Wellbore drill bit with stationary and expandable blades

Abstract

A wellbore drill bit with stationary and expandable blades includes a drill bit body defining an internal volume. The stationary blades are attached and stationary with respect to the drill bit body. The stationary blades are spaced apart on an outer surface of the drill bit body to define openings; each defined between two consecutive stationary blades. The expandable blades are positioned in the respective spaces. Each expandable blade can transition between a retracted state and an open state. In the retracted state, each expandable blade is radially nearer to the longitudinal axis compared to each stationary blade. In the open state, each expandable blade extends radially away from the longitudinal axis to be radially farther away from the longitudinal axis compared to each stationary blade. The drill bit includes a ball activation mechanism that can be activated to transition the expandable blades between the retracted and open states.

Description

TECHNICAL FIELD

[0001] This disclosure describes wellbore operations and particularly wellbore drilling operations using a wellbore drilling assembly that implements a wellbore drill bit.BACKGROUND

[0002] Drilling a wellbore through a subterranean formation begins with designing a detailed plan based on the geological survey of the area. The wellbore drilling assembly includes a drilling rig set up to drill a hole deep into the earth, using a wellbore drill bit attached to a drill string. Drilling fluid, also known as mud, is circulated through the drill string to cool the drill bit, remove cuttings, and maintain hydrostatic pressure to prevent well collapse. As the drill bit penetrates different layers, casing pipes are inserted to stabilize the wellbore walls. Cement is then pumped down the casing to secure it in place and isolate the wellbore from surrounding formations. This process ensures a stable path for extracting resources from the targeted reservoir. Wellbore tools like reamers can be used to enlarge the diameter of the wellbore during drilling operations.SUMMARY

[0003] This specification describes technologies relating to a wellbore drill bit with stationary and expandable blades.

[0004] The details of one or more implementations of the subject matter described in this specification are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.BRIEF DESCRIPTION OF THE DRAWINGS

[0005] FIGS. 1A and 1B are each a schematic diagram of an example of a wellbore drill bit having stationary blades and expandable blades.

[0006] FIGS. 2A, 2B and 2C are each a schematic diagram of an activation mechanism implemented by the wellbore drill bit of FIGS. 1A and 1B.

[0007] FIG. 3 is a schematic diagram of a wellbore drilling assembly implementing the wellbore drill bit of FIGS. 1A and 1B.

[0008] FIG. 4 is a flowchart of an example of a process of implementing the wellbore drill bit of FIGS. 1A and 1B.

[0009] Like reference numbers and designations in the various drawings indicate like elements.DETAILED DESCRIPTION

[0010] This disclosure describes a wellbore drill bit with expandable blades of cutters that can be retracted into the body of the wellbore drill bit. Such a drill bit can dynamically adjust its cutting diameter in response to varying geological conditions encountered during drilling operations. Such a drill bit implements a mechanism that allows the blades to extend outward to enlarge the wellbore diameter or retract for passage through narrower sections. Such a drill bit can maintain a full cutting structure when expanded, ensuring efficient rock disintegration while preserving the integrity of the wellbore. Moreover, the bit's retractable feature facilitates its retrieval through the existing casing string, optimizing the drilling process and enhancing well construction methods. Such a drill bit also allows enlarging wellbore diameter even if the inner diameter of the casing is restrictive. Further, implementing the techniques described here eliminates the need for an under-reamer or a similar tool, separate from the wellbore drill bit, to enlarge the wellbore.

[0011] FIGS. 1A and 1B are each a schematic diagram of an example of a wellbore drill bit 100 having stationary blades and expandable blades. The wellbore drill bit 100 can be a polycrystalline diamond cutter (PDC) bit made from diamond grit fused together under high temperature and pressure conditions either in the presence or absence of catalysts. Other types of drill bits, such as tri-cone bit (rock bit), can also be used. The bit 100 includes a drill bit body 102 that has a longitudinal axis 104. When the drill bit 100 is connected to a drill string (not shown) of a drilling assembly and deployed within a wellbore, a longitudinal axis of the drill string aligns with (e.g., is colinear with) the longitudinal axis 104 of the drill bit body 102.

[0012] The drill bit 100 includes multiple stationary blades (e.g., stationary blade 106a) attached to the drill bit body 102. The stationary blades are stationary with respect to the drill bit body 102. That is, the stationary blades are locked to and move with the drill bit body 102. Conversely, the stationary blades do not move when the drill bit body 102 does not move. The stationary blades can drill through a subterranean formation to form a wellbore. For example, the stationary blades are made of PDC. The PDC stationary blades are cylindered with a man-made black diamond cutting face engineered to withstand extreme abrasion, heat and impact that comes from drilling through rock. The PDC stationary blades can be arranged into a geometry called cutting structure, which drives the performance of the stationary blades.

[0013] The multiple stationary blades are spaced apart on an outer surface of the drill bit body 102. For example, the drill bit body 102 defines multiple shoulders (e.g., shoulders 108a, 108b, and so on) on which sets of multiple stationary blades are installed, e.g., as rows of blades. The multiple shoulders are equally spaced around the outer surface of the drill bit body 102. The shoulders are spaced apart to define openings (e.g., openings 110a, 110b, and so on); each opening defined between two consecutively spaced apart shoulders. The openings are sometimes called junk slots that serve as passage ways for wellbore drilling fluids.

[0014] The drill bit body 102 has a longitudinal length called a gauge of the drill bit 100. The features of the drill bit 100 are formed or mounted on the gauge. In some implementations, the gauge of the drill bit 100 is greater than a corresponding gauge of a drill bit that does not have the expandable blades described here. That is, the longitudinal length of the drill bit 100 is greater than that of a drill bit that does not have the expandable blades.

[0015] The drill bit 100 includes multiple expandable blades (e.g., blade 112a) positioned in the gauge of the drill bit 100. Specifically, the multiple expandable blades are positioned in the respective multiple openings defined on the outer surface of the drill bit body 102. Each expandable blade can transition between a retracted state (shown in FIG. 1A) and an open state (shown in FIG. 1B). In the retracted state, each expandable blade is radially nearer to the longitudinal axis 104 compared to each stationary blade. In the open state, each expandable blade extends radially away from the longitudinal axis 104. In this state, each expandable blade is radially farther away from the longitudinal axis compared to each stationary blade. Also, an outer diameter of the drill bit 100 in the retracted state is less than an outer diameter of the drill bit 100 in the open state. As the drill bit 100 transitions from the retracted state to the open state, the outer diameter gradually increases as the expandable blades move away from the longitudinal axis 104. The expandable blades can be in a fully retracted state as long as the stationary blades are radially farther away from the longitudinal axis 104 compared to the expandable blades. Conversely, the expandable blades can be in a fully open state as long as the expandable blades are radially farther away from the longitudinal axis 104 compared to the stationary blades.

[0016] Each expandable blade includes serrated edges configured to cut the subterranean formation and to enlarge a wellbore. For example, the expandable blades can be made of steel or tungsten carbide. As described below, the drill bit 102 implements an activation mechanism that can transition the expandable blades between the retracted state and the open state. In some implementations, the drill bit can include thermally stable polycrystalline (TSP) for gauge protection.

[0017] FIGS. 2A, 2B and 2C are each a schematic diagram of an activation mechanism implemented by the wellbore drill bit of FIGS. 1A and 1B. As shown in each of FIGS. 2A, 2B and 2C, the wellbore drill bit body 102 defines an internal volume 200. In operation, wellbore fluid (e.g., drilling mud) is configured to flow through the internal volume 200 in the direction represented by arrows 202a, 202b. The wellbore drill bit body 102 includes a wall that is thick enough to form or mount the features described above with reference to FIGS. 1A and 1B. The wall is also strong enough to resist the forces on the drill bit 100 during wellbore drilling. The space enclosed by the wall forms the internal volume 200.

[0018] In the schematic diagrams shown in FIGS. 2A, 2B and 2C, the features formed or mounted on the outer surface of the drill bit body 102 have been omitted for ease of illustration and explanation. In the schematic diagram shown in FIG. 2A, the expandable blades (e.g., expandable blades 112a, 112b) are shown in a retracted state. Specifically, FIG. 2A shows that the expandable blades are completely within the internal volume 200 in the retracted state. In some implementations, however, a portion of the expandable blade can be outside the internal volume 200 even when the expandable blades are in a fully retracted state.

[0019] To transition the expandable blades between the retracted state and the open state, the wellbore drill bit 100 implements a ball activation mechanism. The ball activation mechanism is installed within the internal volume 200 defined by the drill bit body 100. The ball activation mechanism includes two pistons. A first piston 202 is positioned within the internal volume 200 and defines a first ball seat 204. The first ball seat 204 can be formed at a geometric center of the first piston 202 and be aligned with the longitudinal axis 104 of the drill bit body 102. A second piston 206 is also positioned within the internal volume 200 and defines a second ball seat 208. The second ball seat 208 can also be formed at a geometric center of the second piston 206 and be aligned with the longitudinal axis 104 of the drill bit body 102. As described below, when the first ball seat 204 receives a first ball 210 (FIG. 2B), a process is initiated to transition the expandable blades from the retracted state to the open state. Subsequently, when the second ball seat 206 receives a second ball 212 (FIG. 2C), another process is initiated to transition the expandable blades from the open state back to the retracted state.

[0020] In some implementations, the first piston 202 defines an internal volume 214. The first piston 202 can be wider (radially) than longer (axially). The first piston 202 can define two radial walls (216a, 216b) that are perpendicular to the longitudinal axis 104. The first piston 202 can also define two axial walls (218a, 218b) that are parallel to the longitudinal axis 104. The internal volume 214 of the first piston 202 is defined by the four walls – the two axial walls and the two radial walls – of the first piston 202. Two openings (220a, 220b) are formed in the two axial walls (218a, 218b), respectively. When wellbore fluid (e.g., drilling mud) flows into the internal volume 214 of the first piston 202, the wellbore fluid can exit the internal volume 214 through the two openings 220a, 220b.

[0021] In some implementations, the second piston 206 is axially offset relative to the first piston 202. For example, the second piston 206 is upstream of the first piston 202 within the internal volume 200 of the drill bit body 102. Wellbore fluid that flows into the internal volume 200 first contacts and flows past the second piston 206 before contacting or flowing past the first piston 202. Like the first piston 202, the second piston also includes two radial walls and two axial walls.

[0022] An axial wall of the second piston 206 is axially offset from the axial wall 218b of the first piston 202. A piece of metal or other material can be positioned between the axial wall of the second piston 206 and the axial wall 218b of the first piston 202. Under this arrangement, an axial movement of the second piston 206 in a downstream direction (i.e., in a direction of flow of the wellbore fluid) can cause axial movement of the first piston 202 in the downstream direction.

[0023] Multiple pads (e.g., pads 222a, 222b) or rams are positioned within the internal volume 200 defined by the drill bit body 102. Each pad is attached to an inner surface of the inner wall of the drill bit body 102 such that each pad extends inward (i.e., towards the longitudinal axis 104) of the drill bit body 102. Each axial wall of the second piston 206 is connected to a respective pad. The connection is such that the second piston 206 and the multiple pads are pinned to each other. That is, an axial force on the second piston 206 causes an axial movement of both the second piston 206 and the multiple pads. Similarly, an axial force on the multiple pads causes an axial movement of both the multiple pads and the second piston 206. In some implementations, such connection can be established by sizing the second piston 206 to fit within the internal distance between the multiple pads. In some implementations, the pads and the second piston 206 can be formed as one integral part.

[0024] The multiple pads 222a, 222b are connected to and in contact with the expandable blades 112a, 112b. The multiple pads 222a, 222b and the expandable blades 112a, 112b are arranged such that an axial movement of the multiple pads 222a, 222b causes a radial movement of the expandable blades 112a, 112b. In particular, in response to a movement of the multiple pads 222a, 222b in an uphole direction (i.e., opposite a downhole direction in which the wellbore fluid is flowed from a surface of the wellbore into the subterranean formation), the expandable blades 112a, 112b move radially away from the longitudinal axis 104 from the retracted state to the open state. Conversely, in response to a movement of the multiple pads 222a, 222b in the downhole direction, the expandable blades 112a, 112b move radially toward the longitudinal axis 104 from the open state to the retracted state. The movement is implemented by traveling blocks that push out the pads. Although FIGS. 2A-2C schematically show the pads as rectangles, the pads can have angular surfaces that transform an axial motion of the pads into a radial motion of the expandable blades.

[0025] FIG. 2A shows the wellbore drill bit 100 with the expandable blades in the retracted state. The retracted state can be a default state in which the wellbore drill bit 100 is deployed. That is, the wellbore drilling operations can be started with the expandable blades in the retracted state. After a portion of the wellbore has been drilled, the expandable blades can be transitioned from the retracted state to the open state. In this default state, wellbore drilling fluid (e.g., drilling mud) flows from a surface of the Earth into the wellbore through a drill string. The drilling mud flows into the internal volume 200 of the drill bit 100 through an axial end of the drill bit 100. The drill mud flows past the second piston 206 and the first piston 202, and flows out of the drill bit 100 through the opposite axial end of the drill bit 100. For example, each of the second piston 206 and the first piston 202 can include bit nozzles through which the drilling mud flows. As the drill bit 100 is rotated by the drill string, the stationary blades (FIGS. 1A, 1B) cut the rock in the subterranean formation to form the wellbore. Further, in this arrangement, the openings 220a, 220b are sealed because the axial walls 218a, 218b of the first piston 202 are closed by the inner walls of the multiple pads 222a, 222b.

[0026] FIG. 2B shows the transition of the expandable blades from the retracted state to the open state. To do so, the first ball 210 is dropped onto the first ball seat 204. For example, the wellbore drilling fluid 224 (e.g., drilling mud) is flowed from the surface in the downhole direction. The first ball 210 can be dropped into the wellbore drilling fluid 224 and carried through the drill string (not shown) into the internal volume 200 of the drill bit body 102. The second piston 206 is upstream of the first piston 202. The second ball seat 208 can be larger than the first ball 210, allowing the first ball 210 to pass through the second piston 206 and onto the first ball seat 204. In some implementations, the ball can be hollow or deformable / dissolvable allowing required pressures to be achieved.

[0027] When the first ball 210 is received in the first ball seat 204, the drilling mud cannot flow past the first piston 202. Instead, the drilling mud is received within the internal volume 214 defined by the first piston 202. Here too, the ball can be hollow or deformable / dissolvable allowing required pressures to be achieved. When the drill string is pressurized, the pressure applies an axial force on the first piston 202. The axial force causes the first piston 202 to axially move in the downstream direction. The multiple pads 222a, 222b, however, remain pinned to the inner wall of the drill bit body 100, causing a separation between the first piston 202 and the multiple pads 222a, 222b. The separation exposes the openings 220a, 22b. The wellbore fluid that flows radially within the first piston 202 exits the internal volume 214 through the openings 220a, 22b. Upon exiting the internal volume 214, the wellbore fluid reverses flow direction and begins to flow in an uphole direction. For example, the drilling mud can exit nozzles under both the expandable blades and the drill bit.

[0028] The wellbore fluid, having reversed flow direction to flow in the uphole direction, applies a force on the multiple pads 222a, 222b in the uphole direction. The force in the uphole direction causes the multiple pads 222a, 222b to move axially in the uphole direction. Such axial movement of the multiple pads 222a, 222b in the uphole direction is transferred to the expandable blades 112a, 112b as a radially outward force away from the longitudinal axis 104. The radially outward force causes the expandable blades 112a, 112b to transition from the retracted state to the open state.

[0029] With the expandable blades in the open state, the drill bit 100 can be rotated to enlarge the wellbore. In the open state, the expandable blades can be locked in place. The ball can then be removed from the ball seat, e.g., by dissolving or deforming the ball, or by using a hollow ball through which the drilling mud can be flowed. Removing the ball from the ball seat allows the drilling mud to flow through the drill bit and out of the bit nozzles at the end of the drill bit. Rotating the drill bit allows the expandable blades to cut through rock formation.

[0030] FIG. 2C shows the transition of the expandable blades from the open state to the retracted state. To do so, the second ball 212 is dropped onto the second ball seat 208. For example, the wellbore drilling fluid 224 (e.g., drilling mud) is flowed from the surface in the downhole direction. The second ball 212 can be dropped into the wellbore drilling fluid 224 and carried through the drill string (not shown) into the internal volume 200 of the drill bit body 102. The second ball 212 can be larger than the second ball seat 208, allowing the second ball seat 208 to retain the second ball 212. The first ball is smaller than the second ball and second ball seat. The first ball cannot be landed in the second ball seat. The second ball cannot fall past the second ball seat.

[0031] When the second ball 212 is received in the second ball seat 208, the drilling mud cannot flow past the second piston 204. When the drill string is pressurized, the pressure applies an axial force on the second piston 204. The axial force causes the second piston 204 to axially move in the downstream direction. The multiple pads 222a, 222b, which are connected to second piston 204, move axially downhole with the second piston 204. Such axial movement of the second piston 204 in the downhole direction causes a radially inward movement of the expandable blades 112a, 112b towards the longitudinal axis 104. Also, such axial movement of the second piston 204 in the downhole direction covers and closes the multiple openings 222a, 222b in the first piston 202.

[0032] The wellbore fluid, having reversed flow direction to flow in the uphole direction, applies a force on the multiple pads 222a, 222b in the uphole direction. The force in the uphole direction causes the multiple pads 222a, 222b to move axially in the uphole direction. Such axial movement of the multiple pads 222a, 222b in the uphole direction is transferred to the expandable blades 112a, 112b as a radially outward force away from the longitudinal axis 104. The radially outward force causes the expandable blades 112a, 112b to transition from the retracted state to the open state. As described above, the ball can be hollow or dissolvable / deformable for removal from the ball seat.

[0033] FIG. 3 is a schematic diagram of a wellbore drilling assembly 300 implementing the wellbore drill bit of FIGS. 1A and 1B. The assembly 300 is implemented to form a wellbore 302 through a subterranean formation 304 (e.g., a formation, a portion of a formation, multiple formations). The assembly 300 includes a drill string 306, which is a wellbore conveyance, run into the wellbore from a surface 308 into the wellbore 302. The drill bit 100 is connected to a downhole end of the drill string 306. As described above, the drill bit 100 is a PDC bit with expandable blades of cutters. The drill bit 100 is run in hole to the desired depth. In some implementations, all or a portion of the wellbore 302 that has been drilled can be cased, and the drill bit 100 can be run inside the cased wellbore. The wellbore fluid circulation rate and pressure can be lower than the pressure required to expand the blades to avoid damage to the casing that can be caused by a stuck bit. In some instances, a rat hole can be formed a few feet below the casing shoe to ensure that the drill bit 100 is fully inside the formation. Then, the expandable blades can be activated to transition the expandable blades from the retracted state to the open state. The expandable blades can remain in the open state until the hole is drilled to the required depth. After that the drill bit 100 can be pulled out of the hole to one full stand below the casing shoe. Then, the expandable blades can be retracted to the retracted state. The wellbore drilling assembly includes the first ball and the second ball that are dropped onto the first ball seat and the second ball seat, respectively, to implement the transition of the expandable blade between the retracted and open states.

[0034] FIG. 4 is a flowchart of an example of a process 400 of implementing the wellbore drill bit 100. The drill bit 100 can be implemented while drilling a wellbore through a subterranean formation using the wellbore drill bit 100, for example, as described with reference to FIG. 3. At 402, a first ball is flowed with a wellbore fluid into the interior volume defined by the wellbore drill bit. At 404, a first ball seat formed in a first piston receives the first ball to prevent flow of wellbore fluid past the first piston. At 406, in response to preventing the flow of wellbore fluid past the first piston, the first piston redirects the wellbore fluid towards multiple pads positioned within the interior volume defined by the wellbore drill bit. At 408, the multiple pads move in an axial direction in response to the redirected flow of the wellbore fluid. The multiple pads contact multiple expandable blades positioned within the interior volume defined by the wellbore drill bit. At 410, the multiple pads move in an axial direction in response to the redirected flow of the wellbore fluid. The multiple pads contact multiple expandable blades positioned within the interior volume defined by the wellbore drill bit. At 412, the multiple expandable blades enlarge the wellbore by rotating within the wellbore.

[0035] At 414, a second ball is flowed with the wellbore fluid into the interior volume defined by the wellbore drill bit. At 416, a second ball seat formed in a second piston positioned within the interior volume defined by the wellbore drill bit receives the second ball. The multiple pads are connected to the second piston. The second ball prevents flow of the wellbore fluid past the second piston. At 418, in response to preventing the flow of the wellbore fluid past the second piston, the second piston moves in an axial direction towards the first piston. At 420, in response to the second piston moving in the axial direction, the pads move axially with the second piston. At 422, the expandable blades move in a radial direction in response to axial movement of the pads.EXAMPLES

[0036] Certain aspects of the subject matter described here can be implemented as a wellbore drilling assembly. The assembly includes a wellbore drill bit that has a drill bit body, multiple stationary blades, multiple expandable blades and a ball activation mechanism. The multiple stationary blades are attached and stationary with respect to the drill bit body. The multiple stationary blades can drill through a subterranean formation to form a wellbore. The multiple stationary blades are spaced apart on an outer surface of the drill bit body to define multiple openings. Each opening is defined between two consecutively spaced apart stationary blades. The multiple expandable blades are positioned in the respective multiple openings. Each expandable blade can drill through the subterranean formation to form the wellbore. Each expandable blade can transition between a retracted state and an open state. In the retracted state, each expandable blade is radially nearer to the longitudinal axis compared to each stationary blade. In the open state, each expandable blade extends radially away from the longitudinal axis to be radially farther away from the longitudinal axis compared to each stationary blade. The ball activation mechanism includes multiple ball seats axially offset from each other along the longitudinal axis. A first ball seat can receive a first ball to transition the multiple expandable blades from the retracted state to the open state. A second ball seat can receive a second ball to transition the multiple expandable blades from the open state to the retracted state. The assembly includes multiple balls including the first ball and the second ball.

[0037] An aspect combinable with any other aspect includes the following features. The drill bit body defines an internal volume including the multiple openings defined on the outer surface of the drill bit body. In the retracted state, the multiple expandable blades reside within the internal volume of the drill bit body. The first ball seat and the second ball seat are installed within the internal volume of the drill bit body.

[0038] An aspect combinable with any other aspect includes the following features. The ball activation mechanism includes a first piston positioned within the internal volume of the drill bit body. The first piston defines the first ball seat. The first piston can move axially within the internal volume of the drill bit body in response to axial pressure.

[0039] An aspect combinable with any other aspect includes the following features. The first piston defines an internal volume. The first piston includes axial walls defining through openings. In an absence of the first ball in the first ball seat, the first piston can permit wellbore fluid to flow along the longitudinal axis past the first piston. In a presence of the first ball in the first ball seat, the first piston can divert the wellbore fluid to flow through the internal volume of the first piston and through openings in the axial walls instead of past the first piston.

[0040] An aspect combinable with any other aspect includes the following features.. The ball activation mechanism includes a second piston positioned within the internal volume of the drill bit body. The second piston defines the second ball seat. The second piston contacts the first piston. The second piston can move axially within the internal volume in response to axial pressure and to responsively axially move the first piston.

[0041] An aspect combinable with any other aspect includes the following features. The ball activation mechanism includes multiple pads positioned within the internal volume defined by the drill bit body. The multiple pads are connected to the multiple expandable blades. The second piston contacts the multiple pads. The multiple pads and the multiple expandable blades are arranged such that an axial movement of the multiple pads within the internal volume defined by the drill bit body causes a radial movement of the multiple expandable blades between the retracted state and the open state.

[0042] An aspect combinable with any other aspect includes the following features. In an absence of the second ball in the second ball seat, the second piston can permit wellbore fluid to flow along the longitudinal axis past the second piston. In a presence of the second ball in the second ball seat, the second piston can prevent the wellbore fluid to flow past the second piston. The second piston can move the multiple pads along the longitudinal axis in response to the wellbore fluid being prevented from flowing past the second piston.

[0043] An aspect combinable with any other aspect includes the following features. The first ball seat is smaller than the second ball seat.

[0044] An aspect combinable with any other aspect includes the following features. The first ball is smaller than the second ball.

[0045] An aspect combinable with any other aspect includes the following features. The multiple stationary blades are attached to a first axial end of the drill bit body. The drill bit body includes a second axial end that can receive the multiple balls.

[0046] An aspect combinable with any other aspect includes the following features. The assembly includes a wellbore conveyance fluidically coupled to the second axial end. The wellbore conveyance can flow wellbore fluid through the second axial end. The multiple balls are flowed into the internal volume of the drill bit body with the wellbore fluid through the wellbore conveyance.

[0047] Certain aspects of the subject matter described here can be implemented as a wellbore drill bit. The drill bit includes a drill bit body having a longitudinal axis and defining an internal volume. The drill bit includes multiple stationary blades attached to the drill bit body and stationary with respect to the drill bit body. The multiple stationary blades can drill through a subterranean formation to form a wellbore. The multiple stationary blades are spaced apart on an outer surface of the drill bit body to define multiple openings. Each opening is defined between two consecutively spaced apart stationary blades. The drill bit includes multiple expandable blades positioned in the respective multiple spaces. Each expandable blade can drill through the subterranean formation to form the wellbore. Each expandable blade can transition between a retracted state and an open state. In the retracted state, each expandable blade is radially nearer to the longitudinal axis compared to each stationary blade. In the open state, each expandable blade extends radially away from the longitudinal axis to be radially farther away from the longitudinal axis compared to each stationary blade. The drill bit includes a ball activation mechanism that includes a first piston and a second piston. The first piston is positioned within the internal volume defined by the drill bit body. The first piston defines a ball seat. The second piston is positioned within the internal volume defined by the drill bit body. The second piston is axially offset from the first piston. The second piston defines a second ball seat. In response to receiving a first ball and a second ball in the first ball seat and the second ball seat, respectively, the first piston and the second piston can axially move causing the multiple expandable blades to radially move between the retracted state and the open state.

[0048] An aspect combinable with any other aspect includes the following features. The drill bit includes multiple pads positioned within the internal volume defined by the drill bit body. The multiple pads are connected to the multiple expandable blades. The multiple pads can move axially within the internal volume defined by the drill bit body.

[0049] An aspect combinable with any other aspect includes the following features. The multiple pads are connected to the second piston. The multiple pads can move axially in response to axial movement of the second piston.

[0050] An aspect combinable with any other aspect includes the following features. The multiple pads are in contact with the multiple expandable blades. The multiple expandable blades can radially move in response to axial movement of the multiple pads.

[0051] Certain aspects of the subject matter described here can be implemented as a method performed while drilling a wellbore through a subterranean formation using a wellbore drill bit. The wellbore drill bit defines an internal volume and includes multiple stationary blades. With a wellbore fluid, a first ball is flowed into the internal volume defined by the wellbore drill bit. A first ball seat formed in a first positioned within the internal volume defined by the wellbore drill bit receives the first ball. The first ball prevents flow of wellbore fluid past the first piston. In response to preventing the flow of wellbore fluid past the first piston, the first piston redirects the wellbore fluids towards multiple pads positioned within the internal volume defined by the wellbore drill bit. The multiple pads move in an axial direction in response to the redirected flow of the wellbore fluid. The multiple pads contact multiple expandable blades positioned within the internal volume defined by the wellbore drill bit. In response to movement of the multiple pads in the axial direction, the multiple pads move the multiple expandable blades in a radially outward direction out of the internal volume defined by the wellbore drill bit. The multiple expandable pads extend past the multiple stationary blades of the wellbore drill bit. The multiple expandable blades enlarge the wellbore by rotating within the wellbore.

[0052] An aspect combinable with any other aspect includes the following features. With the wellbore fluid, a second ball is flowed into the internal volume defined by the wellbore drill bit. A second ball seat formed in a second piston positioned within the internal volume defined by the wellbore drill bit receives the second ball. The second ball prevents flow of the wellbore fluid past the second piston. The multiple pads are connected to the second piston. In response to preventing the flow of the wellbore fluid past the second piston, the second piston moves in an axial direction towards the first piston. In response to the second piston moving in the axial direction towards the first piston, the expandable blades move in a radially inward direction into the internal volume defined by the wellbore drill bit.

[0053] An aspect combinable with any other aspect includes the following features. The first piston is downstream of the second piston.

[0054] An aspect combinable with any other aspect includes the following features. The first ball seat is smaller than the second ball seat.

[0055] An aspect combinable with any other aspect includes the following features. The first ball is smaller than the second ball.

[0056] Thus, particular implementations of the subject matter have been described. Other implementations are within the scope of the following claims.

Examples

examples

[0036] Certain aspects of the subject matter described here can be implemented as a wellbore drilling assembly. The assembly includes a wellbore drill bit that has a drill bit body, multiple stationary blades, multiple expandable blades and a ball activation mechanism. The multiple stationary blades are attached and stationary with respect to the drill bit body. The multiple stationary blades can drill through a subterranean formation to form a wellbore. The multiple stationary blades are spaced apart on an outer surface of the drill bit body to define multiple openings. Each opening is defined between two consecutively spaced apart stationary blades. The multiple expandable blades are positioned in the respective multiple openings. Each expandable blade can drill through the subterranean formation to form the wellbore. Each expandable blade can transition between a retracted state and an open state. In the retracted state, each expandable blade is radially nearer to the longitudina...

TECHNICAL FIELD

[0001] This disclosure describes wellbore operations and particularly wellbore drilling operations using a wellbore drilling assembly that implements a wellbore drill bit.BACKGROUND

[0002] Drilling a wellbore through a subterranean formation begins with designing a detailed plan based on the geological survey of the area. The wellbore drilling assembly includes a drilling rig set up to drill a hole deep into the earth, using a wellbore drill bit attached to a drill string. Drilling fluid, also known as mud, is circulated through the drill string to cool the drill bit, remove cuttings, and maintain hydrostatic pressure to prevent well collapse. As the drill bit penetrates different layers, casing pipes are inserted to stabilize the wellbore walls. Cement is then pumped down the casing to secure it in place and isolate the wellbore from surrounding formations. This process ensures a stable path for extracting resources from the targeted reservoir. Wellbore tools like reamers can be used to enlarge the diameter of the wellbore during drilling operations.SUMMARY

[0003] This specification describes technologies relating to a wellbore drill bit with stationary and expandable blades.

[0004] The details of one or more implementations of the subject matter described in this specification are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.BRIEF DESCRIPTION OF THE DRAWINGS

[0005] FIGS. 1A and 1B are each a schematic diagram of an example of a wellbore drill bit having stationary blades and expandable blades.

[0006] FIGS. 2A, 2B and 2C are each a schematic diagram of an activation mechanism implemented by the wellbore drill bit of FIGS. 1A and 1B.

[0007] FIG. 3 is a schematic diagram of a wellbore drilling assembly implementing the wellbore drill bit of FIGS. 1A and 1B.

[0008] FIG. 4 is a flowchart of an example of a process of implementing the wellbore drill bit of FIGS. 1A and 1B.

[0009] Like reference numbers and designations in the various drawings indicate like elements.DETAILED DESCRIPTION

[0010] This disclosure describes a wellbore drill bit with expandable blades of cutters that can be retracted into the body of the wellbore drill bit. Such a drill bit can dynamically adjust its cutting diameter in response to varying geological conditions encountered during drilling operations. Such a drill bit implements a mechanism that allows the blades to extend outward to enlarge the wellbore diameter or retract for passage through narrower sections. Such a drill bit can maintain a full cutting structure when expanded, ensuring efficient rock disintegration while preserving the integrity of the wellbore. Moreover, the bit's retractable feature facilitates its retrieval through the existing casing string, optimizing the drilling process and enhancing well construction methods. Such a drill bit also allows enlarging wellbore diameter even if the inner diameter of the casing is restrictive. Further, implementing the techniques described here eliminates the need for an under-reamer or a similar tool, separate from the wellbore drill bit, to enlarge the wellbore.

[0011] FIGS. 1A and 1B are each a schematic diagram of an example of a wellbore drill bit 100 having stationary blades and expandable blades. The wellbore drill bit 100 can be a polycrystalline diamond cutter (PDC) bit made from diamond grit fused together under high temperature and pressure conditions either in the presence or absence of catalysts. Other types of drill bits, such as tri-cone bit (rock bit), can also be used. The bit 100 includes a drill bit body 102 that has a longitudinal axis 104. When the drill bit 100 is connected to a drill string (not shown) of a drilling assembly and deployed within a wellbore, a longitudinal axis of the drill string aligns with (e.g., is colinear with) the longitudinal axis 104 of the drill bit body 102.

[0012] The drill bit 100 includes multiple stationary blades (e.g., stationary blade 106a) attached to the drill bit body 102. The stationary blades are stationary with respect to the drill bit body 102. That is, the stationary blades are locked to and move with the drill bit body 102. Conversely, the stationary blades do not move when the drill bit body 102 does not move. The stationary blades can drill through a subterranean formation to form a wellbore. For example, the stationary blades are made of PDC. The PDC stationary blades are cylindered with a man-made black diamond cutting face engineered to withstand extreme abrasion, heat and impact that comes from drilling through rock. The PDC stationary blades can be arranged into a geometry called cutting structure, which drives the performance of the stationary blades.

[0013] The multiple stationary blades are spaced apart on an outer surface of the drill bit body 102. For example, the drill bit body 102 defines multiple shoulders (e.g., shoulders 108a, 108b, and so on) on which sets of multiple stationary blades are installed, e.g., as rows of blades. The multiple shoulders are equally spaced around the outer surface of the drill bit body 102. The shoulders are spaced apart to define openings (e.g., openings 110a, 110b, and so on); each opening defined between two consecutively spaced apart shoulders. The openings are sometimes called junk slots that serve as passage ways for wellbore drilling fluids.

[0014] The drill bit body 102 has a longitudinal length called a gauge of the drill bit 100. The features of the drill bit 100 are formed or mounted on the gauge. In some implementations, the gauge of the drill bit 100 is greater than a corresponding gauge of a drill bit that does not have the expandable blades described here. That is, the longitudinal length of the drill bit 100 is greater than that of a drill bit that does not have the expandable blades.

[0015] The drill bit 100 includes multiple expandable blades (e.g., blade 112a) positioned in the gauge of the drill bit 100. Specifically, the multiple expandable blades are positioned in the respective multiple openings defined on the outer surface of the drill bit body 102. Each expandable blade can transition between a retracted state (shown in FIG. 1A) and an open state (shown in FIG. 1B). In the retracted state, each expandable blade is radially nearer to the longitudinal axis 104 compared to each stationary blade. In the open state, each expandable blade extends radially away from the longitudinal axis 104. In this state, each expandable blade is radially farther away from the longitudinal axis compared to each stationary blade. Also, an outer diameter of the drill bit 100 in the retracted state is less than an outer diameter of the drill bit 100 in the open state. As the drill bit 100 transitions from the retracted state to the open state, the outer diameter gradually increases as the expandable blades move away from the longitudinal axis 104. The expandable blades can be in a fully retracted state as long as the stationary blades are radially farther away from the longitudinal axis 104 compared to the expandable blades. Conversely, the expandable blades can be in a fully open state as long as the expandable blades are radially farther away from the longitudinal axis 104 compared to the stationary blades.

[0016] Each expandable blade includes serrated edges configured to cut the subterranean formation and to enlarge a wellbore. For example, the expandable blades can be made of steel or tungsten carbide. As described below, the drill bit 102 implements an activation mechanism that can transition the expandable blades between the retracted state and the open state. In some implementations, the drill bit can include thermally stable polycrystalline (TSP) for gauge protection.

[0017] FIGS. 2A, 2B and 2C are each a schematic diagram of an activation mechanism implemented by the wellbore drill bit of FIGS. 1A and 1B. As shown in each of FIGS. 2A, 2B and 2C, the wellbore drill bit body 102 defines an internal volume 200. In operation, wellbore fluid (e.g., drilling mud) is configured to flow through the internal volume 200 in the direction represented by arrows 202a, 202b. The wellbore drill bit body 102 includes a wall that is thick enough to form or mount the features described above with reference to FIGS. 1A and 1B. The wall is also strong enough to resist the forces on the drill bit 100 during wellbore drilling. The space enclosed by the wall forms the internal volume 200.

[0018] In the schematic diagrams shown in FIGS. 2A, 2B and 2C, the features formed or mounted on the outer surface of the drill bit body 102 have been omitted for ease of illustration and explanation. In the schematic diagram shown in FIG. 2A, the expandable blades (e.g., expandable blades 112a, 112b) are shown in a retracted state. Specifically, FIG. 2A shows that the expandable blades are completely within the internal volume 200 in the retracted state. In some implementations, however, a portion of the expandable blade can be outside the internal volume 200 even when the expandable blades are in a fully retracted state.

[0019] To transition the expandable blades between the retracted state and the open state, the wellbore drill bit 100 implements a ball activation mechanism. The ball activation mechanism is installed within the internal volume 200 defined by the drill bit body 100. The ball activation mechanism includes two pistons. A first piston 202 is positioned within the internal volume 200 and defines a first ball seat 204. The first ball seat 204 can be formed at a geometric center of the first piston 202 and be aligned with the longitudinal axis 104 of the drill bit body 102. A second piston 206 is also positioned within the internal volume 200 and defines a second ball seat 208. The second ball seat 208 can also be formed at a geometric center of the second piston 206 and be aligned with the longitudinal axis 104 of the drill bit body 102. As described below, when the first ball seat 204 receives a first ball 210 (FIG. 2B), a process is initiated to transition the expandable blades from the retracted state to the open state. Subsequently, when the second ball seat 206 receives a second ball 212 (FIG. 2C), another process is initiated to transition the expandable blades from the open state back to the retracted state.

[0020] In some implementations, the first piston 202 defines an internal volume 214. The first piston 202 can be wider (radially) than longer (axially). The first piston 202 can define two radial walls (216a, 216b) that are perpendicular to the longitudinal axis 104. The first piston 202 can also define two axial walls (218a, 218b) that are parallel to the longitudinal axis 104. The internal volume 214 of the first piston 202 is defined by the four walls – the two axial walls and the two radial walls – of the first piston 202. Two openings (220a, 220b) are formed in the two axial walls (218a, 218b), respectively. When wellbore fluid (e.g., drilling mud) flows into the internal volume 214 of the first piston 202, the wellbore fluid can exit the internal volume 214 through the two openings 220a, 220b.

[0021] In some implementations, the second piston 206 is axially offset relative to the first piston 202. For example, the second piston 206 is upstream of the first piston 202 within the internal volume 200 of the drill bit body 102. Wellbore fluid that flows into the internal volume 200 first contacts and flows past the second piston 206 before contacting or flowing past the first piston 202. Like the first piston 202, the second piston also includes two radial walls and two axial walls.

[0022] An axial wall of the second piston 206 is axially offset from the axial wall 218b of the first piston 202. A piece of metal or other material can be positioned between the axial wall of the second piston 206 and the axial wall 218b of the first piston 202. Under this arrangement, an axial movement of the second piston 206 in a downstream direction (i.e., in a direction of flow of the wellbore fluid) can cause axial movement of the first piston 202 in the downstream direction.

[0023] Multiple pads (e.g., pads 222a, 222b) or rams are positioned within the internal volume 200 defined by the drill bit body 102. Each pad is attached to an inner surface of the inner wall of the drill bit body 102 such that each pad extends inward (i.e., towards the longitudinal axis 104) of the drill bit body 102. Each axial wall of the second piston 206 is connected to a respective pad. The connection is such that the second piston 206 and the multiple pads are pinned to each other. That is, an axial force on the second piston 206 causes an axial movement of both the second piston 206 and the multiple pads. Similarly, an axial force on the multiple pads causes an axial movement of both the multiple pads and the second piston 206. In some implementations, such connection can be established by sizing the second piston 206 to fit within the internal distance between the multiple pads. In some implementations, the pads and the second piston 206 can be formed as one integral part.

[0024] The multiple pads 222a, 222b are connected to and in contact with the expandable blades 112a, 112b. The multiple pads 222a, 222b and the expandable blades 112a, 112b are arranged such that an axial movement of the multiple pads 222a, 222b causes a radial movement of the expandable blades 112a, 112b. In particular, in response to a movement of the multiple pads 222a, 222b in an uphole direction (i.e., opposite a downhole direction in which the wellbore fluid is flowed from a surface of the wellbore into the subterranean formation), the expandable blades 112a, 112b move radially away from the longitudinal axis 104 from the retracted state to the open state. Conversely, in response to a movement of the multiple pads 222a, 222b in the downhole direction, the expandable blades 112a, 112b move radially toward the longitudinal axis 104 from the open state to the retracted state. The movement is implemented by traveling blocks that push out the pads. Although FIGS. 2A-2C schematically show the pads as rectangles, the pads can have angular surfaces that transform an axial motion of the pads into a radial motion of the expandable blades.

[0025] FIG. 2A shows the wellbore drill bit 100 with the expandable blades in the retracted state. The retracted state can be a default state in which the wellbore drill bit 100 is deployed. That is, the wellbore drilling operations can be started with the expandable blades in the retracted state. After a portion of the wellbore has been drilled, the expandable blades can be transitioned from the retracted state to the open state. In this default state, wellbore drilling fluid (e.g., drilling mud) flows from a surface of the Earth into the wellbore through a drill string. The drilling mud flows into the internal volume 200 of the drill bit 100 through an axial end of the drill bit 100. The drill mud flows past the second piston 206 and the first piston 202, and flows out of the drill bit 100 through the opposite axial end of the drill bit 100. For example, each of the second piston 206 and the first piston 202 can include bit nozzles through which the drilling mud flows. As the drill bit 100 is rotated by the drill string, the stationary blades (FIGS. 1A, 1B) cut the rock in the subterranean formation to form the wellbore. Further, in this arrangement, the openings 220a, 220b are sealed because the axial walls 218a, 218b of the first piston 202 are closed by the inner walls of the multiple pads 222a, 222b.

[0026] FIG. 2B shows the transition of the expandable blades from the retracted state to the open state. To do so, the first ball 210 is dropped onto the first ball seat 204. For example, the wellbore drilling fluid 224 (e.g., drilling mud) is flowed from the surface in the downhole direction. The first ball 210 can be dropped into the wellbore drilling fluid 224 and carried through the drill string (not shown) into the internal volume 200 of the drill bit body 102. The second piston 206 is upstream of the first piston 202. The second ball seat 208 can be larger than the first ball 210, allowing the first ball 210 to pass through the second piston 206 and onto the first ball seat 204. In some implementations, the ball can be hollow or deformable / dissolvable allowing required pressures to be achieved.

[0027] When the first ball 210 is received in the first ball seat 204, the drilling mud cannot flow past the first piston 202. Instead, the drilling mud is received within the internal volume 214 defined by the first piston 202. Here too, the ball can be hollow or deformable / dissolvable allowing required pressures to be achieved. When the drill string is pressurized, the pressure applies an axial force on the first piston 202. The axial force causes the first piston 202 to axially move in the downstream direction. The multiple pads 222a, 222b, however, remain pinned to the inner wall of the drill bit body 100, causing a separation between the first piston 202 and the multiple pads 222a, 222b. The separation exposes the openings 220a, 22b. The wellbore fluid that flows radially within the first piston 202 exits the internal volume 214 through the openings 220a, 22b. Upon exiting the internal volume 214, the wellbore fluid reverses flow direction and begins to flow in an uphole direction. For example, the drilling mud can exit nozzles under both the expandable blades and the drill bit.

[0028] The wellbore fluid, having reversed flow direction to flow in the uphole direction, applies a force on the multiple pads 222a, 222b in the uphole direction. The force in the uphole direction causes the multiple pads 222a, 222b to move axially in the uphole direction. Such axial movement of the multiple pads 222a, 222b in the uphole direction is transferred to the expandable blades 112a, 112b as a radially outward force away from the longitudinal axis 104. The radially outward force causes the expandable blades 112a, 112b to transition from the retracted state to the open state.

[0029] With the expandable blades in the open state, the drill bit 100 can be rotated to enlarge the wellbore. In the open state, the expandable blades can be locked in place. The ball can then be removed from the ball seat, e.g., by dissolving or deforming the ball, or by using a hollow ball through which the drilling mud can be flowed. Removing the ball from the ball seat allows the drilling mud to flow through the drill bit and out of the bit nozzles at the end of the drill bit. Rotating the drill bit allows the expandable blades to cut through rock formation.

[0030] FIG. 2C shows the transition of the expandable blades from the open state to the retracted state. To do so, the second ball 212 is dropped onto the second ball seat 208. For example, the wellbore drilling fluid 224 (e.g., drilling mud) is flowed from the surface in the downhole direction. The second ball 212 can be dropped into the wellbore drilling fluid 224 and carried through the drill string (not shown) into the internal volume 200 of the drill bit body 102. The second ball 212 can be larger than the second ball seat 208, allowing the second ball seat 208 to retain the second ball 212. The first ball is smaller than the second ball and second ball seat. The first ball cannot be landed in the second ball seat. The second ball cannot fall past the second ball seat.

[0031] When the second ball 212 is received in the second ball seat 208, the drilling mud cannot flow past the second piston 204. When the drill string is pressurized, the pressure applies an axial force on the second piston 204. The axial force causes the second piston 204 to axially move in the downstream direction. The multiple pads 222a, 222b, which are connected to second piston 204, move axially downhole with the second piston 204. Such axial movement of the second piston 204 in the downhole direction causes a radially inward movement of the expandable blades 112a, 112b towards the longitudinal axis 104. Also, such axial movement of the second piston 204 in the downhole direction covers and closes the multiple openings 222a, 222b in the first piston 202.

[0032] The wellbore fluid, having reversed flow direction to flow in the uphole direction, applies a force on the multiple pads 222a, 222b in the uphole direction. The force in the uphole direction causes the multiple pads 222a, 222b to move axially in the uphole direction. Such axial movement of the multiple pads 222a, 222b in the uphole direction is transferred to the expandable blades 112a, 112b as a radially outward force away from the longitudinal axis 104. The radially outward force causes the expandable blades 112a, 112b to transition from the retracted state to the open state. As described above, the ball can be hollow or dissolvable / deformable for removal from the ball seat.

[0033] FIG. 3 is a schematic diagram of a wellbore drilling assembly 300 implementing the wellbore drill bit of FIGS. 1A and 1B. The assembly 300 is implemented to form a wellbore 302 through a subterranean formation 304 (e.g., a formation, a portion of a formation, multiple formations). The assembly 300 includes a drill string 306, which is a wellbore conveyance, run into the wellbore from a surface 308 into the wellbore 302. The drill bit 100 is connected to a downhole end of the drill string 306. As described above, the drill bit 100 is a PDC bit with expandable blades of cutters. The drill bit 100 is run in hole to the desired depth. In some implementations, all or a portion of the wellbore 302 that has been drilled can be cased, and the drill bit 100 can be run inside the cased wellbore. The wellbore fluid circulation rate and pressure can be lower than the pressure required to expand the blades to avoid damage to the casing that can be caused by a stuck bit. In some instances, a rat hole can be formed a few feet below the casing shoe to ensure that the drill bit 100 is fully inside the formation. Then, the expandable blades can be activated to transition the expandable blades from the retracted state to the open state. The expandable blades can remain in the open state until the hole is drilled to the required depth. After that the drill bit 100 can be pulled out of the hole to one full stand below the casing shoe. Then, the expandable blades can be retracted to the retracted state. The wellbore drilling assembly includes the first ball and the second ball that are dropped onto the first ball seat and the second ball seat, respectively, to implement the transition of the expandable blade between the retracted and open states.

[0034] FIG. 4 is a flowchart of an example of a process 400 of implementing the wellbore drill bit 100. The drill bit 100 can be implemented while drilling a wellbore through a subterranean formation using the wellbore drill bit 100, for example, as described with reference to FIG. 3. At 402, a first ball is flowed with a wellbore fluid into the interior volume defined by the wellbore drill bit. At 404, a first ball seat formed in a first piston receives the first ball to prevent flow of wellbore fluid past the first piston. At 406, in response to preventing the flow of wellbore fluid past the first piston, the first piston redirects the wellbore fluid towards multiple pads positioned within the interior volume defined by the wellbore drill bit. At 408, the multiple pads move in an axial direction in response to the redirected flow of the wellbore fluid. The multiple pads contact multiple expandable blades positioned within the interior volume defined by the wellbore drill bit. At 410, the multiple pads move in an axial direction in response to the redirected flow of the wellbore fluid. The multiple pads contact multiple expandable blades positioned within the interior volume defined by the wellbore drill bit. At 412, the multiple expandable blades enlarge the wellbore by rotating within the wellbore.

[0035] At 414, a second ball is flowed with the wellbore fluid into the interior volume defined by the wellbore drill bit. At 416, a second ball seat formed in a second piston positioned within the interior volume defined by the wellbore drill bit receives the second ball. The multiple pads are connected to the second piston. The second ball prevents flow of the wellbore fluid past the second piston. At 418, in response to preventing the flow of the wellbore fluid past the second piston, the second piston moves in an axial direction towards the first piston. At 420, in response to the second piston moving in the axial direction, the pads move axially with the second piston. At 422, the expandable blades move in a radial direction in response to axial movement of the pads.EXAMPLES

[0036] Certain aspects of the subject matter described here can be implemented as a wellbore drilling assembly. The assembly includes a wellbore drill bit that has a drill bit body, multiple stationary blades, multiple expandable blades and a ball activation mechanism. The multiple stationary blades are attached and stationary with respect to the drill bit body. The multiple stationary blades can drill through a subterranean formation to form a wellbore. The multiple stationary blades are spaced apart on an outer surface of the drill bit body to define multiple openings. Each opening is defined between two consecutively spaced apart stationary blades. The multiple expandable blades are positioned in the respective multiple openings. Each expandable blade can drill through the subterranean formation to form the wellbore. Each expandable blade can transition between a retracted state and an open state. In the retracted state, each expandable blade is radially nearer to the longitudinal axis compared to each stationary blade. In the open state, each expandable blade extends radially away from the longitudinal axis to be radially farther away from the longitudinal axis compared to each stationary blade. The ball activation mechanism includes multiple ball seats axially offset from each other along the longitudinal axis. A first ball seat can receive a first ball to transition the multiple expandable blades from the retracted state to the open state. A second ball seat can receive a second ball to transition the multiple expandable blades from the open state to the retracted state. The assembly includes multiple balls including the first ball and the second ball.

[0037] An aspect combinable with any other aspect includes the following features. The drill bit body defines an internal volume including the multiple openings defined on the outer surface of the drill bit body. In the retracted state, the multiple expandable blades reside within the internal volume of the drill bit body. The first ball seat and the second ball seat are installed within the internal volume of the drill bit body.

[0038] An aspect combinable with any other aspect includes the following features. The ball activation mechanism includes a first piston positioned within the internal volume of the drill bit body. The first piston defines the first ball seat. The first piston can move axially within the internal volume of the drill bit body in response to axial pressure.

[0039] An aspect combinable with any other aspect includes the following features. The first piston defines an internal volume. The first piston includes axial walls defining through openings. In an absence of the first ball in the first ball seat, the first piston can permit wellbore fluid to flow along the longitudinal axis past the first piston. In a presence of the first ball in the first ball seat, the first piston can divert the wellbore fluid to flow through the internal volume of the first piston and through openings in the axial walls instead of past the first piston.

[0040] An aspect combinable with any other aspect includes the following features.. The ball activation mechanism includes a second piston positioned within the internal volume of the drill bit body. The second piston defines the second ball seat. The second piston contacts the first piston. The second piston can move axially within the internal volume in response to axial pressure and to responsively axially move the first piston.

[0041] An aspect combinable with any other aspect includes the following features. The ball activation mechanism includes multiple pads positioned within the internal volume defined by the drill bit body. The multiple pads are connected to the multiple expandable blades. The second piston contacts the multiple pads. The multiple pads and the multiple expandable blades are arranged such that an axial movement of the multiple pads within the internal volume defined by the drill bit body causes a radial movement of the multiple expandable blades between the retracted state and the open state.

[0042] An aspect combinable with any other aspect includes the following features. In an absence of the second ball in the second ball seat, the second piston can permit wellbore fluid to flow along the longitudinal axis past the second piston. In a presence of the second ball in the second ball seat, the second piston can prevent the wellbore fluid to flow past the second piston. The second piston can move the multiple pads along the longitudinal axis in response to the wellbore fluid being prevented from flowing past the second piston.

[0043] An aspect combinable with any other aspect includes the following features. The first ball seat is smaller than the second ball seat.

[0044] An aspect combinable with any other aspect includes the following features. The first ball is smaller than the second ball.

[0045] An aspect combinable with any other aspect includes the following features. The multiple stationary blades are attached to a first axial end of the drill bit body. The drill bit body includes a second axial end that can receive the multiple balls.

[0046] An aspect combinable with any other aspect includes the following features. The assembly includes a wellbore conveyance fluidically coupled to the second axial end. The wellbore conveyance can flow wellbore fluid through the second axial end. The multiple balls are flowed into the internal volume of the drill bit body with the wellbore fluid through the wellbore conveyance.

[0047] Certain aspects of the subject matter described here can be implemented as a wellbore drill bit. The drill bit includes a drill bit body having a longitudinal axis and defining an internal volume. The drill bit includes multiple stationary blades attached to the drill bit body and stationary with respect to the drill bit body. The multiple stationary blades can drill through a subterranean formation to form a wellbore. The multiple stationary blades are spaced apart on an outer surface of the drill bit body to define multiple openings. Each opening is defined between two consecutively spaced apart stationary blades. The drill bit includes multiple expandable blades positioned in the respective multiple spaces. Each expandable blade can drill through the subterranean formation to form the wellbore. Each expandable blade can transition between a retracted state and an open state. In the retracted state, each expandable blade is radially nearer to the longitudinal axis compared to each stationary blade. In the open state, each expandable blade extends radially away from the longitudinal axis to be radially farther away from the longitudinal axis compared to each stationary blade. The drill bit includes a ball activation mechanism that includes a first piston and a second piston. The first piston is positioned within the internal volume defined by the drill bit body. The first piston defines a ball seat. The second piston is positioned within the internal volume defined by the drill bit body. The second piston is axially offset from the first piston. The second piston defines a second ball seat. In response to receiving a first ball and a second ball in the first ball seat and the second ball seat, respectively, the first piston and the second piston can axially move causing the multiple expandable blades to radially move between the retracted state and the open state.

[0048] An aspect combinable with any other aspect includes the following features. The drill bit includes multiple pads positioned within the internal volume defined by the drill bit body. The multiple pads are connected to the multiple expandable blades. The multiple pads can move axially within the internal volume defined by the drill bit body.

[0049] An aspect combinable with any other aspect includes the following features. The multiple pads are connected to the second piston. The multiple pads can move axially in response to axial movement of the second piston.

[0050] An aspect combinable with any other aspect includes the following features. The multiple pads are in contact with the multiple expandable blades. The multiple expandable blades can radially move in response to axial movement of the multiple pads.

[0051] Certain aspects of the subject matter described here can be implemented as a method performed while drilling a wellbore through a subterranean formation using a wellbore drill bit. The wellbore drill bit defines an internal volume and includes multiple stationary blades. With a wellbore fluid, a first ball is flowed into the internal volume defined by the wellbore drill bit. A first ball seat formed in a first positioned within the internal volume defined by the wellbore drill bit receives the first ball. The first ball prevents flow of wellbore fluid past the first piston. In response to preventing the flow of wellbore fluid past the first piston, the first piston redirects the wellbore fluids towards multiple pads positioned within the internal volume defined by the wellbore drill bit. The multiple pads move in an axial direction in response to the redirected flow of the wellbore fluid. The multiple pads contact multiple expandable blades positioned within the internal volume defined by the wellbore drill bit. In response to movement of the multiple pads in the axial direction, the multiple pads move the multiple expandable blades in a radially outward direction out of the internal volume defined by the wellbore drill bit. The multiple expandable pads extend past the multiple stationary blades of the wellbore drill bit. The multiple expandable blades enlarge the wellbore by rotating within the wellbore.

[0052] An aspect combinable with any other aspect includes the following features. With the wellbore fluid, a second ball is flowed into the internal volume defined by the wellbore drill bit. A second ball seat formed in a second piston positioned within the internal volume defined by the wellbore drill bit receives the second ball. The second ball prevents flow of the wellbore fluid past the second piston. The multiple pads are connected to the second piston. In response to preventing the flow of the wellbore fluid past the second piston, the second piston moves in an axial direction towards the first piston. In response to the second piston moving in the axial direction towards the first piston, the expandable blades move in a radially inward direction into the internal volume defined by the wellbore drill bit.

[0053] An aspect combinable with any other aspect includes the following features. The first piston is downstream of the second piston.

[0054] An aspect combinable with any other aspect includes the following features. The first ball seat is smaller than the second ball seat.

[0055] An aspect combinable with any other aspect includes the following features. The first ball is smaller than the second ball.

[0056] Thus, particular implementations of the subject matter have been described. Other implementations are within the scope of the following claims.

Examples

examples

[0036] Certain aspects of the subject matter described here can be implemented as a wellbore drilling assembly. The assembly includes a wellbore drill bit that has a drill bit body, multiple stationary blades, multiple expandable blades and a ball activation mechanism. The multiple stationary blades are attached and stationary with respect to the drill bit body. The multiple stationary blades can drill through a subterranean formation to form a wellbore. The multiple stationary blades are spaced apart on an outer surface of the drill bit body to define multiple openings. Each opening is defined between two consecutively spaced apart stationary blades. The multiple expandable blades are positioned in the respective multiple openings. Each expandable blade can drill through the subterranean formation to form the wellbore. Each expandable blade can transition between a retracted state and an open state. In the retracted state, each expandable blade is radially nearer to the longitudina...

Claims

1. A wellbore drilling assembly comprising: a wellbore drill bit comprising: a drill bit body having a longitudinal axis,a plurality of stationary blades attached to the drill bit body and stationary with respect to the drill bit body, the plurality of stationary blades configured to drill through a subterranean formation to form a wellbore, the plurality of stationary blades spaced apart on an outer surface of the drill bit body to define a plurality of openings, each opening defined between two consecutively spaced apart stationary blades,a plurality of expandable blades positioned in the respective plurality of openings, each expandable blade configured to drill through the subterranean formation to form the wellbore, each expandable blade configured to transition between a retracted state, in which each expandable blade is radially nearer to the longitudinal axis compared to each stationary blade, and an open state, in which each expandable blade extends radially away from the longitudinal axis to be radially farther away from the longitudinal axis compared to each stationary blade, anda ball activation mechanism comprising a plurality of ball seats axially offset from each other along the longitudinal axis, a first ball seat of the plurality of ball seats configured to receive a first ball to transition the plurality of expandable blades from the retracted state to the open state, a second ball seat of the plurality of ball seats configured to receive a second ball to transition the plurality of expandable blades from the open state to the retracted state; anda plurality of balls comprising the first ball and the second ball.

2. The assembly of claim 1, wherein the drill bit body defines an internal volume including the plurality of openings defined on the outer surface of the drill bit body, wherein, in the retracted state, the plurality of expandable blades reside within the internal volume of the drill bit body, wherein the first ball seat and the second ball seat are installed within the internal volume of the drill bit body.

3. The assembly of claim 2, wherein the ball activation mechanism comprises a first piston positioned within the internal volume of the drill bit body, the first piston defining the first ball seat, the first piston configured to move axially within the internal volume of the drill bit body in response to axial pressure.

4. The assembly of claim 3, wherein the first piston defines an internal volume, wherein the first piston comprises axial walls defining through openings, wherein, in an absence of the first ball in the first ball seat, the first piston is configured to permit wellbore fluid to flow along the longitudinal axis past the first piston, and in a presence of the first ball in the first ball seat, the first piston is configured to divert the wellbore fluid to flow through the internal volume of the first piston and through openings in the axial walls instead of past the first piston.

5. The assembly of claim 4, wherein the ball activation mechanism comprises a second piston positioned within the internal volume of the drill bit body, the second piston defining the second ball seat, the second piston contacting the first piston, the second piston configured to move axially within the internal volume in response to axial pressure and to responsively axially move the first piston.

6. The assembly of claim 5, wherein the ball activation mechanism comprises a plurality of pads positioned within the internal volume defined by the drill bit body, the plurality of pads connected to the plurality of expandable blades, the second piston contacting the plurality of pads, the plurality of pads and the plurality of expandable blades arranged such that an axial movement of the plurality of pads within the internal volume defined by the drill bit body causes a radial movement of the plurality of expandable blades between the retracted state and the open state.

7. The assembly of claim 6, wherein, in an absence of the second ball in the second ball seat, the second piston is configured to permit wellbore fluid to flow along the longitudinal axis past the second piston, and in a presence of the second ball in the second ball seat, the second piston is configured to prevent the wellbore fluid to flow past the second piston, wherein the second piston is configured to move the plurality of pads along the longitudinal axis in response to the wellbore fluid being prevented from flowing past the second piston.

8. The assembly of claim 1, wherein the first ball seat is smaller than the second ball seat.

9. The assembly of claim 8, wherein the first ball is smaller than the second ball.

10. The assembly of claim 2, wherein the plurality of stationary blades is attached to a first axial end of the drill bit body, wherein the drill bit body comprises a second axial end configured to receive the plurality of balls.

11. The assembly of claim 1, further comprising a wellbore conveyance fluidically coupled to the second axial end, the wellbore conveyance configured to flow wellbore fluid through the second axial end, wherein the plurality of balls are flowed into the internal volume of the drill bit body with the wellbore fluid through the wellbore conveyance.

12. A wellbore drill bit comprising: a drill bit body having a longitudinal axis and defining an internal volume;a plurality of stationary blades attached to the drill bit body and stationary with respect to the drill bit body, the plurality of stationary blades configured to drill through a subterranean formation to form a wellbore, the plurality of stationary blades spaced apart on an outer surface of the drill bit body to define a plurality of openings, each opening defined between two consecutively spaced apart stationary blades;a plurality of expandable blades positioned in the respective plurality of openings, each expandable blade configured to drill through the subterranean formation to form the wellbore, each expandable blade configured to transition between a retracted state, in which each expandable blade is radially nearer to the longitudinal axis compared to each stationary blade, and an open state, in which each expandable blade extends radially away from the longitudinal axis to be radially farther away from the longitudinal axis compared to each stationary blade; anda ball activation mechanism comprising: a first piston positioned within the internal volume defined by the drill bit body, the first piston defining a first ball seat, anda second piston positioned within the internal volume defined by the drill bit body, the second piston axially offset from the first piston, the second piston defining a second ball seat, wherein, in response to receiving a first ball and a second ball in the first ball seat and the second ball seat, respectively, the first piston and the second piston are configured to axially move causing the plurality of expandable blades to radially move between the retracted state and the open state.

13. The wellbore drill bit of claim 12, further comprising a plurality of pads positioned within the internal volume defined by the drill bit body, the plurality of pads connected to the plurality of expandable blades, the plurality of pads configured to move axially within the internal volume defined by the drill bit body.

14. The wellbore drill bit of claim 13, wherein the plurality of pads are connected to the second piston, wherein the plurality of pads are configured to move axially in response to axial movement of the second piston.

15. The wellbore drill bit of claim 13, wherein the plurality of pads are in contact with the plurality of expandable blades, wherein the plurality of expandable blades are configured to radially move in response to axial movement of the plurality of pads.

16. A method comprising: while drilling a wellbore through a subterranean formation using a wellbore drill bit defining an internal volume, the wellbore drill bit including a plurality of stationary blades: flowing, with a wellbore fluid, a first ball into the internal volume defined by the wellbore drill bit;receiving, by a first ball seat formed in a first piston positioned within the internal volume defined by the wellbore drill bit, the first ball to prevent flow of wellbore fluid past the first piston;in response to preventing the flow of wellbore fluid past the first piston, redirecting, by the first piston, the wellbore fluid towards a plurality of pads positioned within the internal volume defined by the wellbore drill bit;moving, by the plurality of pads, in an axial direction in response to the redirected flow of the wellbore fluid, wherein the plurality of pads contact a plurality of expandable blades positioned within the internal volume defined by the wellbore drill bit; in response to moving, by the plurality of pads, in the axial direction, moving, by the plurality of expandable blades, in a radially outward direction out of the internal volume defined by the wellbore drill bit, by the plurality of pads, in the axial direction, wherein the plurality of expandable pads extend past the plurality of stationary blades of the wellbore drill bit; andenlarging, by the plurality of expandable blades, the wellbore by rotating within the wellbore.

17. The method of claim 16, further comprising, after enlarging the wellbore: flowing, with the wellbore fluid, a second ball into the internal volume defined by the wellbore drill bit;receiving, by a second ball seat formed in a second piston positioned within the internal volume defined by the wellbore drill bit, the second ball to prevent flow of the wellbore fluid past the second piston, wherein the plurality of pads are connected to the second piston;in response to preventing the flow of the wellbore fluid past the second piston, moving, by the second piston, in an axial direction towards the first piston; andin response to the second piston moving in the axial direction towards the first piston, moving, by the expandable blades, in a radially inward direction into the internal volume defined by the wellbore drill bit.

18. The method of claim 17, wherein the first piston is downstream of the second piston.

19. The method of claim 17, wherein the first ball seat is smaller than the second ball seat.

20. The method of claim 17, wherein the first ball is smaller than the second ball.

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