Patent Grant
10227826
Field of the Invention
Embodiments of the present invention generally relate to methods and apparatus for operating a downhole tool.
Description of the Related Art
A wellbore is formed to access hydrocarbon bearing formations, e.g. crude oil and/or natural gas, by the use of drilling. Drilling is accomplished by utilizing a drill bit that is mounted on the end of a tubular string, such as a drill string. To drill within the wellbore to a predetermined depth, the drill string is often rotated by a top drive or rotary table on a surface platform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a section of casing is lowered into the wellbore. An annulus is thus formed between the string of casing and the formation. The casing string is temporarily hung from the surface of the well. The casing string is cemented into the wellbore by circulating cement into the annulus defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.
It is common to employ more than one string of casing in a wellbore. In this respect, the well is drilled to a first designated depth with a drill bit on a drill string. The drill string is removed. A first string of casing is then run into the wellbore and set in the drilled out portion of the wellbore, and cement is circulated into the annulus behind the casing string. Next, the well is drilled to a second designated depth, and a second string of casing or liner, is run into the drilled out portion of the wellbore. If the second string is a liner string, the liner is set at a depth such that the upper portion of the second string of casing overlaps the lower portion of the first string of casing. The liner string may then be fixed, or “hung” off of the existing casing by the use of slips which utilize slip members and cones to frictionally affix the new string of liner in the wellbore. The second casing or liner string is then cemented. This process is typically repeated with additional casing or liner strings until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casing/liner of an ever-decreasing diameter.
As more casing/liner strings are set in the wellbore, the casing/liner strings become progressively smaller in diameter to fit within the previous casing/liner string. In a drilling operation, the drill bit for drilling to the next predetermined depth must thus become progressively smaller as the diameter of each casing/liner string decreases. Therefore, multiple drill bits of different sizes are ordinarily necessary for drilling operations. As successively smaller diameter casing/liner strings are installed, the flow area for the production of oil and gas is reduced. Therefore, to increase the annulus for the cementing operation, and to increase the production flow area, it is often desirable to enlarge the borehole below the terminal end of the previously cased/lined borehole. By enlarging the borehole, a larger annulus is provided for subsequently installing and cementing a larger casing/liner string than would have been possible otherwise. Accordingly, by enlarging the borehole below the previously cased borehole, the bottom of the formation can be reached with comparatively larger diameter casing/liner, thereby providing more flow area for the production of oil and/or gas. Underreamers also lessen the equivalent circulation density (ECD) while drilling the borehole.
In order to accomplish drilling a wellbore larger than the bore of the casing/liner, a drill string with an underreamer and pilot bit may be employed. Underreamers may include a plurality of arms which may move between a retracted position and an extended position. The underreamer may be passed through the casing/liner, behind the pilot bit when the arms are retracted. After passing through the casing, the arms may be extended in order to enlarge the wellbore below the casing.
In another embodiment, a method of drilling a wellbore includes running a drilling assembly into the wellbore through a casing string, the drilling assembly comprising a tubular string, an underreamer, and a drill bit; injecting drilling fluid through the tubular string and rotating the drill bit, wherein the underreamer remains locked in the retracted position; sending an instruction signal to the underreamer via modulation of a rotational speed of the drilling assembly or modulation of a drilling fluid flow rate, thereby extending the underreamer; and reaming the wellbore using the extended underreamer.
In one embodiment, a method of drilling a wellbore includes running a drilling assembly into the wellbore through a casing string, the drilling assembly comprising a tubular string, upper and lower underreamers, and a drill bit; injecting drilling fluid through the tubular string and rotating the drill bit, wherein at least one of the underreamers remain locked in the retracted position; sending a first instruction signal to the underreamers to extend one of the underreamers; drilling and reaming the wellbore using the drill bit and the extended underreamer; sending a second instruction signal to the underreamers via modulation of a rotational speed of the drilling assembly or modulation of a drilling fluid flow rate, thereby extending the other of the underreamers; and reaming the wellbore using the extended other underreamer.
In one or more of the embodiments described herein, the instruction signal includes a trigger portion and a command portion.
In another embodiment, a method of drilling a wellbore includes running a drilling assembly into the wellbore through a casing string, the drilling assembly comprising a tubular string, a MWD tool or LWD tool, an underreamer, and a drill bit; injecting drilling fluid through the tubular string and rotating the drill bit, wherein the underreamer remains locked in the retracted position; sending an instruction signal to the underreamer, thereby extending the underreamer; and reaming the wellbore using the extended underreamer.
In one or more of the embodiments described herein, the instruction signal is sent using a RFID tag.
In one or more of the embodiments described herein, the RFID tag flows past the MWD tool or LWD tool and is received by the underreamer.
In one or more of the embodiments described herein, modulation of the rotational speed or fluid flow rate is time based.
In one or more of the embodiments described herein, modulation of the rotational speed or fluid pressure is not time based.
The patent or application file contains at least one drawing executed in color. Copies of this patent or patent application publication with color drawing(s) will be provided by the Office upon request and payment of the necessary fee.
So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.
The underreamer 100 may include a body 5, an adapter 7, a piston 10, one or more seal sleeves 15u,l, a mandrel 20, and one or more arms 50a,b (see
The piston 10 may be a tubular, have a longitudinal bore formed therethrough, and may be disposed in the body bore. The piston 10 may have a flow port 10p formed through a wall thereof corresponding to each arm 50a,b. A nozzle 14 may be disposed in each port 10p and made from an erosion resistant material, such as a metal, alloy, ceramic, or cermet. The mandrel 20 may be tubular, have a longitudinal bore formed therethrough, and be longitudinally coupled to the lower seal sleeve 15l by a threaded connection. The lower seal sleeve 15l may be longitudinally coupled to the body 5 by being disposed between the shoulder 5s and a top of the adapter 7. The upper seal sleeve 15u may be longitudinally coupled to the body 5 by a threaded connection.
Each arm 50a,b may be movable between an extended and a retracted position and may initially be disposed in the opening 5o in the retracted position. Each arm 50a,b may be pivoted to the piston 10 by a fastener 25. Each arm 50a,b may be biased radially inward by a torsion spring (not shown) disposed around the fastener 25. A surface of the body 5 defining each opening 5o may serve as a rotational stop for a respective blade 50a,b, thereby rotationally coupling the blade 50a,b to the body 5 (in both the extended and retracted positions). Each arm 50a,b may include an actuation profile 50p formed in an inner surface thereof corresponding to the profile 5p. Movement of each arm 50a,b along the actuation profile 5p may force the arm radially outward from the retracted position to the extended position. Each actuation profile 5p, 50p may include a shoulder. The shoulders may be inclined relative to a radial axis of the body 5 in order to secure each arm 50a,b to the body in the extended position so that the arms do not chatter or vibrate during reaming. The inclination of the shoulders may create a radial component of the normal reaction force between each arm and the body 5, thereby holding each arm 50a,b radially inward in the extended position. Additionally, the actuation profiles 5p, 50p may each be circumferentially inclined (not shown) to retain the arms 50a,b against a trailing surface of the body defining the opening 5o to further ensure against chatter or vibration.
The underreamer 100 may be fluid operated by drilling fluid injected through the drill string being at a high pressure and drilling fluid and cuttings, collectively returns, flowing to the surface via the annulus being at a lower pressure. A first surface 10h of the piston 10 may be isolated from a second surface 10l of the piston 10 by a lower seal 12l disposed between an outer surface of the piston 10 and an inner surface of the lower seal sleeve 15l. The lower seal 12l may be a ring or stack of seals, such as chevron seals, and made from a polymer, such as an elastomer. The high pressure may act on the first surface 10h of the piston via one or more ports formed through a wall of the mandrel 20 and the low pressure may act on the second surface 10l of the piston 10 via fluid communication with the openings 5o, thereby creating a net actuation force and moving the arms 50a,b from the retracted position to the extended position. An upper seal 12u may be disposed between the upper seal sleeve 15u and an outer surface of the piston 10 to isolate the openings 5o. The upper seal 12u may be a ring or stack of seals, such as chevron seals, and made from a polymer, such as an elastomer. Various other seals, such as o-rings may be disposed throughout the underreamer 100.
In the retracted position, the piston ports 10p may be closed by the mandrel 20 and straddled by seals, such as o-rings, to isolate the ports from the piston bore. In the extended position, the flow ports 10p may be exposed to the piston bore, thereby discharging a portion of the drilling fluid into the annulus to cool and lubricate the arms 50a,b and carry cuttings to the surface. This exposure of the flow ports 10p may result in a drop in upstream pressure, thereby providing an indication at the surface that the arms 50a,b are extended.
The arms 50a,b may be longitudinally aligned and circumferentially spaced around the body 5 and junk slots 5r may be formed in an outer surface of the body between the arms. The junk slots 5r may extend the length of the openings 5o to maximize cooling and cuttings removal (both from the drill bit and the underreamer). The arms 50a,b may be concentrically arranged about the body 5 to reduce vibration during reaming. The underreamer 100 may include a third arm (not shown) and each arm may be spaced at one-hundred twenty degree intervals. The arms 50a,b may be made from a high strength metal or alloy, such as steel. The blades 51a,b may each be arcuate, such as parabolic, semi-elliptical, semi-oval, or semi-super-elliptical. The arcuate blade shape may include a straight or substantially straight gage portion 51g and curved leading 51l and trailing 51t ends, thereby allowing for more cutters 55 to be disposed at the gage portion thereof and providing a curved actuation surface against a previously installed casing shoe when retrieving the underreamer 100 from the wellbore should the actuator spring be unable to retract the blades. Cutters 55 may be disposed on both a leading and trailing surface of each blade for back-reaming capability. The cutters in the leading and trailing ends of each blade may be super-flush with the blade. The gage portion may be raised and the gage-cutters flattened and flush with the blade, thereby ensuring a concentric and full-gage hole.
Alternatively, the cutters 55 may be omitted and the underreamer 100 may be used as a stabilizer instead.
The biasing member may be a spring 235 and may be disposed between a shoulder 210s of the control mandrel 210 and a shoulder of the lock mandrel 230. The spring 235 may bias a longitudinal end of the control mandrel or a control module adapter 212 into abutment with the underreamer piston end 10t, thereby also biasing the underreamer piston 210 toward the retracted position. The control module adapter 212 may be longitudinally coupled to the control mandrel 210, such as by a threaded connection, and may allow the control module 200 to be used with differently configured underreamers by changing the adapter 212. The control mandrel 210 may be longitudinally coupled to the lock mandrel 230 by a latch or lock, such as a plurality of dogs 227. Alternatively, the latch or lock may be a collet. The dogs 227 may be held in place by engagement with a lip 225l of the keeper 225 and engagement with a lip 210l of the control mandrel 210. The lock mandrel 230 may be longitudinally coupled to the piston housing 215 by a threaded connection and may abut a body shoulder 205s and the piston housing 215.
The piston housing 215 may be longitudinally coupled to the body 205 by a threaded connection. The piston 220 may be longitudinally coupled to the keeper 225 by one or more fasteners, such as set screws 224, and by engagement of a piston end 220b with a keeper shoulder 225s. The set screws 224 may each be disposed through a respective slot formed through a wall of the piston 220 so that the piston may move longitudinally relative to the keeper 225, the movement limited by a length of the slot. The keeper 225 may be longitudinally movable relative to the body 205, the movement limited by engagement of the keeper shoulder 225s with a piston housing shoulder 215s and engagement of a keeper longitudinal end with a lock mandrel shoulder 230s. The piston 220 may be longitudinally coupled to the piston housing 215 by one or more frangible fasteners, such as shear screws 222. The piston 220 may have a seat 220s formed therein for receiving a closure element, such as a ball 290, plug, or dart. A nozzle 214 may be disposed in a bore of the piston 220 and made from an erosion resistant material, such as a metal, alloy, ceramic, or cermet.
When deploying the underreamer 100 and control module 200 in the wellbore, a drilling operation (e.g., drilling through a casing shoe) may be performed without operation of the underreamer 100. Even though force is exerted on the underreamer piston 10 by drilling fluid, the shear screws 222 may prevent the underreamer piston 10 from extending the arms 50a,b. When it is desired to operate the underreamer 100, the ball 290 is pumped or dropped from the surface and lands in the ball seat 220s. Drilling fluid continues to be injected or is injected through the drill string. Due to the obstructed piston bore, fluid pressure acting on the ball 290 and piston 220 increases until the shear screws 222 are fractured, thereby allowing the piston to move longitudinally relative to the body 205. The piston end 220b may then engage the keeper shoulder 225s and push the keeper 225 longitudinally relative to the body 205, thereby disengaging the keeper lip 225l from the dogs 227. The control mandrel lip 210l may be inclined and force exerted on the control mandrel 210 by the underreamer piston 10 may push the dogs 227 radially outward into a radial gap defined between the lock mandrel 230 and the keeper 225, thereby freeing the control mandrel and allowing the underreamer piston 10 to extend the arms 50a,b. Movement of the piston 220 may also expose a piston housing bore and place bypass ports 220p formed through a wall of the piston 220 in fluid communication therewith.
The tubular body 341 may house an interior tubular body 350. The inner body 350 may be concentrically supported within the tubular body 341 at its ends by support rings 351. The support rings 351 may be ported to allow drilling fluid flow to pass into an annulus 352 formed between the two bodies 341, 350. The lower end of tubular body 350 may slidingly support a positioning piston 355, the lower end of which may extend out of the body 350 and may engage piston end 10t.
The interior of the piston 355 may be hollow in order to receive a longitudinal position sensor 360. The position sensor 360 may include two telescoping members 361 and 362. The lower member 362 may be connected to the piston 355 and be further adapted to travel within the first member 361. The amount of such travel may be electronically measured. The position sensor 360 may be a linear potentiometer. The upper member 361 may be attached to a bulkhead 365 which may be fixed within the tubular body 350.
The bulkhead 365 may have a solenoid operated valve 366 and passage extending therethrough. The bulkhead 365 may further include a pressure switch 367 and passage. A conduit tube (not shown) may be attached at its lower end to the bulkhead 365 and at its upper end to and through a second bulkhead 369 to provide electrical communication for the position sensor 360, the solenoid valve 366, and the pressure switch 367, to a battery pack 370 located above the second bulkhead 369. The batteries may be high temperature lithium batteries. A compensating piston 371 may be slidingly positioned within the body 350 between the two bulkheads 365,369. A spring 372 may be located between the piston 371 and the second bulkhead 369, and the chamber containing the spring may be vented to allow the entry of drilling fluid.
A tube 301 may be disposed in the connector sub 345 and may house an electronics package 325. The electronics package 325 may include a controller, such as microprocessor, power regulator, and transceiver. Electrical connections 377 may be provided to interconnect the power regulator to the battery pack 370. A data connector 378 may be provided for data communication between the microprocessor 325 and the telemetry sub 400. The data connector may include a short-hop electromagnetic telemetry antenna 378.
Hydraulic fluid (not shown), such as oil, may be disposed in a lower chamber defined by the positioning piston 355, the bulkhead 365, and the body 350 and an upper chamber defined by the compensating piston 371, the bulkhead 365, and the body 350. The spring 372 may bias the compensating piston 371 to push hydraulic oil from the upper reservoir, through the bulkhead passage and valve, thereby extending the positioning piston into engagement with the underreamer piston 10 and biasing the underreamer piston toward the retracted position. Alternatively, the underreamer 100 may include its own return spring and the spring 372 may be used maintain engagement of the positioning piston 355 with the underreamer piston 10. The solenoid valve 366 may be a check valve operable between a closed position where the valve functions as a check valve oriented to prevent flow from the lower chamber to the upper chamber and allow reverse flow therethrough, thereby fluidly locking the underreamer 100 in the retracted position and an open position where the valve allows flow through the passage (in either direction). Alternatively, a solenoid operate shutoff valve may be used instead of the check valve. To allow extension of the underreamer 100, the valve 366 may be opened when drilling fluid is flowing. The underreamer piston 10 may then actuate and push the positioning piston 355 toward the lower bulkhead 365.
The position sensor 360 may measure the position of the piston 355. The controller 325 may monitor the sensor 360 to verify that the piston 355 has been actuated. The differential pressure switch 367 in the lower bulkhead 365 may verify that the underreamer piston 10 has made contact with the positioning piston 355. The force exerted on the piston 355 by the underreamer piston 310 may cause a pressure increase on that side of the bulkhead. Additionally, the underreamer 100 may be modified to be variable (see section mill 1100) and the controller 325 may close the valve 366 before the underreamer arms 50a,b are fully extended, thereby allowing the underreamer 100 to have one or more intermediate positions. Additionally, the controller may lock and unlock the underreamer 100 repeatedly.
In operation, the control module 300 may receive an instruction signal from the surface (discussed below). The instruction signal may direct the control module 300 to allow full or partial extension of the arms 50a,b. The controller 325 may open the solenoid valve 366. If drilling fluid is being circulated through the BHA, the underreamer piston 10 may then extend the arms 50a,b. During extension, the controller 325 may monitor the arms using the pressure sensor 367 and the position sensor 361. Once the arms have reached the instructed position, the controller 325 may close the valve 366, thereby preventing further extension of the arms. The controller 325 may then report a successful extension of the arms or an error if the arms are obstructed from the instructed extension. Once the underreamer operation has concluded, the control module 300 may receive a second instruction signal to retract the arms. If the valve 366 is the check valve, the controller may open the valve or may not have to take action as the check valve may allow for hydraulic fluid to flow from the upper chamber to the lower chamber regardless of whether the valve is open or closed. The controller may simply monitor the position sensor and report successful retraction of the arms. If the valve 366 is a shutoff valve, the instruction signal may include a time at which the rig pumps are shut off or the controller 325 may wait for indication from the telemetry sub that the rig pumps are shut off. The controller may then open the valve to allow the retraction of the arms. Since the control module may not force retraction of the arms 50a,b the control module may be considered a passive control module. Advantageously, the passive control module may use less energy to operate than an active control module (discussed below).
As shown, components of the control module 300 are disposed in a bore of the body 341 and connector 345. Alternatively, components of the control module may be disposed in a wall of the body 341, similar to the telemetry sub 400. The center configured control module 300 may allow for: stronger outer collar connections, a single size usable for different size underreamers or other downhole tools, and easier change-out on the rig floor. The annular alternative arranged control module may provide a central bore therethrough so that tools, such as a ball, may be run-through or dropped through the drill string.
In one embodiment, an optional latch, such as a collet, may be formed in an outer surface of the position piston 355. A corresponding profile may be formed in an inner surface of the interior body 350. The latch may engage the profile when the position piston is in the retracted position. The latch may transfer at least a substantial portion of the underreamer piston 10 force to the interior body 350 when drilling fluid is injected through the underreamer 100, thereby substantially reducing the amount of pressure required in the lower hydraulic chamber to restrain the underreamer piston.
The adapters 401,408 may each be tubular and have a threaded coupling 401p, 408b formed at a longitudinal end thereof for connection with the control module 300 and the drill string. Each housing may be longitudinally and rotationally coupled together by one or more fasteners, such as screws (not shown), and sealed by one or more seals, such as o-rings (not shown).
The sensor housing 404 may include the pressure sensor 405 and a tachometer 455. The pressure sensor 405 may be in fluid communication with a bore of the sensor housing via a first port and in fluid communication with the annulus via a second port. Additionally, the pressure sensor 405 may also measure temperature of the drilling fluid and/or returns. The sensors 405,455 may be in data communication with the electronics package 425 by engagement of contacts disposed at a top of the mandrel 406 with corresponding contacts disposed at a bottom of the sensor housing 406. The sensors 405,455 may also receive electricity via the contacts. The sensor housing 404 may also relay data between the mud pulser 475, the auxiliary sensors 402a,b, and the electronics package 425 via leads and radial contacts 409a,b.
The auxiliary sensors 402a,b may be magnetometers which may be used with the accelerometers for determining directional information, such as azimuth, inclination, and/or tool face/bent sub angle.
The antenna 426 may include an inner liner, a coil, and an outer sleeve disposed along an inner surface of the downlink mandrel 406. The liner may be made from a non-magnetic and non-conductive material, such as a polymer or composite, have a bore formed longitudinally therethrough, and have a helical groove formed in an outer surface thereof. The coil may be wound in the helical groove and made from an electrically conductive material, such as a metal or alloy. The outer sleeve may be made from the non-magnetic and non-conductive material and may be insulate the coil from the downlink mandrel 406. The antenna 426 may be longitudinally and rotationally coupled to the downlink mandrel 406 and sealed from a bore of the telemetry sub 400.
The pressure switch 433 may remain open at the surface to prevent the electronics package 425 from becoming an ignition source. Once the data sub 400 is deployed to a sufficient depth in the wellbore, the pressure switch 433 may close. The microprocessor 430 may also detect deployment in the wellbore using pressure sensor 405. The microprocessor 430 may delay activation of the transmitter for a predetermined period of time to conserve the battery 431.
When it is desired to operate the underreamer 100, one of the tags 450a,p may be pumped or dropped from the surface to the antenna 426. If a passive tag 450p is deployed, the microprocessor 430 may begin transmitting a signal and listening for a response. Once the tag 450p is deployed into proximity of the antenna 426, the passive tag 450p may receive the signal, convert the signal to electricity, and transmit a response signal. The antenna 426 may receive the response signal and the electronics package 425 may amplify, filter, demodulate, and analyze the signal. If the signal matches a predetermined instruction signal, then the microprocessor 430 may communicate the signal to the underreamer control module 300 using the antenna 426 and the transmitter circuit. The instruction signal carried by the tag 450a,p may include an address of a tool (if the BHA includes multiple underreamers and/or stabilizers, discussed below) and a set position (if the underreamer/stabilizer is adjustable).
If an active tag 450a is used, then the tag 450a may include its own battery, pressure switch, and timer so that the tag 450a may perform the function of the components 432-434. Further, either of the tags 450a,p may include a memory unit (not shown) so that the microprocessor 430 may send a signal to the tag and the tag may record the signal. The signal may then be read at the surface. The signal may be confirmation that a previous action was carried out or a measurement by one of the sensors. The data written to the RFID tag may include a date/time stamp, a set position (the command), a measured position (of control module position piston), and a tool address. The written RFID tag may be circulated to the surface via the annulus.
Alternatively, the control module 300 may be hard-wired to the telemetry sub 400 and a single controller, such as a microprocessor, disposed in either sub may control both subs. The control module 300 may be hard-wired by replacing the data connector 378 with contact rings disposed at or near the pin 347 and adding corresponding contact rings to/near the box 408b of the telemetry sub 400. Alternatively, inductive couplings may be used instead of the contact rings. Alternatively, a wet or dry pin and socket connection may be used instead of the contact rings.
Instead of using one of the RFID tags 450a,p to activate the underreamer 100, an instruction signal may be sent to the controller 430 by modulating angular speed of the drill string according to a predetermined protocol. The protocol may represent data by varying the angular speed on to off, a lower speed to a higher speed and/or a higher speed to a lower speed, monotonically increasing from a lower speed to a higher speed and/or a higher speed to a lower speed, maintaining speed for a period of time, and combinations thereof. The modulated angular speed may be detected by the tachometer 455. The controller 430 may then demodulate the signal and relay the signal to the control module controller 325, thereby operating the underreamer 100.
Instead of using one of the RFID tags 450a,p or angular speed modulation to activate the underreamer 100, a signal may be sent to the controller by modulating a flow rate of the rig drilling fluid pump according to a predetermined protocol. Alternatively, a mud pulser (not shown) may be installed in the rig pump outlet and operated by the surface controller to send pressure pulses from the surface to the telemetry sub controller according to a predetermined protocol. The telemetry sub controller may use the turbine and/or pressure sensor as a flow switch and/or flow meter to detect the sequencing of the rig pumps/pressure pulses. The flow rate protocol may represent data by varying the flow rate on to off, a lower speed to a higher speed and/or a higher speed to a lower speed, or monotonically increasing from a lower speed to a higher speed and/or a higher speed to a lower speed. Alternatively, an orifice flow switch or meter may be used to receive pressure pulses/flow rate signals communicated through the drilling fluid from the surface instead of the turbine and/or pressure sensor. Alternatively, the sensor sub may detect the pressure pulses/flow rate signals using the pressure sensor and accelerometers to monitor for BHA vibration caused by the pressure pulse/flow rate signal.
The drilling system 500 may include a drilling derrick 510. The drilling system 500 may further include drawworks 524 for supporting a top drive 542. The top drive 542 may in turn support and rotate a drilling assembly 500. Alternatively, a Kelly and rotary table (not shown) may be used to rotate the drilling assembly instead of the top drive. The drilling assembly 500 may include a drill string 502 and a bottomhole assembly (BHA) 550. The drill string 502 may include joints of threaded drill pipe connected together or coiled tubing. The BHA 550 may include the telemetry sub 400, the control module 300, the underreamer 100, and a drill bit 505. A rig pump 518 may pump drilling fluid, such as mud 514f, out of a pit 520, passing the mud through a stand pipe and Kelly hose to a top drive 542. The mud 514f may continue into the drill string, through a bore of the drill string, through a bore of the BHA, and exit the drill bit 505. The mud 514f may lubricate the bit and carry cuttings from the bit. The drilling fluid and cuttings, collectively returns 514r, flow upward along an annulus 517 formed between the drill string and the wall of the wellbore 516a/casing 519, through a solids treatment system (not shown) where the cuttings are separated. The treated drilling fluid may then be discharged to the mud pit for recirculation.
The drilling system may further include a launcher 520, surface controller 525, and a pressure sensor 528. The pressure sensor 528 may detect mud pulses sent from the telemetry sub 400. The surface controller 525 may be in data communication with the rig pump 518, launcher 520, pressure sensor 528, and top drive 542. The rig pump 518 and/or top drive 542 may include a variable speed drive so that the surface controller 525 may modulate 545 a flow rate of the rig pump 518 and/or an angular speed (RPM) of the top drive 542. The modulated signal may be a square wave, trapezoidal wave, sinusoidal wave, or other suitable waves. Alternatively, the controller 545 may modulate the rig pump and/or top drive by simply switching them on and off.
A first section of a wellbore 516a has been drilled. A casing string 519 has been installed in the wellbore 516a and cemented 511 in place. A casing shoe 519s remains in the wellbore. The drilling assembly 500 may then be deployed into the wellbore 516a until the drill bit 505 is proximate the casing shoe 519s. The drill bit 505 may then be rotated by the top drive and mud injected through the drill string by the rig pump. Weight may be exerted on the drill bit, thereby causing the drill bit to drill through the casing shoe. The underreamer 100 may be restrained in the retracted position by the control module 200/300. Once the casing shoe 519s has been drilled through and the underreamer 100 is in a pilot section 516p of the wellbore, the underreamer 100 may be extended. If the control module 200 is used, then the surface controller 525 may instruct the launcher 520 to deploy the ball 290. If the control module 300 is used, then the surface controller 525 may instruct the launcher 520 to deploy one of the RFID tags 450a,p; modulate angular speed of the top drive 545; or flow rate of the rig pump 518, thereby conveying an instruction signal to extend the underreamer 100. Alternatively, the ball 290/RFID tags 450a,p may be manually launched. The telemetry sub 400 may receive the instruction signal; relay the instruction signal to the control module 300 allow the arms 50a,b to extend; and send a confirmation signal to the surface via mud pulse. The pressure sensor 528 may receive the mud pulse and communicate the mud pulse to the surface controller. The underreamer 100 may then ream the pilot section 516p into a reamed section 516r, thereby facilitating installation of a larger diameter casing/liner upon completion of the reamed section.
Alternatively, instead of drilling through the casing shoe, a sidetrack may be drilled or the casing shoe may have been drilled during a previous trip.
Once drilling and reaming are complete, it may be desirable to perform a cleaning operation to clear the wellbore 516r of cuttings in preparation for cementing a second string of casing. A second instruction signal may sent to the telemetry sub 400 commanding retraction of the arms. The rig pump may be shut down, thereby allowing the control module 300 to retract the arms and lock the arms in the retracted position. Once the arms are retracted, the rig pump may resume circulation of drilling fluid and the telemetry sub may confirm retraction of the arms via mud pulse. Once the confirmation is received at the surface, the cleaning operation may commence. The cleaning operation may involve rotation of the drill string at a high angular velocity that may otherwise damage the arms if they are extended. The drilling assembly may be removed from the wellbore during the cleaning operation. Additionally, the control module 300 may be commanded to retract and lock the arms for other wellbore operations, such as underreaming only a selected portion of the wellbore. Alternatively, the drill string may remain in the wellbore during the cleaning operation and then the arms may be re-extended by sending another instruction signal and the wellbore may be back-reamed while removing the drill string from the wellbore. The arms may then be retracted again when reaching the casing shoe. Alternatively, the cleaning operation may be omitted. Alternatively or additionally, the cleaning operation may be occasionally or periodically performed during the drilling and reaming operation.
The control module 600 may include an outer tubular body 641. The lower end of the body 641 may include a threaded coupling, such as a pin, connectable to the threaded end 5a of the underreamer 100. The upper end of the body 641 may include a threaded coupling, such as a box, connected to a threaded coupling, such as the drill string.
The tubular body 641 may house an interior tubular body 650. The inner body 650 may be concentrically supported within the outer tubular body 641. In one embodiment, a balance piston 671 is disposed between an annulus 644 formed between the two bodies 641, 650. Drilling fluid is allowed to flow into the annulus above the balance piston 671. An upper hydraulic reservoir 602u is formed in the annulus below the balance piston 671 and houses a hydraulic fluid. The interior tubular body 650 may include a central bore. A positioning piston 655 is disposed at the lower end of and may extend out of the tubular body 641. The positioning piston 655 may engage piston end 10t. A flange of the piston 655 sealingly engages an inner surface of the interior tubular body 650. A lower hydraulic chamber 602l is defined in an annular area between the piston 655 and the interior tubular body 650. A biasing member 658, such as a spring, may be used to bias the piston 655 in the extended position, as shown. The lower end of the piston 655 may be coupled to an extension sleeve. In another embodiment, the extension sleeve in integral with the piston 655. A bulkhead 665 is coupled to the inner tubular body 650 and the positioning piston 655. A central bore 657 extends through the exterior tubular body 641, the interior tubular body 650, the bulkhead 665, and the positioning piston 655. The bulkhead 665 may have a hydraulic passage 676 to allow selective fluid communication between the lower hydraulic chamber 602l and the upper hydraulic chamber 602u. In this embodiment, a solenoid valve 666 is used to control fluid communication through the hydraulic passage 676. The bulkhead 665 may further include pressure sensors for measuring the pressure in the lower hydraulic chamber 602l and the pressure in the upper hydraulic chamber.
The compensating piston 671 may be slidingly positioned within the annulus between the interior tubular body 650 and the exterior tubular body 641. The upper hydraulic chamber 602u is defined in an annular area between the inner conduit 601 and the interior tubular body 650 and axially between the compensating piston 671 and the bulkhead 665. The annulus above the compensating piston 671 may be referred to as a compensating chamber 606. The compensating piston 671 equalizes pressure between drilling fluid in the compensating chamber 606 and the upper chamber 602u.
The bulkhead 665 may house the battery 631 and an electronics package 625. The batteries 631 may be high temperature lithium batteries. The electronics package 625 may include a controller, such as microprocessor, power regulator, and transceiver. The controller may be configured to receive data from the sensors. The electronics package may further include sufficient electronic components for RFID communication with either an active RFID tag or a passive RFID tag. The module 600 also includes an antenna 626 for RFID communication.
In one embodiment, the solenoid valve 666 is operable to prevent flow from the lower chamber to the upper chamber in the closed position. Suitable solenoid valves 666 include a check valve or a shutoff valve. Similar to the control module 300, the position piston 655 may prevent the underreamer piston 10 from extending the arms 50a,b while drilling fluid 514f is pumped through the control module 600 and the underreamer 100 due to the closed valve 666. The control module 600 may further include a position sensor, such as a Hall sensor and magnet, which may be monitored by the controller 625 to allow extension of the arms to one or more intermediate positions and/or to confirm full extension of the arms. Alternatively, the position sensor may be a linear voltage differential transformer (LVDT).
In operation, when the controller of the control module 625 may receive a signal instructing retraction of the arms 50a,b, the controller 625 may open the solenoid check valve 666 so oil may flow through the hydraulic passage from the upper chamber to the lower chamber. In one embodiment, the signal is sent using a RFID tag. After the solenoid valve opens, the position piston 655 is allowed to retract, thereby allowing the underreamer arms to extend. Once the controller 625 detects that the position piston 655 is in the instructed position via the position sensor 611, 612, the controller may close the solenoid check valve.
The control module 600 may optionally include an actuator so that the control module 600 may actively move the underreamer piston 10 while the rig pump 518 is injecting drilling fluid through the control module 600 and the underreamer 100. The actuator may be a hydraulic pump in communication with the upper 602u and lower 602l hydraulic chambers via a hydraulic passage and operable to pump the hydraulic fluid from the upper chamber 602u to the lower chamber 602l while being opposed by the underreamer piston 10. An electric motor may drive the hydraulic pump. The electric motor may be reversible to cause the hydraulic pump to pump fluid from the lower chamber 602l to the upper chamber 602u. The active control module 600 may receive an instruction signal from the surface and operate the underreamer 100 without having to wait for shut down of the rig pump 518. Alternatively, the underreamer piston force may be reduced by decreasing flow rate of the drilling fluid or shutting off the rig pump before or during sending of the instruction signal.
Instead of using one of the RFID tags 450a,p, a signal may be sent to the controller 625 by modulating a flow rate of the rig drilling fluid pump according to a predetermined protocol. Alternatively, a mud pulser (not shown) may be installed in the rig pump outlet and operated by the surface controller to send pressure pulses from the surface to the control module 600 according to a predetermined protocol. The module controller 625 may use one or more pressure sensor as a flow switch and/or flow meter to detect the sequencing of the pressure pulses. The flow rate protocol may represent data by varying the flow rate on to off, a lower speed to a higher speed and/or a higher speed to a lower speed, or monotonically increasing from a lower speed to a higher speed and/or a higher speed to a lower speed. Alternatively, an orifice flow switch or meter may be used to receive pressure pulses/flow rate signals communicated through the drilling fluid from the surface instead of the pressure sensor. Alternatively, the control module may detect the pressure pulses/flow rate signals using the pressure sensor and accelerometers to monitor for BHA vibration caused by the pressure pulse/flow rate signal.
In one embodiment, the flow rate signal may include a trigger portion and a command portion. The trigger portion may be used to trigger the command recognition algorithm in the control module for the target tool. For example, the trigger portion may be a flow rate pattern that, when detected by the control module 600, indicates to the target tool that a new command is to be sent. For example, the trigger portion may involve flowing the fluid at or above a first flow rate and then at or below a second flow rate, or vice versa, for the same period of time for two cycles. The trigger portion prevents the receiver, e.g., the control module, from incorrectly activating the target tool. In another embodiment, the trigger portion may be determined by monitoring for a rate of change of the fluid pressure as a result of the change in flow rate. For example, during the trigger portion, the control module may monitor for a rate of change in pressure over time (i.e., slope) that is within a predetermined slope range to “trigger” the algorithm to look for the remainder of the digital command. In another example, the slope has to be bigger than a value defined in the recognition algorithm.
The command portion may be a flow rate pattern that, when detected, instructs the target tool to perform certain functions. The command portion may, for example, instruct the control module 600 to keep the solenoid valve open for a particular time period before closing. In another embodiment, the command portion may instruct the control module 600 to close the solenoid valve or close for a period of time before opening. In one embodiment, the flow rate pattern may be detected downhole as a pressure change due to the tool bore pressure being a function of flow rate, bit nozzle pressure drop, and BHA pressure drop. In another embodiment, the flow rate pattern may be detected downhole by monitoring the speed (e.g., rpm) of impeller or turbine blades or other flow sensor. In another embodiment, the signal may comprise modulating angular speed of the drill string instead of the flow rate. The angular speed may be measured using one or more accelerometers. The speed signal may also include a trigger portion and a command portion. In yet another embodiment, the signal may involve modulation of a combination of flow rate and angular speed. For example, the trigger portion may involve modulation of flow rate and the command portion may involve modulation of speed, and vice versa. In yet another embodiment, other types of modulation protocols are also contemplated. Exemplary modulation protocols include pulse width modulation, amplitude based modulation, phase shift key modulation, and frequency shift key modulation. For example, amplitude based modulation may be used by modulating the flow rate between three different flow rates. In this respect, time is not a constraint in amplitude based modulation.
In one embodiment, one or more underreamers may be used in a bottom hole assembly (“BHA”). In one exemplary arrangement, the BHA may include a drill bit at the bottom, then a 3D rotary steerable system, a lower underreamer, a MWD tool, a LWD tool, an upper underreamer, and other suitable components. In this example, the lower and upper underreamers may be operated by a signal via RFID tag, flow rate modulation, and/or angular speed modulation. The lower underreamer and the upper reamer may be operated by the same of different type of signals. For example, the upper underreamer can be operated by RFID, while the lower underreamer is operated by flow rate modulation. In yet another embodiment, the upper underreamer may be a ball-drop controller and the lower underreamer may be an electro-mechanical controller. The upper underreamer may be used during drilling to underream the drilled borehole. After drilling, the lower underreamer may be used to underream the rat-hole, which is a bottom section of the wellbore between the drill bit and the upper underreamer. The rat-hole is the same diameter as the drill bit. In another embodiment, the lower underreamer could be mounted just above the drill-bit, or anywhere below the MWD pulser and/or turbine. In yet another embodiment, the lower underreamer may be mounted adjacent (either above or below) to the rotary steerable system. The upper underreamer may be mounted above the LWD tool and the MWD tool. In another embodiment, the upper underreamer may be closed prior to opening the lower underreamer or closed shortly after opening the lower underreamer.
In one embodiment, a process of forming a wellbore includes opening the upper underreamer using any of the telemetry method described herein. Optionally, the BHA may be lowered with the upper underreamer already open. The process includes simultaneously drilling using the drill bit and underreaming using the upper underreamer. After drilling, the upper underreamer may optionally be closed using any of the telemetry method described herein. To underream the rat-hole, the BHA is picked up off-bottom to a location above the rat-hole and the lower underreamer is opened using any of the telemetry method described herein. Prior to underreaming, the lower underreamer is optionally set on the ledge of the rat-hole to confirm the lower underreamer is open. Thereafter, the lower underreamer is operated to underream the rat-hole. After underreaming, one or both underreamers are optionally closed, and the BHA is pulled out of the hole.
To actuate the lower underreamer, a RFID tag may be released into the drill string. The RFID tag may flow past the upper underreamer, the LWD tool, and MWD tool, before being picked up or read by the lower underreamer. The RFID tag is configured to only actuate the lower underreamer, not the upper underreamer.
In another embodiment, the lower underreamer may be actuated by sending a flow rate signal such as the signal shown in
Upon receiving the command portion, the controller opens the solenoid valve 666 to allow hydraulic fluid to flow from the lower chamber 602l to the upper chamber 602u. In turn, the arms of the underreamer are allowed extend in response to fluid pressure. Extension of the arms causes the piston to retract and forces the hydraulic fluid to flow from the lower chamber 602l to the upper chamber 602u. The hydraulic fluid causes the compensating piston to move in a direction that increases the size of the upper chamber 602u. The command portion may also instruct the controller to close the solenoid valve after a specified period of time that is sufficient to allow the completion of the reaming process. After reaming, the drilling fluid pressure is relieved to allow the arms of the underreamer to retract. As a result, the spring in the control module biases the piston to the extended position. Also, the hydraulic fluid in the upper chamber is allowed to flow back into the lower chamber. Drilling fluid pressure in the drill string may also act on the compensating piston to facilitate the flow of hydraulic fluid back to the lower chamber.
In another embodiment, at least one of the lower underreamer and the upper underreamer may receive their respective commands from the logging while drilling tool or the rotary steerable system. The LWD tool may obtain the command from changes in the LWD bore pressure, the speed of the turbine/impeller blades, or both.
In yet another embodiment, the flow rate modulation signal may be expressed as a digital signal. For example, referring back to
In yet another embodiment, the command portion of the signal may instruct the controller to perform a particular function is certain conditions are observed. In the example shown in
Referring to
Alternatively, any of the control modules 200, 300, 600, may be used with any of the underreamer 100. Alternatively, any of the sensors or electronics of the telemetry sub 400 may be incorporated into any of the control modules 300, 600 and the telemetry sub 400 may be omitted. Moreover, the control modules 200, 300, 600 may be used to operate other suitable downhole tools, including circulation subs, drilling disconnect, section mills, and combinations thereof. Communication with the control modules to operate any of these downhole tools may include RFID, flow rate commands monitored via pressure changes, flow rate commands monitored via speed changes in the impeller or turbine blades, and combinations thereof.
In another alternative (not shown), any of the electric control modules 300, 600 may include an override connection in the event that the telemetry sub 400 and/or controllers of the control modules fail. An actuator may then be deployed from the surface to the control module through the drill string using wireline or slickline. The actuator may include a mating coupling. The actuator may further include a battery and controller if deployed using slickline. The override connection may be a contact or hard-wire connection, such as a wet-connection, or a wireless connection, such as an inductive coupling. The override connection may be in direct communication with the control module actuator, e.g., the solenoid valve, so that transfer of electricity via the override connection will operate the control module actuator.
In another alternative (not shown), any of the electric control modules 300, 600 may be deployed without the electronics package and without the telemetry sub and include the override connection, discussed above. The wireline or slickline actuator may then be deployed each time it is desired to operate the control module.
Additionally, the telemetry sub 400 or any of the sensors or electronics thereof may be used with the motor actuator, the jar actuator, the vibrating jar actuator, the overshot actuator, or the disconnect actuator disclosed and illustrated in the '077 application.
In one embodiment, a method of drilling a wellbore includes running a drilling assembly into the wellbore through a casing string, the drilling assembly having a tubular string, an underreamer, and a drill bit; injecting drilling fluid through the tubular string and rotating the drill bit, wherein the underreamer remains locked in the retracted position; sending an instruction signal to the underreamer via at least one of modulation of rotational speed of the drilling assembly, modulation of a drilling fluid flow rate, and modulation of a drilling fluid pressure, thereby extending the underreamer; and reaming the wellbore using the extended underreamer.
While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.
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