Underreamer for increasing a wellbore diameter

An underreamer for increasing a diameter of a wellbore. The underreamer may include a body having an axial bore extending at least partially therethrough. An electromagnetic activation system may be disposed at least partially within the bore of the body. A valve may be disposed within the bore of the body and coupled to the electromagnetic activation system. The valve may include a mobile element and a static element. The mobile element may be coupled to the electromagnetic activation system and move from a first position where the mobile element obstructs fluid flow through the valve to a second position where the mobile element permits fluid flow through the valve. A cutter block may be movably coupled to the body and move radially-outward as the mobile element moves from the first position to the second position.

FIELD OF THE INVENTION

Embodiments described herein generally relate to downhole tools. More particularly, such embodiments relate to underreamers for increasing the diameter of a wellbore and methods for using same.

BACKGROUND INFORMATION

Wellbores are drilled by a drill bit coupled to the end portion of a drill pipe. The drill bit drills the wellbore to a “pilot hole” diameter. During or after the drilling of the wellbore to the pilot hole diameter, an underreamer may be used to enlarge the diameter of the wellbore from the original “pilot hole” diameter. The underreamer is run into the wellbore on the same drill pipe, behind the drill bill. The underreamer actuates between an inactive state and an active state. In the inactive state, cutter blocks on the underreamer are folded or retracted inwardly into the body of the underreamer such that the cutter blocks are positioned radially-inward from the surrounding casing or wellbore wall. Once the underreamer reaches the desired depth in the wellbore, the underreamer is actuated to an active state. In the active state, the cutter blocks move radially-outward and into contact with the wellbore wall. The cutter blocks are then used to increase the diameter of the wellbore.

Underreamers are generally spaced axially apart from the drill bit on the drill pipe. For example, the underreamer is typically positioned “above” the drill bit by about 30 m to about 60 m. As such, the underreamer is not able to increase the diameter of this lower portion (30 m-60 m) of the wellbore because the drill bit contacts the subterranean formation proximate the base of the wellbore, thereby preventing further downward movement of the underreamer. This portion of the wellbore that remains at the pilot hole diameter is called the “rat hole.” What is needed, therefore, is an improved system and method for increasing the diameter of at least a portion of the rat hole.

SUMMARY

An underreamer for increasing a diameter of a wellbore is disclosed. The underreamer may include a body having an axial bore extending at least partially therethrough. An electromagnetic activation system (e.g., a motor) may be disposed at least partially within the bore of the body. A valve may be disposed within the bore of the body and coupled to the electromagnetic activation system. The valve may include a mobile element and a static element. The mobile element may be coupled to the electromagnetic activation system and move from a first position where the mobile element obstructs fluid flow through the valve to a second position where the mobile element permits fluid flow through the valve. A cutter block may be movably coupled to the body and move radially-outward as the mobile element moves from the first position to the second position.

A downhole tool is also disclosed. The downhole tool may include a body having an axial bore extending at least partially therethrough. A control unit may be disposed within the bore of the body. The control unit may include a sensor, a control electronic system, an electromagnetic activation system, and a valve. The sensor may receive a signal transmitted through the wellbore or a surrounding formation. The control electronic system may be coupled to the sensor and process the signal. The electromagnetic activation system may be coupled to the control electronic system move in response to the control electronic system processing the signal. The valve may be disposed within the bore of the body and coupled to the electromagnetic activation system. The valve may include a mobile element and a static element. The mobile element may be coupled to the electromagnetic activation system and move from a first position where the mobile element obstructs fluid flow through the valve to a second position where the mobile element permits fluid flow through the valve. A flow tube may be coupled to the valve and have fluid flow therethrough when the mobile element is in the second position.

A method for increasing a diameter of a wellbore is also disclosed. The method may include running a bottom hole assembly into a wellbore. The bottom hole assembly may include a body having an axial bore extending at least partially therethrough. A sensor may be disposed at least partially within the bore of the body. An electromagnetic activation system may be disposed within the bore of the body. A valve may be disposed within the bore of the body and coupled to the electromagnetic activation system. A cutter block may be movably coupled to the body. A signal may be transmitted through the wellbore or a surrounding formation to the sensor. A mobile element of the valve may be moved from a first position to a second position with electromagnetic activation system in response to the signal received by the sensor. The mobile element may obstruct fluid flow through the valve when in the first position and permit fluid flow through the valve when in the second position. The cutter block may move radially-outward in response to the mobile element moving from the first position to the second position.

DETAILED DESCRIPTION

FIG. 1depicts an illustrative bottom hole assembly100disposed within a wellbore102, according to one or more embodiments. The bottom hole assembly100may be run into the wellbore102using a drill pipe110. The bottom hole assembly100may include a drill collar112, one or more stabilizers (three are shown114,118,132), a first underreamer116, a measuring-while-drilling (“MWD”) tool120, a logging-while-drilling (“LWD”) tool122, a communication device124, a flexible joint126, a second underreamer128, a rotary steerable system (“RSS”), and a drill bit136. In at least one embodiment, the rotary steerable system may include a control unit130and a bias unit134.

The measuring-while-drilling tool120may include one or more sensors. The sensors may be used to measure directional parameters (e.g., azimuth and inclination) to assist the navigation of the bottom hole assembly100. The sensors may also measure loads acting on the bottom hole assembly100, such as weight on the drill bit136(“WOB”), torque on the drill bit136(“TOB”), and/or bending moments. The sensors may further measure axial, lateral, and/or torsional vibrations in the drill pipe110as well as the temperature and pressure of the fluids in the wellbore102.

The logging-while-drilling tool122may include one or more sensors configured to measure properties of the formation and its contents such as formation porosity, density, lithology, dielectric constants, formation layer interfaces, and the pressure and permeability of the fluid in the formation. The measuring-while-drilling tool120and/or the logging-while-drilling tool122may be configured to send signals to the surface and receive signals from the surface, for example, by mud pulse telemetry. Although not shown, the bottom hole assembly100may include a bypass valve. The bypass valve may be positioned above the first underreamer116and be selectively activated for cleaning the wellbore102.

The second underreamer128may be positioned along the bottom hole assembly100between the measuring-while-drilling tool120and the drill bit136, between the logging-while-drilling tool122and the drill bit136, between the communication device124and the drill bit136, between the flexible joint126and the drill bit136, between the control unit130and the drill bit136(not shown), or between the bias unit134and the drill bit136(not shown). A distance between the second underreamer128and the drill bit136may be less than about 50 m, less than about 40 m, less than about 30 m, less then about 20 m, less than about 15 m, less than about 10 m, less than about 7.5 m, less than about 5 m, or less than about 2.5 m.

FIG. 2depicts a partial cross-section view of the second underreamer128, according to one or more embodiments. This particular embodiment includes a solenoid and a poppet valve, as shown in greater detail inFIG. 4. The second underreamer128includes a substantially cylindrical body200having an axial bore206extending at least partially (or completely) therethrough. The body200may be a single component, or the body200may be two or more components coupled together. The body200has a first or “upper” end portion202and a second or “lower” end portion204.

One or more cutter blocks220are movably coupled to the body200. Although a single cutter block220is shown, the number of cutter blocks220may range from a low of 1, 2, 3, or 4 to a high of 5, 6, 7, 8, or more. For example, the body200may have three cutter blocks220movably coupled thereto.

The second underreamer128is adapted to actuate from a first or inactive state (as shown inFIG. 2) to a second or active state. When the second underreamer128is in the inactive state, the outer (radial) surfaces222of the cutter blocks220are aligned with, or positioned radially-inward from, the outer (radial) surface208of the body200. The external surface of the body200may have an overall shape of an undergage stabilizer, and the cutter blocks220may be contained in the blade of the undergage stabilizer. When in the inactive state, the outer (radial) surface222of the cutter blocks220may be retracted inside of the surface of the stabilizer blade. Such design/shape of the second underreamer128, similar to the design/shape of an undergage stabilizer, may permit sufficient annular flow passage along the second underreamer128. In another embodiment, when the second underreamer128is in the inactive state, the outer (radial) surfaces222of the cutter blocks220may be positioned radially-outward from the outer (radial) surface208of the body200. In this embodiment, a ratio of the diameter of the outer (radial) surfaces222of the cutter blocks220to the outer (radial) surface208of the body200may be between about 1.01:1 and about 1.03:1, between about 1.02:1 and about 1.05:1, between about 1.05:1 and about 1.1:1, between about 1.1:1 and about 1.15:1, between about 1.01:1 and about 1.15:1, or more. When the cutter blocks220are positioned radially-outward from the body200in the inactive state, the cutter blocks220may stabilize the body200in the wellbore102.

The cutter blocks220have a plurality of splines224(also known as a “Z-drive”) formed on the outer (side) surfaces thereof. The splines224may be or include offset ridges or protrusions configured to engage corresponding grooves or channels in the body200. The splines224on the cutter blocks220(and the corresponding grooves) are oriented at an angle with respect to a longitudinal axis through the body200. The angle may range from a low of about 10°, about 15°, or about 20° to a high of about 25°, about 30°, about 35°, or more. For example, the angle may be between about 15° and about 25°, or about 17° and about 23°. Although four splines224are shown, it will be appreciated that the number of splines224may range from a low of 1, 2, 3, 4, or 5 to a high of about 10, about 15, about 20, about 25, about 30, or more.

When the second underreamer128transitions from the inactive state to the active state, the engagement of the splines224on the cutter blocks220and the grooves in the body200cause the cutter blocks220to simultaneously move axially toward the first end portion202of the body200and radially-outward. The resultant movement may be at an angle between about 15° and about 25°, or about 17° and about 23° with respect to the longitudinal axis through the body200. This movement of the cutter blocks220transitions the second underreamer128into the active state.

When the second underreamer128is in the active state, the outer (radial) surfaces222of the cutter blocks220are positioned radially-outward from the outer (radial) surface208of the body200by a distance226(seeFIG. 8). A ratio of the diameter of the outer (radial) surfaces222of the cutter blocks220to the outer (radial) surface208of the body200may be between about 1.1:1 and about 1.2:1, between about 1.15:1 and about 1.25:1, between about 1.2:1 and about 1.3:1, between about 1.25:1 and about 1.35:1, between about 1.3:1 and about 1.4:1 or more. In addition, a ratio of the distance226(seeFIG. 10) to the diameter of the body200may range from a low of about 1:4, about 1:5, about 1:6, or about 1.7 to a high of about 1:8, about 1:9, about 1:10, about 1:12, or more.

The cutter blocks220each have a plurality of cutting contacts or elements disposed on the outer (radial) surface222thereof. The cutting contacts of the cutter blocks220may include polycrystalline diamond compact (“PDC”) or the like. The cutting contacts on the cutter blocks220are adapted to cut, grind, shear, and/or crush the wall of the wellbore102to increase the diameter thereof when the second underreamer128is in the active state. The cutter blocks220may also include a plurality of stabilizer pads (not shown) disposed on the outer (radial) surface222thereof. When the cutter blocks220include cutting contacts and stabilizer pads, the cutter blocks220may function as a cleanout stabilizer. When the cutter blocks220include stabilizer pads but no cutting contacts, the cutter blocks220may function as an expandable stabilizer.

A first cutter block220of the second underreamer128may have a different height (as measured radially outward from the body200) than a second cutter block (not shown). For example, the first cutter block220may have a greater height than the second cutter block. In this embodiment, the first cutter block220may act as a stabilizer when the second underreamer128is in the inactive state, and the first cutter block220may push the body200off the longitudinal axis of the wellbore102when the second underreamer128is in the active state to allow bi-centric cutting to occur.

A control unit210, e.g., a remote control unit, is disposed within the bore206of the body200. The control unit210is configured to actuate the cutter blocks220from the inactive state to the active state and vice versa, as described in greater detail below. Although the control unit210is shown positioned above the component (e.g., cutter blocks220) that the control unit210actuates, the control unit210may also be positioned below the component that the control unit210actuates. The control unit210may be disposed within and configured to actuate a mechanical device such as the first underreamer116, a pipe cutter, a section mill, a bypass valve, a whipstock anchor, or any other component coupled to or disposed within any downhole tool or bottom hole assembly.

The mechanical device may have at least two positions. For example, a pipe cutter, a section mill, or a variable gauge stabilizer may be retracted or extended, a bypass valve may be open or closed, a whipstock anchor which may be retracted or expanded (for anchoring), a drill string agitator may be locked or in agitation mode, or a jar may be locked or set to ready mode to be triggered. The control unit210may select the mode of the mechanical devices via the setting of a valve (introduced below).

FIG. 3depicts a partial cross-sectional view of the control unit210, according to one or more embodiments. The control unit210may include one or more sensors (one is shown310), a source of electricity (e.g., one or more batteries320) to provide electrical power, an electronics unit330, and an actuator unit340. In another embodiment, the source of electricity may be or include a turbo-generator installed in the vicinity of the control unit210. The mud flow inside the drill string may set in rotation the turbo-generator which delivers electricity to the control unit210. The one or more sensors310are adapted to receive one or more signals, e.g., hydraulic signals, transmitted through the wellbore102, e.g., via the drill pipe110, from the surface that direct the control unit210to actuate the second underreamer128from the inactive state to the active state, or vice versa. In at least one embodiment, the bottom hole assembly100(FIG. 1) may include a plurality of control units or control systems, and each control unit may send and/or receive different signals. Each control unit may be used to actuate a different component (e.g., underreamer) of the bottom hole assembly100.

The sensor310may be or include a flow sensor, a pressure sensor, a delta-pressure sensor (across the collar wall), a vibration sensor, or combinations of such sensors, and the signals may be in the form of flow pulses/variations, pressure pulses/variations, or vibration pulses/variations.

The sensing may also be based on an electromagnetic signal (i.e., current) sent from the surface to the bottom hole assembly100. In such applications, the current path may be via the formation and the drill string. The sensing method (and associated sensor) may be used to determine the current in the collar. In at least one embodiment, the sensor may be a toroid around the collar. In another embodiment, the sensing method may be an “electrical gap” in the drill string obtained by insulating a tubular joint, and measurement of the current from one side to the other side of the “electrical gap” may be accomplished via a measurement amplifier inside the control unit210.

The sensing may also be based on an acoustic signal sent through the mud in the wellbore. A hydrophone may be used as the sensor for detecting the signal. In another embodiment, the sensing may be based on an acoustic signal sent on or through the steel of the drill string, and the sensor may be or include an accelerometer or geophone coupled to the collar steel of the tool. In yet another embodiment, the sensing may be based on an acoustic signal sent on or through the surrounding formation, and the sensor may be a seismic-type sensor in the tool for the detection of the signal.

The electronics unit330may interpret the signals received by the sensor310. In response to the signals, the electronics unit330may control the actuator unit340.

FIG. 4depicts a partial cross-sectional view of the actuator unit340when the second underreamer128is in the inactive state, andFIG. 5depicts a partial cross-sectional view of the actuator unit340when the second underreamer128is in the active state, according to one or more embodiments. The actuator unit340may include a solenoid410having a shaft412coupled thereto. A mobile element, such as plunger or valve414(e.g., a poppet valve), on an end portion of the shaft412is configured to sealingly engage a static element (e.g., a valve seat)420to prevent fluid flow therethrough when the second underreamer128is in the inactive state (seeFIG. 4). The plunger414and/or the valve seat420may be made of ceramic transition-toughened zirconia, tungsten carbide, polycrystalline diamond, stellite, or the like. The stroke of the plunger414may be from about 0.5 mm to about 5 mm.

When the control unit210determines that the second underreamer128is to actuate into the active state, the control unit210directs, e.g., by supplying electrical current to, the solenoid410and the shaft412to move axially with respect to the valve seat420to allow fluid flow through the valve seat420. As shown, the solenoid410and the shaft412move toward the first end portion202of the body200(to the left as shown inFIG. 5) a small distance. The distance may be from about 0.5 mm to about 5 mm or about 1 mm to about 2.5 mm. In other embodiments, the distance may be from about 5 mm to about 10 mm, about 10 mm to about 20 mm, about 20 mm to about 40 mm, or more.

A position sensor430may be used to determine the position of the solenoid410and the shaft412and, thus, the state of the second underreamer128. The position sensor430may communicate the position back to the electronics unit330in the control unit210. Such position information permits the control unit210to lower the current applied to the solenoid410after opening the valve414. The action of valve opening includes a larger pull force (and current applied to solenoid410) than maintaining the valve414in the open position. This selective reduction in current applied to the solenoid410lowers the energy consumption from the one or more batteries320. The heat output from the electronics unit330and solenoid410are also reduced. Based on feedback from the position sensor430, the electronics unit330may reapply current to the solenoid410to open the valve414when the actuator unit340closes at least partially due to external perturbations, such shocks, flows or pressure conditions, or other causes, such as spring bias. The status of the position sensor430may be conveyed from the control unit210to the measuring-while-drilling tool120(seeFIG. 1) for transmission uphole, e.g., via mud pulse telemetry, such that underreamer setting may be monitored.

The position of the plunger or valve414may correspond to the last successfully received signal/command received from uphole. Under high-shock drilling conditions, the plunger or valve414may be inadvertently set in an undesirable position, (e.g., when there is little to no fluid flow through axial bore106). The electronics unit330monitors and/or verifies the position of plunger or valve414via the position sensor430and compares the sensed position to the desired/expected position. If the electronics unit330determines that the plunger or valve414is in an undesirable position, then the electronics unit330initiates a new actuation of the actuator340.

The actuator340may be arranged and designed such that actuation to the open position occurs when there is little to no fluid flow through the axial bore206. When there is little to no fluid flow through the axial bore206, there may also be little to no pressure differential between the axial bore206and the well annulus. Thus, valve414experiences minimal, if any, self-closing effects due to pressure differential. The actuation of the actuator340under minimal self-closing effects may allow smaller currents and smaller components to be used.

When the solenoid410and the shaft412move toward the first end portion202of the body200, the solenoid410compresses a spring440. A locking unit450may secure or “lock” the solenoid410and the shaft412in place when the second underreamer128is in the active state, thereby maintaining the spring440in the compressed state. Thus, the actuator340may be maintained in the open position without application of a current. A short duration current pulse may control the locking unit450during in the opening of the actuator340. The locking unit450may be a secondary solenoid which moves a lock pin, and the lock pin may engage in the plunger or valve414or the solenoid410. In another embodiment, the solenoid410may stay energized until a deactivate command is received. Nevertheless, even if a constant or near constant current is used to energize the solenoid to maintain the actuator340in an open position, the current used to maintain the open position may be less than the current used to actuate the plunger or valve414to the open position, e.g., from closed or near closed position.

Once the second underreamer128is in an active state, fluid may flow radially-inward through a filter460. The filter460is configured to prevent particles (e.g., sand drilling fluid additives such as LCM, and other contaminants) from flowing therethrough to the control unit210. More particularly, the filter460is configured to prevent particles from passing therethrough that would prevent the plunger or valve414from sealing against the valve seat420or would plug the channel or port234(seeFIG. 8). The filter460may be constructed of a wrapped trapezoid wire, as used in sand control operations. The external surface of the filter460may be kept clean by ensuring that mud velocity around the filter460is sufficient (e.g., above 20 feet/second). The flow restrictor may be chosen in accordance with the fluid flow rate to keep the flow velocity sufficient for filter self-cleaning. Once through the filter460, the fluid may then flow toward the first end portion202of the body200, through the valve seat420(now unobstructed by the plunger414), and through a flow tube470toward the second end portion204of the body200. The flow path of the fluid is indicated by the arrows472inFIG. 5.

When the control unit210determines that the second underreamer128is to actuate back into the inactive state, the control unit210de-energizes the solenoid410(or the locking unit450releases the solenoid410), and the compressed spring440moves the solenoid410and the shaft412, thereby moving the plunger414back into sealing engagement with the valve seat420to once again prevent fluid flow through the valve seat420and the flow tube470.

FIG. 6depicts a partial cross-sectional view of another illustrative actuator unit500(involving a rotary motor and rotary valve) when the second underreamer128is in the inactive state, andFIG. 7depicts a partial cross-sectional view of the actuator unit500when the second underreamer128is in the active state, according to one or more embodiments. The actuator unit500may include an electromagnetic activation system (e.g., a motor or electric motor)510. The electronics unit330may cause the motor510to rotate about a longitudinal axis extending therethrough in response to one or more signals, such as pressure signals, received by the sensor310(seeFIG. 3). The motor510may be configured to rotate a predetermined amount in response to each signal. The predetermined amount may range from about 5°, about 10°, about 20°, about 30°, or about 45° to about 60°, about 75°, about 90°, about 180°, or more. For example, in response to a signal received by the sensor310, the motor510may rotate about 5° to about 30°, about 30° to about 60°, about 60° to about 90°, about 90° to about 180°, or about 5° to about 180°.

The motor510may have a shaft512coupled thereto and configured to rotate therewith. The shaft512may be coupled to a valve520. The valve520may be made of diamond, ceramic, tungsten carbide, alloy steel, stellite, thermoplastic, combinations thereof, and the like. The valve520may include a mobile element (e.g., rotor)522and a static element (e.g., a stator)526. The rotor522may be coupled to the shaft512and configured to rotate therewith. The stator526may be stationary with respect to the rotor522. The stator526may be positioned radially-outward from the rotor522, as shown. In another embodiment, the stator526may be positioned radially-inward from the rotor522.

The rotor522may have one or more ports or openings524formed radially therethrough. The openings524may be axially and/or circumferentially offset from one another. Although not shown, in another embodiment, the one or more openings524may be formed axially through the rotor522and be radially and/or circumferentially offset from one another. The number of openings524may range from a low of 1, 2, 3, 4, or 5 to a high of 10, 20, 30, 40, 50, or more.

The stator526may also have one or more ports or openings528formed radially therethrough. The openings528may be axially and/or circumferentially offset from one another. Although not shown, in another embodiment, the one or more openings528may be formed axially through the stator526and be radially and/or circumferentially offset from one another. The number of openings528may range from a low of 1, 2, 3, 4, or 5 to a high of 10, 20, 30, 40, 50, or more. The openings524,528may be arranged and designed to align with one another when the second underreamer128is in the active state, and to be misaligned when the second underreamer128is in the inactive state, as described below.

The rotation of the rotor522may cause the second underreamer128to actuate between the inactive state and the active state. When second underreamer128is in the inactive state, the openings524in the rotor522are not aligned with the openings528in the stator526. As such, the stator526may obstruct the openings524in the rotor522, thereby preventing the fluid from flowing therethrough and into the flow tube470.

When the sensor310receives a signal to actuate the second underreamer128to the active state, the motor510may rotate the rotor522until the openings524in the rotor522are aligned with corresponding openings528in the stator526. When the openings524,528are aligned, a path of fluid communication is provided therethrough. As such, the fluid may flow through the openings524,528and into the flow tube470toward the second end portion204of the body200. The flow path of the fluid is indicated by the arrows530inFIG. 7.

The motor510and the valve520may be arranged and designed such that rotation of the motor510and the rotor522of the valve520occurs when there is little to no fluid flow through the axial bore206. For example, the rotation of the motor510and the rotor522may occur when the fluid flow through the bore206of the body200is less than about 1000 L/min, less than about 500 L/min, less than about 250 L/min, less than about 100 L/min, less than about 50 L/min, less than about 25 L/min, less than about 10 L/min, or about 0 L/min. When there is little to no fluid flow through the axial bore206, there may also be little to no pressure differential between the axial bore206and the well annulus. Thus, valve520experiences minimal, if any, self-closing effects due to pressure differential.

When there is fluid flow through the axial bore206, or when fluid flow through the axial bore206increases above the predetermined level, a pressure differential in a locking mechanism540causes the locking mechanism540to engage the motor510and/or the shaft512to prevent the motor510and the shaft512from rotating the rotor522in the valve520. More particularly, a first side542of the locking mechanism540is in fluid communication with the well annulus through an opening544, and a second side546of the locking mechanism540is in fluid communication with the fluid in the axial bore206. As shown, the first side542is positioned radially inward from the second side546. When there is fluid flow through the axial bore206, or when fluid flow through the axial bore206increases, the pressure of the fluid proximate the second side546of the locking mechanism540increases while the pressure of the fluid proximate the first side542of the locking mechanism540remains substantially constant. This causes the locking mechanism540to move radially-inward until the locking mechanism540engages the motor510and/or the shaft512to prevent the motor510and the shaft512from rotating the rotor522in the valve520. This pressure-actuated locking mechanism540may increase the life of the batteries320because the batteries320supply power to the motor510when the valve520is to be actuated; however, no power is used between actuations.

The lock of the motor510and the valve520may also be achieved by the use of the solenoid410, which may activate a lock pin. The solenoid410and the lock pin may be mounted perpendicular to the axis of rotation of the motor510and the valve520. The lock pin may engage in a radial hole of the rotary component to prohibit any rotation. Current may be applied to the solenoid410to disengage the lock pin before driving the motor510and the valve520in rotation. After the rotation of the motor510and the valve520, the current may be removed from the solenoid410, and a spring may push the solenoid410and the lock pin into the lock mode (by re-engaging the lock pin into a hole in the rotary components).

The lock of the motor510and the rotor522in the valve520(e.g., valve mobile element) may also be obtained by a radial pin entering a small slot of the rotary element (e.g., the motor510or valve520). The pin may be disengaged by the action of a secondary solenoid associated with a spring: the pin, the slot (not shown). The valve520may be made from diamond (Polycrystalline diamond), tungsten carbide, ceramic, stellite, alloy steel, or thermoplastic.

FIGS. 8 and 9depict partial cross-section views of the second underreamer128in the inactive state, according to one or more embodiments. The flow tube470may be coupled to and in fluid communication with a mandrel230disposed within the bore206of the body200. The mandrel230may have one or more ports or openings232formed radially therethrough. For example, mandrel230may include a plurality of openings232that are circumferentially-offset from one another. When the second underreamer128is in the inactive state, an annular sleeve240disposed radially-outward from the mandrel230is axially aligned with the openings232and prevents fluid flow therethrough. This causes the cutter blocks220to be positioned in the inactive state, as shown inFIG. 8.

FIGS. 10 and 11depict partial cross-sectional views of the second underreamer128in the active state, according to one or more embodiments. When the second underreamer128is actuated into the active state, fluid flows through the valve seat420(seeFIGS. 5 and 7) and the flow tube470toward the second end portion204of the body200(to the right as shown inFIGS. 10 and 11). The fluid then flows radially-outward through a channel234formed in the mandrel230into a first chamber236. As the fluid flows into the first chamber236, the pressure in the first chamber236increases. This increase in pressure causes a first piston242to move axially toward the second end portion204of the body200(to the right as shown inFIGS. 10 and 11). The movement of the first piston242causes the sleeve240to also move axially toward the second end portion204of the body200, thereby compressing a spring246. In at least one embodiment, the first piston242and the sleeve240may be a single component.

A plurality of seals (five are shown:248-1,248-2,248-3,248-4,248-5) may prevent the fluid from leaking between adjacent components. The seals248-1,248-2,248-3,248-4,248-5may be dynamic and adapted to move with the first piston242and/or the sleeve240. The seals248-1,248-2,248-3,248-4,248-5may be made from rubber, an elastomer, lapped carbide, Teflon®, metal rings, or the like.

When the first piston242and the sleeve240move toward the second end portion204of the body200, the sleeve240uncovers the one or more openings232in the mandrel230, and one or more openings244formed radially through the first piston242become aligned with the one or more openings232in the mandrel230. When the openings232,244are aligned, fluid may flow from a bore238in the mandrel230through the openings232,244, and into a second chamber250. As the fluid flows into the second chamber250, the pressure in the second chamber250increases. The pressure in the first chamber236and the second chamber250may equalize, and the flow in the flow tube470may become stagnant. The increase in pressure causes a second piston252to move axially toward the first end portion202of the body200(to the left as shown inFIGS. 10 and 11). The movement of the second piston252causes a drive ring254to also move axially toward the first end portion202of the body200. The drive ring254exerts a force on the cutter blocks220in a direction toward the first end portion202of the body200.

When the drive ring254exerts the axial force on the cutter blocks220in a direction toward the first end portion202of the body200, the engagement of the splines224on the cutter blocks220and the grooves in the body200cause the cutter blocks220to simultaneously move axially toward the first end portion202of the body200and radially outward. The resultant movement may be at an angle between about 15° and about 25°, or about 17° and about 23° with respect to the longitudinal axis through the body200. This movement of the cutter blocks220transitions the second underreamer128into the active state. When the second underreamer128is in the active state, the cutter blocks220are positioned as shown inFIG. 10such that the outer (radial) surfaces222of the cutter blocks220are radially-outward from the outer (radial) surface208of the body200.

FIGS. 12, 13 and 14depict a first illustrative sequence of the first and second underreamers116,128increasing the diameter of the wellbore102, according to one or more embodiments. In operation, the drill pipe110runs the bottom hole assembly100with the first and second underreamers116,118coupled thereto into the wellbore102. The first and second underreamers116,118may be in the inactive state while the drill bit136drills the wellbore102to a first “pilot hole” diameter140, as shown inFIG. 12. The first diameter140may range from a low of about 5 cm, about 10 cm, about 15 cm, or about 20 cm to a high of about 30 cm, about 40 cm, about 50 cm, about 60 cm, or more. For example, the first diameter140may be from about 5 cm to about 15 cm, from about 10 cm to about 20 cm, from about 15 cm to about 25 cm, from about 20 cm to about 30 cm, from about 25 cm to about 35 cm, from about 30 cm to about 40 cm, from about 35 cm to about 45 cm, from about 40 cm to about 50 cm, from about 45 cm to about 55 cm, from about 50 cm to about 60 cm, or more. Once the drill bit136reaches the desired depth, as shown inFIG. 12, the portion of the wellbore102below the first underreamer116has the first diameter140.

After the drill bit136drills the wellbore102to the desired depth, the first underreamer116may be actuated into the active state, as shown inFIG. 12. When the first underreamer116is in the active state, the drill pipe110may pull the bottom hole assembly100back toward the surface (i.e., upward, as shown by arrow146). As the first underreamer116moves upward, the cutter blocks117(now expanded radially-outward) cut and/or grind the wall of the wellbore102to increase the diameter of a first portion150of the wellbore102from the first diameter140to a second diameter142. The first portion150of the wellbore102extends upward from the position of the first underreamer116when the drill bit136is positioned proximate the base103of the wellbore102. The second diameter142may be from about 10 cm to about 20 cm, from about 15 cm to about 25 cm, from about 20 cm to about 30 cm, from about 25 cm to about 35 cm, from about 30 cm to about 40 cm, from about 35 cm to about 45 cm, from about 40 cm to about 50 cm, from about 45 cm to about 55 cm, from about 50 cm to about 60 cm, about 55 cm to about 65 cm, about 60 cm to about 70 cm, or more.

After the first underreamer116has increased the diameter of the first portion150of the wellbore102, the second underreamer128is actuated into the active state, as shown inFIG. 13. The second underreamer128may be positioned within the first portion150of the wellbore102when actuated into the active state; however, in another embodiment, the second underreamer128may also be positioned within a second portion152of the wellbore102when actuated into the active state. The second portion152of the wellbore102extends from the position of the first underreamer116to the position of the second underreamer128when the drill bit136is positioned proximate the base103of the wellbore102. The second portion152of the wellbore102is also known as the “rat hole.”

To actuate the second underreamer128into the active state, one or more signals are sent down the wellbore102from the surface and received by the sensor310in the control unit210. The fluid flow rate through axial bore106may be reduced considerably (or even stopped) after receiving the signals to the control unit210. Such flow condition may be maintained for a short time period, e.g., for as long as about 15 minutes. The electronics unit330interprets the signals and causes the solenoid410and the shaft412to move away from the valve seat420, thereby removing the sealing engagement between the plunger414and the valve seat420. Fluid may then flow through the filter460, the valve seat420(now unobstructed), the flow tube470, and the channel234. As the fluid enters the first chamber236, the fluid causes the first piston242and the sleeve240to move such that the sleeve240uncovers the openings232in the mandrel230. The openings232in the mandrel230become aligned with the openings244in the first piston242so that fluid flows from the bore238in the mandrel230through the openings232,244and into the second chamber250. The fluid flowing into the second chamber250causes the second piston252to move the drive ring254. The drive ring254moves the cutter blocks220axially toward the first end portion202of the body200and radially-outward, thereby transitioning the second underreamer128in the active state.

Once the second underreamer128is in the active state, the drill pipe110may move the bottom hole assembly100away from the surface (e.g., downward, as shown by arrow148). As the second underreamer128moves downward, the cutter blocks220(now expanded radially-outward) cut or grind the wall of the wellbore102to increase the diameter of the second portion152of the wellbore102from the first diameter140to a third diameter144, as shown inFIG. 14. The first underreamer116may be in the inactive state while the second underreamer128moves downward (as shown inFIG. 14), or the first underreamer116may be in the active state to act as a stabilizer (not shown).

The third diameter144may range from a low of about 10 cm, about 15 cm, or about 20 cm to a high of about 30 cm, about 40 cm, about 50 cm, or more. For example, the third diameter144may be from about 10 cm to about 20 cm, from about 15 cm to about 25 cm, from about 20 cm to about 30 cm, from about 25 cm to about 35 cm, from about 30 cm to about 40 cm, or more. A ratio of the second and/or third diameters142,144to the first diameter140may be between about 1.05:1 and about 1.15:1, between about 1.1:1 and about 1.2:1, between about 1.15:1 and about 1.25:1, between about 1.2:1 and about 1.3:1, between about 1.25:1 and about 1.35:1, between about 1.3:1 and about 1.5:1, or more. As shown, the second and third diameters142,144are the same; however, in another embodiment, they may be different.

After the second underreamer128has increased the diameter of the second portion152of the wellbore102, the second underreamer128may be actuated into the inactive state. To actuate the second underreamer128back to the inactive state, one or more signals are sent down the wellbore102from the surface and received by the sensor310. The electronics unit330interprets the signals and causes the solenoid410and the shaft412to move back toward from the valve seat420such that the plunger414sealingly engages with valve seat420, thereby preventing fluid flow through the valve seat420and the flow tube470.

With the fluid flow to the channel234and the first chamber236cut off, the force exerted by the compressed spring246overcomes the force exerted by the (now decreasing) pressure in the first chamber236. This causes the first piston242and the sleeve240to move toward the first end portion202of the body200such that the sleeve240blocks fluid flow through the openings232in the mandrel230. With the fluid flow to the second chamber250cut off, the force exerted by the compressed spring260(seeFIG. 10) overcomes the force exerted by the (now decreasing) pressure in the second chamber250. This causes a compressed spring260and a stop ring262(seeFIG. 10) to move the cutter blocks220axially toward the second end portion204of the body200and radially-inward, thereby transitioning the second underreamer128back into the inactive state.

FIGS. 15-17depict another illustrative sequence of the first and second underreamers116,128for increasing the diameter of the wellbore102, according to one or more embodiments. The first underreamer116may be in the active state as the drill bit136drills the wellbore102to the first diameter140. This is referred to as one-pass underreaming, underreaming-while-drilling, or hole enlargement while drilling (“HEWD”). The second underreamer128may be in the inactive state during this initial drilling phase. Once the drill bit136reaches the desired depth, as shown inFIG. 15, the first portion150of the wellbore102has the second diameter142, and the second portion152of the wellbore102has the first diameter140.

The flow of fluid through the bottom hole assembly100may be reduced or stopped, and the drill pipe110may pull the bottom hole assembly100toward the surface (i.e., upward, as shown by arrow146) until the second underreamer128is positioned in the first portion150of the wellbore102, as shown inFIG. 16. The second underreamer128may then be actuated into the active state, as described above. The drill pipe110may then lower the bottom hole assembly100in the wellbore102in the direction148. As the second underreamer128moves downward, the cutter blocks220(now expanded radially-outward) cut or grind the wall of the wellbore102to increase the diameter of the second portion152of the wellbore102from the first diameter140to the third diameter144, as shown inFIG. 17. The first underreamer116may be in the inactive state while the second underreamer128moves downward, or the first underreamer116may be in the active state to act as a stabilizer. The second underreamer128may then be actuated into the inactive state, as described above.

FIGS. 18 and 19depict another illustrative sequence of the first and second underreamers116,128for increasing the diameter of the wellbore102, according to one or more embodiments. Similar to the second sequence described above, the first underreamer116may be in the active state as the drill bit136drills the wellbore102to the first diameter140. The second underreamer128may be in the inactive state during this initial drilling phase. Once the drill bit136reaches the desired depth, as shown inFIG. 15, the first portion150of the wellbore102has the second diameter142, and the second portion152of the wellbore102has the first diameter140.

Rather than raising the second underreamer128into the first portion150of the wellbore102prior to actuating the second underreamer128, as in the second sequence, the second underreamer128may be actuated into the active state while disposed in the second portion152of the wellbore102. For example, the second underreamer128may be actuated into the active state when the drill bit136is positioned proximate the base103of the wellbore102, as shown inFIG. 18.

The drill pipe110may then raise the bottom hole assembly100in the wellbore102in the direction146. As the second underreamer128moves upward, the cutter blocks220(now expanded radially-outward) cut or grind the wall of the wellbore102to increase the diameter of the second portion152of the wellbore102from the first diameter140to the third diameter144, as shown inFIG. 19. The first underreamer116may be in the inactive state while the second underreamer128moves upward, or the first underreamer116may be in the active state to act as a stabilizer. The second underreamer128may then be actuated into the inactive state, as described above.

FIGS. 20 and 21depict another illustrative sequence of the first and second underreamers116,128for increasing the diameter of the wellbore102, according to one or more embodiments. The first underreamer116may be in the active state as the drill bit136drills the wellbore102to the first diameter140. The second underreamer128may be in the inactive state during this initial drilling phase. When the drill bit136is a predetermined distance from the desired depth of the wellbore102, the second underreamer128may be actuated into the active state, as shown inFIG. 20. The distance may be about 1 m to about 5 m, about 5 m to about 10 m, about 10 m to about 25 m, about 25 m to about 50 m, about 50 m to about 100 m, or more. The distance from the desired depth may be greater than the distance between the first and second underreamers116,128.

The drill pipe110may then lower the bottom hole assembly100in the wellbore102in direction148. As the second underreamer128moves downward, the cutter blocks220(now expanded radially-outward) cut or grind the wall of the wellbore102to increase the diameter of the second portion152of the wellbore102from the first diameter140to the third diameter144while the drill bit136drills, as shown inFIG. 21. The first underreamer116may remain in the active state while the second underreamer128moves downward. After the drill bit136reaches the desired depth, the first and second underreamers116,128may be actuated into the inactive state.

In the drill string, several tools may be equipped with a sensing system or sensor to detect signals sent to the downhole tools via the wellbore or surrounding formation. These tools may be designed to detect similar signals based on the same physics, such as flow and/or pressure fluctuation, current in the drill string or the surrounding formation, and/or acoustic signals. The transmitted signal may be sufficiently different so that one of the downhole tools may identify an “acceptable” signal for its own processing. This downhole tool may then take the proper action. The signal differentiation may be based on amplitude, amplitude variation, timing of variations of the amplitude, frequency content of the signal, and/or digital pattern of variation of the amplitude.

The tools which may be simultaneously in the drill string and capable to detect transmitted signal may be the MWD120, the RSS, first underreamer116, the second underreamer128, a diverting valve, a whipstock, a variable gauge stabilizer, a jar (for its locking and un-locking), or any other mechanical tools which may use downhole activation.

As used herein, the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “above” and “below”; “inward” and “outward”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation. The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via one or more intermediate elements or members.”

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from “Underreamer for Increasing a Wellbore Diameter.” Accordingly, all such modifications are intended to be included within the scope of this disclosure. Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges including the combination of any two values, e.g., the combination of any lower value with any upper value, the combination of any two lower values, and/or the combination of any two upper values are contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges appear in one or more claims below. All numerical values are “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.