059 and the third slanted surface 4043). This step may correspond to adjusting the selectable hole trimmer towards the inactive state. For example, turning to FIG. 34D, this step may include increasing the flow rate such that the guide pin 4059 disengages from the second position 4080 and engages the additional (upper in FIG. 34D) trigger position 4079. This movement is one example of adjusting the selectable hole trimmer 4000 towards the inactive state (e.g., a state where the selectable hole cutters 1401 are retracted). Specifically, while the guide pin 4059 engages the additional trigger position 4079, the selectable hole trimmer 4000 may remain in the active state and the selectable hole cutters 1401 may remain extended while the flow rate of the drilling mud remains high (e.g., at or above the activation threshold). However, when the flow rate falls below the activation threshold, the sliding sleeve 4030 may displace upstream and contact of the guide pin 4059 and the fourth slanted surface 4044, further displacement, etc. may cause the selectable hole trimmer 4000 to enter the inactive state and retract the cutter pistons 1402.
The method 4500 may include step 4512 of decreasing the flow rate below the activation threshold and the locking threshold to set the selectable hole trimmer 4000 to the inactive state and to set the selectable hole cutter 1401 to a retracted state. The method 4500 may include receiving, by the selectable hole trimmer 4000, a fourth flow of drilling fluids below the activation threshold. Further, the method 4500 may include receiving a flow rate of drilling fluids below the locking threshold, receiving no flow of drilling fluids (e.g., a flow rate of 0 gpm) or the like. In response to receiving the fourth flow below the activation threshold, this step may include displacing the sliding sleeve 4030 such that the guide pin 4059 disengages from the additional trigger position 4079 and engages an additional first position 4078 of the sleeve groove 4058. Accordingly, the sliding sleeve 4030 may displace to its upstream-most position, the pressure in the hydraulic fluid chamber may drop, and the cutter pistons 1402 may return to their retracted state such that the selectable hole trimmer 4000 is set to the inactive state. The selectable hole trimmer 4000 may then be operated at flow rates below the activation threshold and the selectable hole cutters 1401 may remain in their retracted state.
With the selectable hole cutters 1401 in the retracted state, the selectable hole trimmer 4000 may be retrieved from the borehole and laid down with relatively little friction and without the selectable hole cutters 1401 dragging/cutting at the walls of the borehole.
In some embodiments, the steps of the method 4500 may be repeated, performed in a different order, or have intermittent and/or intervening steps. In other embodiments, some steps of the method 4500 may be omitted, replaced with varied steps, or the like.

Definitions

In the foregoing description of certain embodiments, specific terminology has been resorted to for the sake of clarity. However, the disclosure is not intended to be limited to the specific terms so selected, and it is to be understood that each specific term includes other technical equivalents, which operate in a similar manner to accomplish a similar technical purpose. Terms (e.g., “outer” and “inner,” “upper” and “lower,” “first” and “second,” “internal” and “external,” “above” and “below,” “upstream” and “downstream”, and the like) are used as words of convenience to provide reference points and, as such, are not to be construed as limiting terms.
The embodiments set forth herein are presented to explain the present invention and its practical application and to thereby enable those skilled in the art to make and utilize the invention. However, those skilled in the art will recognize that the foregoing description has been presented for the purpose of illustration and example only. The description as set forth is not intended to be exhaustive or to limit the invention to the precise form disclosed. Many modifications and variations are possible in light of the above teaching without departing from the spirit and scope of the following claims.
Also, the various embodiments described above may be implemented in conjunction with other embodiments, e.g., aspects of one embodiment may be combined with aspects of another embodiment to realize yet other embodiments. Further, each independent feature or component of any given assembly may constitute an additional embodiment.
As used herein, the terms “a,” “an,” “the,” and “said” mean one or more, unless the context dictates otherwise.
As used herein, the term “about” means the stated value plus or minus a margin of error plus or minus 10% if no method of measurement is indicated.
As used herein, the term “or” means “and/or” unless explicitly indicated to refer to alternatives only or if the alternatives are mutually exclusive.
As used herein, the terms “comprising,” “comprises,” and “comprise” are open-ended transition terms used to transition from a subject recited before the term to one or more elements recited after the term, where the element or elements listed after the transition term are not necessarily the only elements that make up the subject.
As used herein, the terms “containing,” “contains,” and “contain” have the same open-ended meaning as “comprising,” “comprises,” and “comprise,” provided above.
As used herein, the terms “having,” “has,” and “have” have the same open-ended meaning as “comprising,” “comprises,” and “comprise,” provided above.
As used herein, the terms “including,” “includes,” and “include” have the same open-ended meaning as “comprising,” “comprises,” and “comprise,” provided above.
As used herein, the phrase “consisting of” is a closed transition term used to transition from a subject recited before the term to one or more material elements recited after the term, where the material element or elements listed after the transition term are the only material elements that make up the subject.
As used herein, the term “simultaneously” means occurring at the same time or about the same time, including concurrently.
Incorporation by Reference All patents and patent applications, articles, reports, and other documents cited herein are fully incorporated by reference to the extent they are not inconsistent with this invention.

Claims

1. A downhole device configured as a selectable hole trimmer comprising:

a sliding sleeve moveably disposed inside a tool body having an upstream end and a downstream end, the tool body including a drilling fluid volume and wherein the sliding sleeve is disposed within and slidable inside the tool body to provide a pressure to a pressurized volume;

an orifice sleeve moveably disposed inside the sliding sleeve, wherein the orifice sleeve is slidable inside the sliding sleeve to selectively engage and disengage a latch mechanism from a body groove of the tool body;

an actuator connected to the pressurized volume and configured to provide the pressure to a selectable hole cutter of the tool body to actuate the selectable hole cutter between a retracted state and an extended state; wherein:

the orifice sleeve is configured to receive a flow of drilling fluids at a first flow rate above an activation threshold that moves the orifice sleeve from an upstream position to a downstream position to disengage the latch mechanism from the body groove, and

the orifice sleeve is configured to receive the flow of drilling fluids at a second flow rate below the activation threshold that moves the orifice sleeve from the downstream position to the upstream position to engage the latch mechanism with the body groove,

a sleeve groove including a well defining a deepest portion of the sleeve groove;

an inclined portion;

an edge connecting the well and the inclined portion; and wherein:

the well is configured to receive at least a portion of the latch mechanism to disengage the latch mechanism from the body groove

2. The downhole device of claim 1, wherein the activation threshold is a drilling fluid volumetric flow rate of 600 gallons per minute or greater.

3. (canceled)

4. The downhole device of claim 1, wherein the sleeve groove extends around a circumference of an outer wall of the orifice sleeve, the well is located at an upstream end of the sleeve groove, and the inclined portion is located at a downstream end of the sleeve groove.

5. The downhole device of claim 1, further comprising:

a sliding sleeve spring configured to bias the sliding sleeve toward the upstream end of the tool body;

an orifice sleeve spring configured to bias the orifice sleeve toward the upstream end of the tool body; and wherein at least one of:

a spring constant of the orifice sleeve spring is greater than a spring constant of the sliding sleeve spring; or

the spring constant of the orifice sleeve spring is less than the spring constant of the sliding sleeve spring.

6. The downhole device of claim 1, wherein:

the latch mechanism prevents a downstream movement of the sliding sleeve while engaged with the body groove;

the latch mechanism includes a rectangular locking dog having a slanted engagement surface; and

a volume is defined between the sliding sleeve and the tool body such that the downstream movement of the sliding sleeve compresses the volume to engage the actuator.

7. The downhole device of claim 1, wherein the latch mechanism comprises:

a recess formed in an outer wall of the sliding sleeve;

a through-hole defined through the outer wall of the sliding sleeve;

a latch key disposed within the recess and moveable between a first position and a second position;

a latch spring disposed in the recess configured to urge the latch key towards the first position;

a cap configured to retain at least a portion of the latch key or the latch spring inside the recess; wherein:

the latch key is configured to engage with the body groove in the first position, and

the latch key is configured to disengage from the body groove in the second position.

8. A downhole device configured as a selectable hole trimmer comprising:

an actuator connected to the pressurized volume and configured to provide the pressure to a selectable hole cutter of the tool body to actuate the selectable hole cutter between a retracted state and an extended state;

a sleeve groove formed within the tool body, the sleeve groove having a first position at a downstream end of the sleeve groove, a trigger position at an upstream end of the sleeve groove, and a second position disposed between the first position and the trigger position;

a guide pin extending into the sleeve groove and configured to selectively engage at least the first position, the trigger position, or the second position; wherein:

a first flow, above an activation threshold, flowing through the selectable hole trimmer is configured to disengage the guide pin from the first position and engage the guide pin with the trigger position, thereby moving the selectable hole cutter to the extended state,

a second flow, below the activation threshold and below a locking threshold that is smaller than the activation threshold, flowing through the selectable hole trimmer is configured to disengage the guide pin from the trigger position and engage the guide pin with the second position, while maintaining the selectable hole cutter in the extended state,

a third flow, above the activation threshold, flowing through the selectable hole trimmer is configured to disengage the guide pin from the second position and engage the guide pin with an additional trigger position, and

a fourth flow, below the activation threshold and below the locking threshold, flowing through the selectable hole trimmer is configured to disengage the guide pin from the additional trigger position and engage the guide pin with an additional first position, thereby moving the selectable hole cutter to the retracted state.

9. The downhole device of claim 8, wherein the actuator comprises at least one of a piston portion of the sliding sleeve or an annular ring disposed between the sliding sleeve and the tool body.

10. The downhole device of claim 8, wherein the sleeve groove further comprises:

a first slanted surface configured to direct the guide pin between the first position and the trigger position;

a second slanted surface configured to direct the guide pin between the trigger position and the second position;

a third slanted surface configured to direct the guide pin between the second position and the additional trigger position; and

a fourth slanted surface configured to direct the guide pin between the additional trigger position and the additional first position.

11. The downhole device of claim 8, wherein:

the activation threshold is 660 gallons per minute or greater; and

the locking threshold is 600 gallons per minute or greater.

12. The downhole device of claim 8, further comprising:

an intermediate sleeve disposed inside the tool body, the intermediate sleeve located between the tool body and the sliding sleeve; and wherein:

the pressurized volume is defined between the intermediate sleeve and the tool body.

13. The downhole device of claim 12, wherein:

the sleeve groove is formed on an outer wall of the sliding sleeve and the guide pin is coupled to an inner wall of the intermediate sleeve; or

the sleeve groove is formed on the inner wall of the intermediate sleeve and the guide pin is coupled to the outer wall of the sliding sleeve.

14. The downhole device of claim 12, wherein a sliding sleeve spring is disposed within the intermediate sleeve and downstream of the sliding sleeve, the sliding sleeve spring configured to bias the sliding sleeve toward the upstream end of the tool body.

15. A method of using a downhole device configured as a selectable hole trimmer comprising:

providing a drill bit a flow of drilling fluids;

lowering the selectable hole trimmer in a borehole;

receiving, by the selectable hole trimmer, the flow of drilling fluids at a flow rate above an activation threshold;

in response to receiving the flow above the activation threshold, disengaging a latch mechanism from a body groove of a tool body of the selectable hole trimmer via a movement of an orifice sleeve, wherein disengaging the latch mechanism, causing a first movement of a sliding sleeve within the selectable hole trimmer to compress a volume, wherein the compressed volume forces hydraulic fluid to move a selectable hole cutter from a retracted state to an extended state;

receiving, by the selectable hole trimmer, the flow of drilling fluids below a deactivation threshold;

in response to receiving the flow below the deactivation threshold, engaging the body groove with the latch mechanism via a second movement of the sliding sleeve; and

in response to the second movement of the sliding sleeve, moving the selectable hole cutter from the extended state to the retracted state.

16. The method of claim 15, wherein the activation threshold is 600 gallons per minute or greater.

17. (canceled)

18. The method of claim 15, wherein the deactivation threshold is 300 gallons per minute or less.

19. The method of claim 15, wherein the first movement of the sliding sleeve within the selectable hole trimmer to compress the volume includes displacing the sliding sleeve such that a guide pin disengages from a first position of a sleeve groove within the selectable hole trimmer and engages a trigger position of the sleeve groove, and further comprising:

decreasing the flow rate below the activation threshold and below a locking threshold to displace the sliding sleeve such that the guide pin disengages from the trigger position and engages a second position of the sleeve groove, wherein the activation threshold is greater than the locking threshold;

maintaining the selectable hole cutter in the extended state while the guide pin engages the second position;

increasing the flow rate above the activation threshold such that the guide pin disengages from the second position and engages an additional trigger position;

decreasing the flow rate below the activation threshold and the locking threshold to displace the sliding sleeve such that the guide pin disengages from the additional trigger position and engages an additional first position of the sleeve groove; and

moving the selectable hole cutter from the extended state to the retracted state as the guide pin engages the additional first position.

20. The method of claim 19, wherein:

the activation threshold is 660 gallons per minute or greater; and

the locking threshold is 600 gallons per minute or greater.