Patent Publication Number: US-2023145195-A1

Title: Selectable hole trimmer and methods thereof

Description:
PRIOR RELATED APPLICATIONS 
     This application is divisional of U.S. patent application Ser. No. 11/365,128 entitled “SELECTABLE HOLE TRIMMER AND METHODS THEREOF,” filed on Jul. 1, 2021, which is a continuation-in-part of U.S. Nonprovisional patent application Ser. No. 17/089,616 entitled “DEVICE AND METHOD TO TRIGGER, SHIFT, AND/OR OPERATE A DOWNHOLE DEVICE OFA DRILLING STRING INA WELLBORE,” filed on Nov. 4, 2020, which claims the benefit of U.S. Provisional Patent Application No. 63/008,364 entitled “DEVICE AND METHOD TO TRIGGER, SHIFT, AND/OR OPERATE A DOWNHOLE DEVICE OF A DRILLING STRING IN A WELLBORE,” filed on Apr. 10, 2020, and U.S. Provisional Patent Application Ser. No. 62/931,629 entitled “DEVICE AND METHOD TO TRIGGER, SHIFT, AND/OR OPERATE A DOWNHOLE DEVICE OF A DRILLING STRING IN A WELLBORE,” filed on Nov. 6, 2019. 
     This application a divisional of U.S. patent application Ser. No. 11/365,128 entitled “SELECTABLE HOLE TRIMMER AND METHODS THEREOF,” filed on Jul. 1, 2021, which also claims benefit of U.S. Provisional Patent Application Ser. No. 63/047,451 entitled “SELECTABLE HOLE TRIMMER AND METHODS THEREOF,” filed on Jul. 2, 2020. 
     All of said priority applications are incorporated by reference in their entirety. 
    
    
     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. 
     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 causes 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 rotation speeds of the drill string or other conditions such as the pressure of the drilling fluids. For example, the drill string may be rotated in some protocol of operation (e.g., rotate at certain rpm for a certain time period, and/or stop at certain other rpm for a certain time period or stop rotating for a predetermined time period, and so forth) to describe a recognizable series of signals to an accelerometer and/or microprocessor that will 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. 
     The disclosed device employs sensors and controllers to make use of the rpm protocol to produce signals that may also be used to extend/retract certain pistons in the downhole device wall to cut a small amount of wall material. For example, after a certain protocol to wake up the downhole device that whenever certain rpm is recognized, reamer pistons may extend a short amount in response to the recognized condition. Continuing to rotate the downhole device will cause the hole to open a small amount more than the bit is cutting so that ultimately when the bottom hole assembly (BHA) is tripped out of the hole and the casing is later tripped into the hole, the components may pass more easily with less interference. Additionally, during directional drilling, particularly rotate and slide procedures, the hole may tend to have a wavy profile as it is drilled, called porpoising. The hole literally may move feet up and down in a wave shape. This also will be reduced or eliminated by utilizing this tool invention. 
     Such hole opening processes utilizing the monitored rpm and controller signals may be automatic and thus unnoticed by the driller. As a result of the reamer piston&#39;s operation, the reamer may smooth out the tight spots caused by the bent motor or other drilling equipment in directional drilling. The rpm or other signal from the driller to the disclosed device may also open an expandable reamer. For example, the disclosed tool may shift a sleeve connected by linkages to reamer blocks, causing the blocks to slide axially up and radially out at a prescribed small angle, thus opening a reamer. Polycrystalline diamond compacts (PDC) and/or other cutting elements of extreme hardness, wear resistance and thermal conductivity will ream and radially enlarge the hole, for example, more or less by 20%. 
     In a first general aspect, the disclosed downhole device for having bypassing drill fluids bypass a drill bit is disclosed. The device includes a sleeve, sealingly slidable inside a body, the sleeve having a port alignable with a nozzle of the body. The device further includes means for resiliently biasing the sleeve against the body and an actuator configured to provide a pressure to the sleeve and actuate the sleeve to move relative to the body. The device also includes a controller configured to operate the actuator in response to a change of a monitored operation condition. 
     In one specific aspect, the resilient member includes a spring providing a biasing force corresponding to a threshold trigger pressure. 
     In another specific aspect, the sleeve may be configured to direct drill fluids to a downhole drill bit when the port is not aligned with the nozzle of the body and is configured to direct a portion of the drill fluids to the downhole drill bit when the port becomes at least partially aligned with the nozzle of the body such that another portion of the drill fluids bypasses the drill bit. 
     In yet another specific aspect, the downhole device further includes a lock ring setting a movement limit to the sleeve. The lock ring may also provide a point of support for the resilient member. 
     In one specific aspect, the body may include an internal tube housing the sleeve and at least one radial compartment housing at least one of an oil accumulator, a motor pump, a battery, the actuator, or the controller. 
     In another specific aspect, the actuator includes a three-way control valve. 
     In yet another specific aspect, the actuator may include an accumulator or a pressure compensator. 
     In one specific aspect, the controller may be configured to operate the actuator in response to an internal drill string pressure variation measured in a pressure transducer, in some embodiments, the internal drill string pressure variation satisfies a trigger condition. 
     In a second general aspect, a method for bypassing drilling fluids from a downhole drill bit is disclosed. The method includes: providing a drill bit a flow of drilling fluids; determining whether a trigger condition has been satisfied; upon determining the trigger condition has been satisfied, actuating a sleeve to move relative to a body, sealingly housing the sleeve, and at least partially aligning a port in the sleeve to a nozzle of the body; and directing a portion of the flow of drilling fluids through the port and the nozzle to bypass the drill bit. 
     In one specific aspect, determining the satisfaction of the trigger condition may include measuring a value related to a rotation speed of the downhole drill bit or a pressure of the drilling fluids and comparing the measured value to a reference value. 
     In another specific aspect, determining the satisfaction of the trigger condition may include receiving a control signal from a controller, in some embodiments, the control signal is 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 yet another specific aspect, determining the satisfaction of the trigger condition 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 one specific aspect, 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 another specific aspect, 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 yet another specific aspect, biasing the sleeve against the body to close the port from the nozzle may include offsetting the port from the nozzle using a spring. 
     In one specific aspect, actuating the sleeve to move relative to the body may include sliding the sleeve inside the body, or rotating the sleeve inside the body, or both. 
     In an embodiment, a device for bypassing drill fluids around a drill bit comprises a sleeve sealingly slidable inside a body, the sleeve having a port alignable with a nozzle of the body and an activation port alignable with a selectable hole cutter of the body, a resilient member biasing the sleeve against the body, an actuator configured to provide a pressure to the sleeve and actuate the sleeve to move relative to the body, and a controller configured to operate the actuator in response to a change of a monitored operation condition. 
     In an embodiment, the resilient member comprises a spring providing a biasing force corresponding to a threshold trigger pressure. 
     In an embodiment, the sleeve is configured to direct drill fluids to the drill bit when the port is not aligned with the nozzle of the body and is configured to direct a portion of the drill fluids to the drill bit when the port becomes at least partially aligned with the nozzle of the body such that another portion of the drill fluids bypasses the drill bit. In an embodiment, the sleeve is configured to direct drill fluids to the drill bit when the port is not aligned with the nozzle of the body and the activation port is not aligned with the selectable hole cutter of the body, and wherein the sleeve is configured to direct a portion of the drill fluids to the drill bit when the port becomes at least partially aligned with the nozzle of the body and the activation port is at least partially aligned with the selectable hole cutter such that another portion of the drill fluids bypasses the drill bit and activates the selectable hole cutter. 
     In an embodiment, the device further comprises a lock ring setting a movement limit to the sleeve. 
     In an embodiment, the body comprises an internal tube housing the sleeve and at least one radial compartment housing at least one of an oil accumulator, a motor pump, a battery, the actuator, or the controller. 
     In an embodiment, the actuator includes a three-way control valve. In an embodiment, the actuator includes an accumulator, a pressure compensator, or both. 
     In an embodiment, the controller is configured to operate the actuator in response to an internal drill string pressure variation measured in a pressure transducer, wherein the internal drill string pressure variation satisfies a trigger condition. 
     In an embodiment, the body comprises helical carved structures distributed radially on an external surface of the body. In an embodiment, the helical carved structures are oriented in an axial direction of the body and are configured to facilitate flow of the drill fluids bypassed the drill bit. 
     In an embodiment, a method for controlling drilling fluids in a drill string to bypass a drill bit comprises providing the drill bit a flow of drilling fluids in the drill string, wherein the flow of drilling fluids returns in an annulus, determining whether a trigger condition has been satisfied, upon determining the trigger condition has been satisfied, actuating a sleeve to move relative to a body sealingly housing the sleeve, and at least partially aligning a port in the sleeve to a nozzle of the body and an activation port in the sleeve to a selectable hole cutter of the body, 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 the selectable hole cutter. 
     In an embodiment, the determining the trigger condition being satisfied comprises measuring a value related to a rotation speed of the downhole drill bit or a pressure of the drilling fluids and comparing the measured value to a reference value. In an embodiment, the determining the satisfaction of the trigger condition comprises receiving a control signal from a controller, wherein the control signal is provided in response to a rotation protocol. In an embodiment, the determining the trigger condition being satisfied comprises 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 wherein actuating the sleeve to move relative to the body 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 an embodiment, the 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 comprises 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 an embodiment, the method further comprises 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 an embodiment, the biasing the sleeve against the body to close the port from the nozzle and the activating port from the selectable hole cutter comprises offsetting the port from the nozzle and the activation port from the selectable hole cutter using a spring. 
     In an embodiment, the actuating the sleeve to move relative to the body comprises sliding the sleeve inside the body or rotating the sleeve inside the body or both. 
     In an embodiment, the method further comprises regulating the portion of the flow of drilling fluids bypassed the drill bit using helical carved structures to facilitate fluid flow in the annulus. 
     In an embodiment, the directing a portion of the flow of drilling fluids through the port and the nozzle to bypass the drill bit comprises actuating the sleeve to move relative to the body to align an opening in the sleeve to an outlet of the body, wherein actuating the sleeve includes providing a high pressure oil flow, using a motor driven pump, to move the sleeve. In an embodiment, the directing a portion of the flow of drilling fluids through the activation port to the selectable hole cutter to activate the selectable hole cutter comprises actuating the sleeve to move relative to a body to align an opening in the sleeve to an outlet of the body, wherein actuating the sleeve includes providing a high pressure oil flow, using a motor driven pump, to move the sleeve, and actuating the sleeve to move relative to the body to align the activation port to the selectable hole cutter. 
     In an embodiment, a device for bypassing drill fluids around a drill bit comprises a sleeve sealingly slidable inside a body, the sleeve having a port alignable with a nozzle and an activation port alignable with a selectable hole cutter of the body, a resilient member biasing the sleeve against the body, wherein the resilient member comprises a spring providing a biasing force corresponding to a threshold trigger pressure, an actuator configured to provide a pressure to the sleeve and actuate the sleeve to move relative to the body, and a controller configured to operate the actuator in response to a change of a monitored operation condition. 
     In an embodiment, the sleeve is configured to direct drill fluids to the drill bit when the port is not aligned with the nozzle of the body and is configured to direct a portion of the drill fluids to the drill bit when the port becomes at least partially aligned with the nozzle of the body such that another portion of the drill fluids bypasses the drill bit. 
     In an embodiment, the sleeve is configured to direct drill fluids to the drill bit when the port is not aligned with the nozzle of the body and the activation port is not aligned with the selectable hole cutter of the body, and wherein the sleeve is configured to direct a portion of the drill fluids to the drill bit when the port becomes at least partially aligned with the nozzle of the body and the activation port is at least partially aligned with the selectable hole cutter such that another portion of the drill fluids bypasses the drill bit and activates the selectable hole cutter. 
     In an embodiment, the device further comprises a lock ring setting a movement limit to the sleeve. 
     In an embodiment, the body comprises an internal tube housing the sleeve and at least one radial compartment housing at least one of an oil accumulator, a motor pump, a battery, the actuator, or the controller. 
     In an embodiment, the actuator includes a three-way control valve. In an embodiment, the actuator includes an accumulator, a pressure compensator, or both. 
     In an embodiment, the controller is configured to operate the actuator in response to an internal drill string pressure variation measured in a pressure transducer, wherein the internal drill string pressure variation satisfies a trigger condition. 
     In an embodiment, the body comprises helical carved structures distributed radially on an external surface of the body. In an embodiment, the helical carved structures are oriented in an axial direction of the body and are configured to facilitate flow of the drill fluids bypassed the drill bit. 
     In an embodiment, a method for controlling drilling fluids in a drill string to bypass a drill bit comprises providing the drill bit a flow of drilling fluids in the drill string, wherein the flow of drilling fluids returns in an annulus, wherein a resilient member comprises a spring providing a biasing force corresponding to a threshold trigger pressure, determining whether a trigger condition has been satisfied, upon determining the trigger condition has been satisfied, actuating a sleeve to move relative to a body sealingly housing the sleeve, and at least partially aligning a port in the sleeve to a nozzle and an activation port with a selectable hole cutter of the body, and directing a portion of the flow of drilling fluids through the port and the nozzle to bypass the drill bit and through the activation port to the selectable hole cutter to activate the selectable hole cutter. 
     In an embodiment, the determining the trigger condition being satisfied comprises measuring a value related to a rotation speed of the downhole drill bit or a pressure of the drilling fluids and comparing the measured value to a reference value. In an embodiment, the determining the satisfaction of the trigger condition comprises receiving a control signal from a controller, wherein the control signal is provided in response to a rotation protocol. In an embodiment, the determining the trigger condition being satisfied comprises 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 wherein actuating the sleeve to move relative to the body 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 an embodiment, the 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 comprises 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 an embodiment, the method further comprises 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 an embodiment, the biasing the sleeve against the body to close the port from the nozzle and the activation port from the selectable hole cutter comprises offsetting the port from the nozzle and the activation port from selectable hole cutter using a coil spring. 
     In an embodiment, the actuating the sleeve to move relative to the body comprises sliding the sleeve inside the body or rotating the sleeve inside the body or both. 
     In an embodiment, the method further comprises regulating the portion of the flow of drilling fluids bypassed the drill bit using helical carved structures to facilitate fluid flow in the annulus. 
     In an embodiment, the directing a portion of the flow of drilling fluids through the port and the nozzle to bypass the drill bit comprises actuating the sleeve to move relative to a body to align an opening in the sleeve to an outlet of the body, wherein actuating the sleeve includes providing a high pressure oil flow, using a motor driven pump, to move the sleeve. In an embodiment, the directing a portion of the flow of drilling fluids through the activation port to the selectable hole cutter to activate the selectable hole cutter comprises actuating the sleeve to move relative to a body to align an opening in the sleeve to an outlet of the body, wherein actuating the sleeve includes providing a high pressure oil flow, using a motor driven pump, to move the sleeve, and actuating the sleeve to move relative to the body to align the activation port to the selectable hole cutter. 
     In an embodiment, a method of making a device for bypassing fluids around a drill bit comprises providing a lower sleeve, an upper sleeve and a resilient member, assembling the lower sleeve, the upper sleeve and the resilient member to form a sleeve, assembling a body and the sleeve to form the device for bypassing drill fluids around the drill bit, wherein the sleeve is sealingly slidable inside the body and wherein the sleeve has a port alignable with a nozzle of the body and an activation port alignable with a selectable hole cutter of the body. 
     In an embodiment, the resilient member comprises a spring providing a biasing force corresponding to a threshold trigger pressure. 
     In an embodiment, a device for a selectable hole trimmer is disclosed. The device comprises an intermediate sleeve sealingly affixed inside a body via a stop block, a sleeve sealingly slidable inside the intermediate sleeve to form a pressurized volume there between, an actuator fluidly connected to the pressurized volume via a port, wherein the actuator is configured to provide a pressure to a selectable hole cutter of the body via an activation port and actuate a cutter piston of the selectable hole cutter to move relative to the body, and a controller configured to operate the actuator in response to a change of a monitored operation condition. 
     In an embodiment, the cutter piston comprises one or more cutters. In an embodiment, the cutter piston comprises a cutter blade, wherein the cutter blade comprises the one or more cutters. 
     In an embodiment, the selectable hole cutter comprises one or more cutter pistons, wherein the one or more cutter pistons comprise a cutter blade and wherein the cutter blade comprises the one or more cutters. 
     In an embodiment, the sliding sleeve is disposed between a return spring and a compensating spring. In an embodiment, the sliding sleeve is biased against a return spring at a first end and against a compensating spring at a second end. 
     In an embodiment, the body comprises at least one radial compartment housing at least one of a pump, a battery, the actuator, or the controller. 
     In an embodiment, the actuator includes a two-way control valve. In an embodiment, the actuator includes an oil accumulator, a pressure compensator, or both. 
     In an embodiment, the controller is configured to operate the actuator in response to an internal drill string pressure variation measured in a pressure transducer, wherein the internal drill string pressure variation satisfies a trigger condition. 
     In an embodiment, another device for selectable hole trimmer is disclosed. The device comprises an intermediate sleeve sealingly affixed inside a body via a stop block, a sleeve sealingly slidable inside the intermediate sleeve to form a pressurized volume, an actuator fluidly connected to the pressurized volume via a port, wherein the actuator is configured to provide a pressure to a selectable hole cutter of the body via an activation port and actuate a cutter piston of the selectable hole cutter to move relative to the body, and a controller configured to operate the actuator in response to a change of a monitored operation condition. 
     In an embodiment, the cutter piston comprises one or more cutters. In an embodiment, the cutter piston comprises a cutter blade, wherein the cutter blade comprises the one or more cutters. 
     In an embodiment, the selectable hole cutter comprises one or more cutter pistons, wherein the one or more cutter pistons comprise a cutter blade and wherein the cutter blade comprises the one or more cutters. 
     In an embodiment, the body comprises at least one radial compartment housing at least one of a pump, a battery, the actuator, or the controller. 
     In an embodiment, the actuator includes a two-way control valve. In an embodiment, the actuator includes an oil accumulator, a pressure compensator, or both. 
     In an embodiment, the controller is configured to operate the actuator in response to an internal drill string pressure variation measured in a pressure transducer, wherein the internal drill string pressure variation satisfies a trigger condition. 
     In an embodiment, a method of using a downhole device as a selectable hole trimmer comprises: providing a drill bit a flow of drilling fluids in the drill string, wherein the flow of drilling fluids returns in an annulus; determining whether a trigger condition has been satisfied; upon determining the trigger condition has been satisfied, opening a valve in a control system to pressurize a volume; at least partially pressurizing an activation port to a selectable hole cutter of a body; and directing a portion of the flow of drilling fluids through the activation port to the selectable hole cutter to activate the cutter piston. 
     In an embodiment, determining the trigger condition being satisfied comprises measuring a value related to a rotation speed of the downhole drill bit or a pressure of the drilling fluids and comparing the measured value to a reference value. In an embodiment, determining the satisfaction of the trigger condition comprises receiving a control signal from a controller, wherein the control signal is provided in response to a rotation protocol. In an embodiment, determining the trigger condition being satisfied comprises 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 an embodiment, 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 comprises 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 an embodiment, the method further comprises operating a pump in the control system to return the drilling fluids to the volume and to deactivate the cutter piston upon determining the trigger condition has not been satisfied; and closing the valve in the control system. 
     In an embodiment, the method further comprises, in an event of a power failure, a hydraulic fluid leak or a temperature spike, opening a fail-safe valve to vent drilling fluids out of the downhole device and to deactivate the cutter piston. 
     In an embodiment, a downhole device configured as a selectable hole trimmer comprises a dual solenoid compensation sleeve sealingly affixed inside a body, an annular compensating ring slidingly sealable outside the dual solenoid compensation sleeve, a volume/waste ring slidingly sealable outside the dual solenoid compensation sleeve to form a pressurized volume, an actuator fluidly connected to the pressurized volume via a port, wherein the actuator is configured to provide a pressure to a selectable hole cutter of the body via an activation port and actuate a cutter piston of the selectable hole cutter to move relative to the body, wherein the cutter piston comprises one or more cutters, and a controller configured to operate the actuator in response to a change of a monitored operation condition. 
     In an embodiment, the cutter piston comprises a cutter blade, wherein the cutter blade comprises the one or more cutters. 
     In an embodiment, the selectable hole cutter comprises one or more cutter pistons, wherein the one or more cutter pistons comprise a cutter blade and wherein the cutter blade comprises the one or more cutters. 
     In an embodiment, the volume/waste ring is biased against a hydraulic fluid return spring at a second end. 
     In an embodiment, the body comprises at least one radial compartment housing at least one of a battery, the actuator, or the controller. 
     In an embodiment, the actuator includes a dual solenoid valve, wherein a first end of the dual solenoid is fluidly connected to the activation port and a second end of the dual solenoid valve is fluidly connected to a waste port into a waste volume. 
     In an embodiment, the controller is configured to operate the actuator in response to an internal drill string pressure variation measured in a pressure transducer, wherein the internal drill string pressure variation satisfies a trigger condition. 
     In an embodiment, the dual solenoid compensating sleeve is held in place with a snap ring at an upper end and a hydraulic fluid return spring at a lower end. 
     In an embodiment, the volume/waste ring comprises a one-way valve between a waste volume and the pressurized volume. 
     In an embodiment, a method of using a downhole device configured as a selectable hole trimmer comprises: providing a drill bit a flow of drilling fluids, 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, 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. 
     In an embodiment, the method further comprises: stopping the flow of drilling fluids through the selectable hole trimmer to deactivate the selectable hole cutter. 
     In an embodiment, the method further comprises: stopping the flow of drilling fluids through the selectable hole trimmer, 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. 
     In an embodiment, the method further comprises: 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. 
     In an embodiment, a downhole device configured as a selective hole trimmer comprises: an intermediate sleeve affixed to a body via a stop lock, a slidable sleeve inside the intermediate sleeve to provide a pressurized volume, wherein the slidable sleeve comprises a seat, an actuator fluidly connected to the pressurized volume via a port, wherein the actuator is configured to provide a pressure to a selectable hole cutter of the body via an actuation port in the transfer sleeve and actuate the selectable hole cutter piston of the selectable hole cutter to move relative to the body, wherein the cutter piston comprises one or more cutters, and a manual controller configured to operate the actuator in response to a dropped activation dart. 
     In an embodiment, the cutter piston comprises a cutter blade, wherein the cutter blade comprises the one or more cutters. 
     In an embodiment, the selectable hole cutter comprises one or more cutter pistons, wherein the one or more cutter pistons comprise a cutter blade and wherein the cutter blade comprises the one or more cutters. 
     In an embodiment, an upper port in the sliding sleeve is capable of being aligned with a lower port the intermediate sleeve to pressurize a top of a divider seal ring with drilling mud to provide the pressurized volume. 
     In an embodiment, the sliding sleeve is capable of moving downward and pressing on a top of a divider seal ring to provide the pressurized volume. 
     In an embodiment, the seat is made from a polymer or a rubber. In an embodiment, the seat is made from polyurethane. 
     In an embodiment, the activation dart comprises a port. In an embodiment, the activation dart is made of a metal, a polymer or a rubber. In an embodiment, the activation dart is made of a metal. 
     In an embodiment, the manual controller configured to operate the actuation in response to a dropped deactivation ball. In an embodiment, the deactivation ball is made from a metal, a polymer or a rubber. In an embodiment, the deactivation ball is made from a metal. 
     In an embodiment, the body comprises a check valve to bypass an upper seal when the divider seal ring is forced upwards. 
     In an embodiment, the downhole device further comprises a catcher basket affixed to the body to catch the activation dart and deactivation ball. 
     In an embodiment, the downhole device further comprises an automatic controller to provide the pressurized volume. 
     In an embodiment, a method of using a downhole device configured as a selectable hole trimer comprises: providing a drill bit a flow of drilling fluids, lowering the selectable hole trimmer in a borehole, 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. 
     In an embodiment, the method further comprises: stopping the flow of the drilling fluids through the selectable hole trimmer to deactivate the selectable hole cutter. 
     In an embodiment, the method further comprises: dropping a deactivation ball to stop the flow of the drilling fluids through the selectable hole trimmer and to deactivate the selectable hole cutter. 
     In an embodiment, the method further comprises: dropping a deactivation ball, and forcing the drop dart and the deactivation ball through the seat to stop the flow of the drilling fluids through the selectable hole trimmer and to deactivate the selectable hole cutter. 
     In an embodiment, the method further comprises: providing a drill bit a flow of drilling fluids, and dropping a second 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. 
     In an embodiment, a downhole device configured as a selectable hole trimmer comprises: an upper sleeve affixed inside a body via a stop, wherein the body comprises a drilling mud volume, a charge sleeve comprising a bypass port, wherein the charge sleeve is slidable inside the upper sleeve to provide a pressure to a pressurized volume, a catch sleeve comprising a return port, wherein the catch sleeve is slidable inside the charge sleeve to align the bypass port and the return port with the drilling mud volume, an actuator fluidly connected to the pressurized volume via a port, wherein the actuator is configured to provide a pressure to a selectable hole cutter of the body via an actuation port in the transfer sleeve and actuate the selectable hole cutter piston of the selectable hole cutter to move relative to the body, wherein the cutter piston comprises one or more cutters, and a manual controller configured to operate the actuator in response to a dropped activation ball. 
     In an embodiment, the cutter piston comprises a cutter blade, wherein the cutter blade comprises the one or more cutters. 
     In an embodiment, the selectable hole cutter comprises one or more cutter pistons, wherein the one or more cutter pistons comprise a cutter blade and wherein the cutter blade comprises the one or more cutters. 
     In an embodiment, the downhole device further comprising: a charge subassembly, wherein the charge subassembly comprises the upper sleeve, the charge sleeve, and the catch sleeve, and a trimmer subassembly, wherein the transfer subassembly comprises a transfer sleeve and the selectable hole cutter. 
     In an embodiment, the upper sleeve acts as an upper stop for the charge sleeve. 
     In an embodiment, the upper sleeve is held in place with a stop at a lower end and a snap ring at an upper end. 
     In an embodiment, an internal stop in the charge sleeve acts as a lower stop for the catch sleeve. 
     In an embodiment, the catch sleeve is capable of moving to a lower position to provide the pressure through the activation ports. 
     In an embodiment, the downhole device further comprises a detent ring disposed between the charge sleeve and the catch sleeve. In an embodiment, the detent ring is made of a metal, a polymer or a rubber. In an embodiment, the detent ring is made of a rubber. In an embodiment, the detent ring is made of a metal. In an embodiment, the detent ring holds the charge sleeve in a relative position to the catch sleeve. 
     In an embodiment, the activation ball is made of a metal, a polymer or a rubber. In an embodiment, the activation ball is made of a metal. 
     In an embodiment, a method of using a downhole device configured as a selectable hole trimer comprises: providing a drill bit a flow of drilling fluids, lowering a selectable hole trimmer in a borehole, dropping an activation ball to seal a seat in a catch sleeve, disengage a detent ring between the charge sleeve and a catch sleeve and allow the catch sleeve to move downward to a lower position within the charge sleeve, 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. 
     In an embodiment, the method further comprises: stopping the flow of the drilling fluids through the selectable hole trimmer to deactivate the selectable hole cutter and to move the charge sleeve and the catch sleeve upward. 
     In an embodiment, the method further comprises: stopping the flow of the drilling fluids through the selectable hole trimmer, raising the selectable hole trimer in the borehole, 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. 
     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.  7 A  shows an exemplary schematic for controlling the downhole device; 
         FIG.  7 B  shows an exemplary schematic of a controller applicable to the downhole device; 
         FIG.  8 A  shows a side view of an exemplary embodiment of the downhole device having carved structures for regulating the annular fluid flow; 
         FIG.  8 B  shows a cross-sectional side view of the exemplary embodiment of the downhole device shown in  FIG.  8 A ; 
         FIG.  8 C  shows a cross-sectional top view of the exemplary embodiment of the downhole device shown in  FIG.  8 A ; 
         FIG.  9    shows a flow diagram of a method for bypassing drilling fluids from a downhole drill bit; 
         FIG.  10 A  shows a side view of an exemplary embodiment of an alternative downhole device having carved structures for regulating annular fluid flow; 
         FIG.  10 B  shows a cross-sectional side view of the exemplary embodiment of the downhole device shown in  FIG.  10 A ; 
         FIG.  10 C  shows a detailed view cross-sectional top view of the exemplary embodiment of the downhole device shown in  FIG.  10 B ; 
         FIG.  11 A  shows a top view of a lower sleeve and an upper sleeve of an alternative exemplary embodiment of the downhole device shown in  FIGS.  10 A- 10 C  prior to a first step of assembly; 
         FIG.  11 B  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.  11 A  after the first step of assembly; 
         FIG.  11 C- 1    shows a side view of a stop block of the exemplary embodiment of the downhole device shown in  FIGS.  11 A- 11 B  prior to a second step of assembly; 
         FIG.  11 C- 2    shows a side view of the assembled sleeve of the exemplary embodiment of the downhole device shown in  FIG.  11 B  prior to a second step of assembly; 
         FIG.  11 D  shows a side view of a body of the exemplary embodiment of the downhole device prior to a second step of assembly; 
         FIG.  11 E  shows a cross-sectional view of the body and the sleeve of the exemplary embodiment of the downhole device of  FIGS.  11 A- 11 D  after the second step of assembly; 
         FIG.  11 F  shows a cross-sectional view of the body and the sleeve of the exemplary embodiment of the downhole device shown in  FIG.  11 E  prior to a third step of assembly; 
         FIG.  11 G  shows a cross-sectional view of the exemplary embodiment of the downhole device of  FIGS.  11 A- 11 F  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.  14 A  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.  14 B  shows a detailed view of the selectable hole trimmer of  FIG.  14 A ; 
         FIG.  14 C  shows a Section A cross-sectional view of the selectable hole trimmer of  FIG.  14 A ; 
         FIG.  15 A  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.  15 B  shows a Section A-A cross-sectional view of the selectable hole trimmer of  FIG.  15 A , showing a deactivated cutter piston, a nozzle, a body, an intermediate sleeve, a sliding sleeve, a pressure equalization slot, and a return spring; 
         FIG.  15 C  shows a detailed B view of the selectable hole trimmer of  FIG.  15 A- 15 B , showing a deactivated cutter piston, a nozzle, an activation port and a pressure equalization slot; 
         FIG.  15 D  shows a detailed C view of the selectable hole trimmer of  FIG.  15 A- 15 C , showing a hydraulic fluid port; 
         FIG.  15 E  shows a Section D-D cross-sectional view of the selectable hole trimmer of  FIG.  15 A- 15 D , showing a deactivated cutter piston, an intermediate sleeve, and a sliding sleeve; 
         FIG.  16 A  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.  16 B  shows a Section A-A cross-sectional view of the selectable hole trimmer of  FIG.  16 A , showing an activated cutter piston, a nozzle, a body, an intermediate sleeve, a sliding sleeve, a pressure equalization slot, and a return spring; 
         FIG.  16 C  shows a detailed B view of the selectable hole trimmer of  FIG.  16 A- 16 B , showing an activated cutter piston with an extended cutter, a nozzle, and an activation port; 
         FIG.  16 D  shows a detailed C view of the selectable hole trimmer of  FIG.  16 A- 16 C , showing a hydraulic fluid port; 
         FIG.  16 E  shows a Section D-D cross-sectional view of the selectable hole trimmer of  FIG.  16 A- 16 D , 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.  19 A  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.  19 B  shows a Section A-A cross-sectional view of the selectable hole trimmer of  FIG.  19 A , showing a deactivated cutter piston, body, an intermediate sleeve, a sliding sleeve, a hydraulic fluid port, a compensating spring, and a return spring; 
         FIG.  19 C  shows a Section C-C cross-sectional view of the selectable hole trimmer of  FIG.  19 A- 19 B , 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.  21 A  shows a cross-sectional view of another exemplary embodiment of a downhole device configured as a selectable hole trimer, 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.  21 B  shows a cross-sectional view of the selectable hole trimmer of  FIG.  21 A , 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.  21 C  shows a detailed cross-sectional view of the selectable hole trimmer of  FIG.  21 A , showing a deactivated cutter piston with retracted cutters, the compensating sleeve and the stop block; 
         FIG.  21 D  shows a detailed cross-sectional view of the selectable hole trimmer of  FIGS.  21 B , showing the activated cutter piston with extended cutters; 
         FIG.  21 E  shows a detailed cross-sectional view of the selectable hole trimmer of  FIGS.  21 A and  21 C ; 
         FIG.  21 F  shows a detailed view of the selectable hole trimmer of  FIGS.  21 B and  21 D ; 
         FIG.  21 G  shows an upper, left perspective view of the selectable hole trimmer of  FIGS.  21 A- 21 F , 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.  23 A  shows a flow diagram of another method of using a downhole device configured as a selectable hole trimmer; 
         FIG.  23 B  shows a flow diagram of additional steps for the method of  FIG.  23 A ; 
         FIG.  23 C  shows a flow diagram of additional steps for the method of  FIGS.  23 A- 23 B ; 
         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.  25 A  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.  25 B  shows a cross-sectional view of the selectable hole trimmer of  FIG.  25 B , showing an alternative sliding sleeve; 
         FIG.  26 A  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.  26 B  shows a cross-sectional view of the selectable hole trimmer of  FIG.  26 A , showing the selectable hole cutter in a deactivated position; 
         FIG.  26 C  shows a detailed view of the selectable hole cutter of the selectable hole trimmer of  FIGS.  26 A- 26 B , showing a cutter piston, a cutter, a spring and a retaining ring; 
         FIG.  26 D  shows a cross-sectional view of the selectable hole cutter of  FIG.  26 C , showing the cutter piston and the cutter; 
         FIG.  26 E  shows a cross-sectional view of selectable hole trimmer of  FIGS.  26 A- 26 D , showing the selectable hole trimmer being activated with an activation ball and a catch sleeve being lowered downward to a lower position; 
         FIG.  26 F  shows a cross-sectional view of selectable hole trimmer of  FIGS.  26 A- 26 D , 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.  26 G  shows a cross-sectional view of selectable hole trimmer of  FIGS.  26 A- 26 D , showing the selectable hole trimer 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.  26 H  shows a detailed view of an upper end of the selectable hole trimmer of  FIG.  26 A- 26 B , showing the selectable hole trimmer in a deactivated position and a seat in the catch sleeve; 
         FIG.  26 I  shows a detailed view of the upper end of the selectable hole trimmer of  FIGS.  26 E- 26 G , showing the selectable hole trimmer in an activated position and an activation ball in a seat in the catch sleeve; 
         FIG.  27 A  is a shows a flow diagram of a method of using the selectable hole trimmer of  FIG.  25   ; 
         FIG.  27 B  shows a flow diagram of additional steps for the method of  FIG.  27 A ; 
         FIG.  27 C  shows a flow diagram of additional steps for the method of  FIG.  27 A ; 
         FIG.  27 D  shows a flow diagram of additional steps for the method of  FIG.  27 A ; 
         FIG.  28 A  shows a flow diagram of a method of using the selectable hole trimmer of  FIGS.  25 A and  25 B ; 
         FIG.  28 B  shows a flow diagram of additional steps for the method of  FIG.  28 A ; 
         FIG.  28 C  shows a flow diagram of additional steps for the method of  FIG.  28 A ; 
         FIG.  29 A  shows a flow diagram of a method of using the selectable hole trimmer of  FIGS.  26 A- 26 I ; 
         FIG.  29 B  shows a flow diagram of additional steps for the method of  FIG.  29 A ; and 
         FIG.  29 C  shows a flow diagram of additional steps for the method of  FIG.  29 A . 
     
    
    
     Like numerals refer to like elements. 
     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 changes to a drilling string. In some embodiments, the downhole device may be deployed in the hole in an asleep mode that awaits actuation signals. Once in position, an operator may produce rotation, pressure, weight, or other predetermined protocol to wake up the tool. Once awakened, the downhole device may respond to rotation rates above a predetermined value for initiating the bypass operation and respond to rotation rates not above the predetermined value for stopping the bypass operation. Other controls based on different measurable values may be used. 
     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, 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. 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. 
     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.  14 A :  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.  14 A :  310 ,  312 ,  313  &amp;  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.  14 A :  310  &amp;  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.  14 A :  310  &amp;  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.  14 A :  310 ,  312 ,  314  &amp;  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.  14 A :  340 . For example, the downhole device  210  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. 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.  14 A :  310  &amp;  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.  14 A :  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.  14 A :  334  &amp;  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.  14 A :  310  &amp;  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.  14 A :  310  &amp;  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.  14 A :  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.  14 A :  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.  14 A :  310 ,  312  &amp;  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.  14 A :  312 ,  314  &amp;  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.  14 A :  312  &amp;  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.  14 A :  310  &amp;  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.  14 A :  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.  14 A :  310  &amp;  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.  14 A :  310  &amp;  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.  14 A :  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.  14 A :  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.  14 A :  410  &amp;  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.  14 A :  410  &amp;  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.  14 A :  410  &amp;  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.  14 A :  410 ,  414  &amp;  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.  14 A :  410  &amp;  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.  14 A :  410 ,  420  &amp;  430 . The volume  422  is connected to the motor pump  440  via a motor pump fluid line  436 . See e.g.,  FIG.  14 A :  436  &amp;  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.  14 A :  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.  14 A :  440 ,  442  &amp;  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.  14 A :  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.  14 A :  436 ,  440  &amp;  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.  14 A :  410 ,  414  &amp;  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.  14 A :  420 ,  434 ,  436  &amp;  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.  14 A :  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.  14 A :  410  &amp;  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.  14 A :  410  &amp;  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.  14 A :  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.  14 A :  410  &amp;  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.  14 A . 
     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.  14 A :  535  &amp;  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.  14 A :  535  &amp;  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.  14 A :  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.  14 A :  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.  14 A :  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 &#39;s inner diameter, sealed by seals that allows for relative movement between the sleeve  510  and the body  120 . See e.g.,  FIG.  14 A . 
     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.  14 A . 
     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.  14 A . 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.  14 A . 
       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.  7 A  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  6 A  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.  7 B  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.  7 A and  7 B  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.  7 B , 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.  7 B  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.  7 B  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.  7 B  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.  8 A  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.  8 B  shows a cross-sectional side view, and  FIG.  8 C  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.  8 A  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.  8 B . 
     Alternative Exemplary Downhole Device 
       FIG.  10 A  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.  10 B  shows a cross-sectional side view, and  FIG.  10 C  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.  10 A  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.  10 B . 
     Exemplary Downhole Devices Configured as a Selectable Hole Trimmer 
       FIG.  14 A  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.  14 B  shows a detailed view of the selectable hole trimmer  1400  of  FIG.  14 A ; and  FIG.  14 C  shows a Section A cross-sectional view of the selectable hole trimmer  1400  of  FIG.  14 A . 
       FIG.  15 A  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.  15 B  shows a Section A-A cross-sectional view of the selectable hole trimmer  1500  of  FIG.  15 A , 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.  15 C  shows a detailed B view of the selectable hole trimmer  1500  of  FIG.  15 A- 15 B , showing a deactivated cutter piston  1402 , a nozzle  1404 , an activation port  1514   b  and a pressure equalization slot  1521   b ;  FIG.  15 D  shows a detailed C view of the selectable hole trimmer  1500  of  FIG.  15 A- 15 C , showing a hydraulic fluid port  1514   a ; and  FIG.  15 E  shows a Section D-D cross-sectional view of the selectable hole trimmer  1500  of  FIG.  15 A- 15 D , showing a deactivated cutter piston  1402 , an intermediate sleeve  1510   a , and a sliding sleeve  1510   b.    
       FIG.  16 A  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.  16 B  shows a Section A-A cross-sectional view of the selectable hole trimmer  1600  of  FIG.  16 A , 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.  16 C  shows a detailed B view of the selectable hole trimmer  1600  of  FIG.  16 A- 16 B , showing an activated cutter piston  1402  with an extended cutter  1406 , a nozzle  1404 , and an activation port  1614   b ;  FIG.  16 D  shows a detailed C view of the selectable hole trimmer  1600  of  FIG.  16 A- 16 C , showing a hydraulic fluid port  1614   a ; and  FIG.  16 E  shows a Section D-D cross-sectional view of the selectable hole trimmer  1600  of  FIG.  16 A- 16 D , showing an activated cutter piston  1402  with extended cutters  1406 , an intermediate sleeve  1610   a , and a sliding sleeve  1610   b.    
       FIG.  19 A  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.  19 B  shows a Section A-A cross-sectional view of the selectable hole trimmer  1900  of  FIG.  19 A , 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.  19 C  shows a Section C-C cross-sectional view of the selectable hole trimmer  1900  of  FIG.  19 A- 19 B , showing an intermediate sleeve  1910   a , and a sliding sleeve  1910   b.    
       FIG.  21 A  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.  21 B  shows a cross-sectional view of the exemplary selectable hole trimmer  2100  of  FIG.  21 A , 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.  21 C  shows a detailed cross-sectional view of the exemplary selectable hole trimmer  2100  of  FIG.  21 A , showing a deactivated cutter piston  1402  with retracted cutters  1406 , the compensating sleeve  2110   c  and the stop block  1158 ;  FIG.  21 D  shows a detailed cross-sectional view of the exemplary selectable hole trimmer  2100  of  FIG.  21 B , showing the activated cutter piston  1402  with extended cutters  1406 ;  FIG.  21 E  shows a detailed cross-sectional view of the exemplary hole trimmer  2100  of  FIGS.  21 A and  21 C ;  FIG.  21 F  shows a detailed view of the exemplary hole trimmer  2100  of  FIGS.  21 B and  21 D ; and  FIG.  21 G  shows an upper, left perspective view of the exemplary selectable hole trimmer  2100  of  FIGS.  21 A- 21 F , showing the activated cutter piston  1402  with extended cutters  1406 . 
       FIGS.  14 A,  15 B,  16 B,  19 B and  21 A- 21 B  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.  14 A , 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  &amp;  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  &amp;  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.  14 A , 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  &amp;  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.  14 B  shows a detailed view of the selectable hole trimmer  1400  of  FIG.  14 A , showing a selectable hole cutter  1401 . As shown in  FIG.  14 B , 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.  21 A- 21 D . 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 selective 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  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.  15 B- 15 C,  16 B- 16 C,  19 B &amp;  21 A- 21 D . 
     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.  15 B- 15 C,  16 B- 16 C,  19 B &amp;  21 A- 21 D . 
     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.  15 B- 15 C,  16 B- 16 C,  19 B &amp;  21 A- 21 D . 
     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.  15 B- 15 C,  16 B- 16 C and  19 B . 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.  21 A- 21 D . 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  11412   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.  21 A- 21 D . 
     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.  21 A- 21 D . 
     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.  21 A- 21 D . 
     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.  21 A- 21 D . 
     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.  21 A- 21 D . 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.  15 B- 15 C,  16 B- 16 C,  19 B &amp;  21 A- 21 D . 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.  15 B- 15 C,  16 B- 16 C,  19 B &amp;  21 A- 21 D . 
     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.  15 B- 15 C,  16 B- 16 C,  19 B &amp;  21 A- 21 D . 
       FIG.  14 C  shows a Section A cross-sectional view of the selectable hole trimmer  1400  of  FIG.  14 A , showing a plurality of selectable hole cutters  1401  and a plurality of nozzles  1404 . See e.g.,  FIGS.  15 B- 15 C,  16 B- 16 C,  19 B &amp;  21 A- 21 D . As shown in  FIG.  14 C , 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.  14 A- 14 C . 
     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  1300  may include: providing a lower sleeve, an upper sleeve and a resilient member  1302  (see e.g.,  FIGS.  11 A- 11 B ); assembling the lower sleeve, the upper sleeve and the resilient member to form a sleeve  1304  (see e.g.,  FIGS.  11 C- 1  &amp;  11 C- 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.  11 D- 11 E ). 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.  11 A  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.  11 D- 11 E :  1110  &amp;  1120 .  FIG.  11 B  shows a side view of the lower sleeve, the upper sleeve and a spring of the downhole device  210  shown in  FIG.  11 A  after the first step of assembly. 
     As shown in  FIGS.  11 A- 11 B , 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.  11 A . 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.  11 C- 1    shows a side view of a stop block of the downhole device  210  shown in  FIGS.  11 A- 11 B ;  FIG.  11 C- 2    shows a side view of the assembled sleeve of the exemplary embodiment of the downhole device  210  shown in  FIG.  11 B ; and  FIG.  11 D  shows a side view of a body and the sleeve of the downhole device  210  prior to a second step of assembly.  FIG.  11 E  shows a cross-sectional view of the body and the sleeve of the downhole device  210  of  FIGS.  11 A- 11 D  after the second step of assembly. 
     As shown in  FIGS.  11 C- 1  and  11 C- 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.  11 C- 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.  11 D- 11 E , 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.  11 C- 1  &amp;  11 C- 2   :  1158 ) having carved structures  1110  and  1120 . See e.g.,  FIGS.  11 D- 11 E :  1110  &amp;  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.  11 E , the body  1105  and the sleeve  310 ,  410  and  510  are attached via a connection. See e.g.,  FIG.  11 D . In some embodiment, the body  1105  and the sleeve  310 ,  410 ,  510  are attached via a threaded connection. Id. 
       FIG.  11 F  shows a cross-sectional view of the body  1105  and the sleeve  310 ,  410  and  510  of the downhole device  210  shown in  FIG.  11 E  prior to a third step of assembly. FIG.  11 G shows a cross-sectional view of the downhole device  210  of  FIGS.  11 A- 11 F  after the third step of assembly. 
     As shown in  FIGS.  11 F and  11 G , the body  1105  and the sleeve  310 ,  410  and  510  are attached via a connection. See e.g.,  FIGS.  11 D- 11 E :  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.  11 G . 
     Alternative Downhole Device Configured as Selectable Hole Trimmer 
     As discussed above,  FIG.  19 A  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.  19 B  shows a Section A-A cross-sectional view of the selectable hole trimmer  1900  of  FIG.  19 A , 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.  19 C  shows a Section C-C cross-sectional view of the selectable hole trimmer  1900  of  FIG.  19 A- 19 B , showing an intermediate sleeve  1910   a , and a sliding sleeve  1910   b.    
     As also discussed above,  FIG.  21 A  shows a cross-sectional view of another exemplary embodiment of a downhole device configured as a selectable hole trimer  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.  21 B  shows a cross-sectional view of the exemplary selectable hole trimmer  2100  of  FIG.  21 A , 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.  21 C  shows a detailed cross-sectional view of the exemplary selectable hole trimmer  2100  of  FIG.  21 A , 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.  21 D  shows a detailed cross-sectional view of the exemplary selectable hole trimmer  2100  of  FIG.  21 B , showing the activated cutter piston  1402  with extended cutters  1406 ;  FIG.  21 E  shows a detailed cross-sectional view of the exemplary hole trimmer  2100  of  FIGS.  21 A and  21 C ;  FIG.  21 F  shows a detailed view of the exemplary hole trimmer  2100  of  FIGS.  21 B  and  21 D; and  FIG.  21 G  shows an upper, left perspective view of the exemplary selectable hole trimmer  2100  of  FIGS.  21 A- 21 F , showing the activated cutter piston  1402  with extended cutters  1406 . 
     As shown in  FIGS.  19 A- 19 C and  21 A- 21 G , 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.  19 B ), 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.  21 A ), 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.  19 A,  19 C and  21 A- 21 B , 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.  23 A  shows a flow diagram of another method of using a downhole device configured as a selectable hole trimmer;  FIG.  23 B  shows a flow diagram of additional steps for the method of  FIG.  23 A ; and  FIG.  23 C  shows a flow diagram of additional steps for the method of  FIGS.  23 A- 23 B . 
     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.  23 B , 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.  23 C , 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 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.  19 A,  19 C and  21 A- 21 B , 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.  25 A  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.  25 B  shows a cross-sectional view of the selectable hole trimmer  2500  of  FIG.  25 B , showing an alternative sliding sleeve  2510   b . As shown in  FIGS.  25 A and  25 B , 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.,  25 A. 
     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.  25 A . 
     Alternatively, the sliding sleeve  2510   b  moves downward and presses on the top of the divider seal ring  2546 . See e.g.,  FIG.  25 B . 
     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.  25 A . 
     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.  25 B . 
     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.  25 A . 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.  25 B . 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.  19 A,  19 C and  21 A- 21 B , 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.  25 A- 25 B . 
     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.  26 A  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.  26 B  shows a cross-sectional view of the selectable hole trimmer of  FIG.  26 A , showing the selectable hole cutter  1401  in a deactivated position;  FIG.  26 C  shows a detailed view of the selectable hole cutter  1401  of the selectable hole trimmer of  FIGS.  26 A- 26 B , showing a cutter piston  1402 , a cutter  1406 , a spring  1410  and a retaining ring  1414 ; and  FIG.  26 D  shows a cross-sectional view of the selectable hole cutter  1401  of  FIG.  26 C , showing the cutter piston  1402  and the cutter  1406 . As shown in  FIGS.  26 A and  26 B , the selectable hole trimer  2600  comprises an upper sleeve  2610   g , a charge sleeve  2610   h , a catch sleeve  2610   i , a transfer sleeve  2610   j.    
       FIG.  26 E  shows a cross-sectional view of selectable hole trimmer of  FIGS.  26 A- 26 D , 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.  26 F  shows a cross-sectional view of selectable hole trimmer of  FIGS.  26 A- 26 D , 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.  26 G  shows a cross-sectional view of selectable hole trimmer of  FIGS.  26 A- 26 D , showing the selectable hole trimer  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.  26 H  shows a detailed view of an upper end of the selectable hole trimmer  2600  of  FIG.  26 A- 26 B , showing the selectable hole trimmer  2600  in a deactivated position and a seat  2644  in the catch sleeve  2610   j ;  FIG.  26 I  shows a detailed view of the upper end of the selectable hole trimmer  2600  of  FIGS.  26 E- 26 G , 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.  26 E ) 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.  26 G ) 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 down ward. 
     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.  26 E ) 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.  26 F . 
     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.  26 G ), 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.  26 F ) due to increased hydraulic fluid pressure. See e.g.,  FIG.  26 F . 
     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.  27 A  shows a flow diagram of a method of using the selectable hole trimmer  2700  of  FIG.  24   ; and  FIGS.  27 B- 27 D  show flow diagrams of additional steps for the method  2700  of  FIG.  27 A . As shown in  FIG.  27 A , 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.  27 B , 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.  27 C , 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.  27 D , 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.  28 A  shows a flow diagram of a method of using the selectable hole trimmer  2800  of  FIGS.  25 A- 25 B ; and  FIGS.  28 B- 28 C  show flow diagrams of additional steps for the method  2800  of  FIG.  28 A . As shown in  FIG.  28 A , the method of using the selectable hole trimer  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.  28 B , 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.  28 C , 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 as Selectable Hole Trimmer 
       FIG.  29 A  shows a flow diagram of a method  2900  of using the selectable hole trimmer  2600  of  FIGS.  26 A- 26 I ; and  FIGS.  29 B- 29 C  show flow diagrams of additional steps for the method  2900  of  FIG.  29 A . As shown in  FIG.  29 A , the method of using the selectable hole trimer 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.  29 B , stopping the flow of the drilling fluids through the selectable hole trimmer to deactivate the selectable hole cutter  2910 . 
     As shown in  FIG.  29 C , stopping the flow of the drilling fluids through the selectable hole trimmer  2912 ; raising the selectable hole trimer 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 . 
     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” 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. 
     Definitions 
     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.