• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
  • 同族专利
  • 引用文献
  • 法律状态
  • 优先权
    • 专利摘要:
    GROUND DRILLING TOOLS INCLUDING RETRACTABLE INSERTS, CARTRIDGES INCLUDING RETRACTABLE INSERTS FOR SUCH TOOLS AND RELATED METHODS A drilling tool can comprise at least one cavity formed on its faces. At least one retractable insert resident in at least one cavity can be coupled to a piston located at least partially within at least one cavity. In addition, a valve can be positioned inside the onshore drilling tool and configured to regulate the flow of incompressible fluid in contact with the piston through an opening in a reservoir. A cartridge may comprise a cylinder wall defining a first hole, and a piston comprising at least one retractable insert positioned at least partially within the first hole. The cylinder wall and the piston can define a first reservoir within the first hole, and a valve can be positioned and configured to regulate flow through an opening to the first reservoir. Related methods and devices are also disclosed.
    公开号:BR112013032031B1
    申请号:R112013032031-1
    申请日:2012-06-14
    公开日:2020-12-01
    发明作者:Marcus Oesterberg
    申请人:Baker Hughes Incorporated；
    IPC主号:
    专利说明:

    [0001] [0001] This application claims the benefit of patent application serial number 13 / 160,015, filed on June 14, 2011, pending, entitled "TERRESTRIAL DRILLING TOOLS INCLUDING RETRACTABLE PILLS, CARTRIDGES INCLUDING RETRACTABLE PILLS FOR SUCH TOOLS AND TOOLS". . TECHNICAL FIELD
    [0002] [0002] The modalities of this disclosure generally refer to drilling tools including retractable inserts. The modalities additionally refer to components for such drilling tools, such as cartridges including shrink inserts, and related methods. BACKGROUND OF THE INVENTION
    [0003] [0003] The trend in the United States and other territories of unconventional oil and gas exploration tends towards a horizontal development of oil and gas wells, where a well is drilled into and then laterally, a formation of hydrocarbon production. Such horizontal development of oil and gas wells typically requires directional drilling, in which a hole segment of the vertical well is drilled, followed by a segment of the curved well hole which in turn transitions to another well or horizontal hole segment extending laterally to follow the formation. Typically, the curved segment of the borehole is drilled with a drill having relatively low aggressiveness, in order to provide stability and control of the tool face. When forming the well hole segment, lateral or horizontal, the operator may want to optimize the penetration rate (ROP). To optimize the total ROP using conventional drills, the operator can use a round trip, dragging the drill out with relatively low aggressiveness and dragging on another drill with relatively high aggressiveness. Such a round trip can be time-consuming and expensive due to the wasted platform time and the need to use two different drills.
    [0004] [0004] In view of the above, onshore drilling tools, improved drilling tool components, and improved drilling methods would be desirable. BRIEF SUMMARY
    [0005] [0005] In some embodiments, a land-based drilling tool may comprise at least one cavity formed on one of its faces. A retractable insert can be positioned in at least one cavity adjacent to the face and coupled to a piston located at least partially within at least one cavity. In addition, a substantially incompressible fluid may be in contact with the piston and contained within a first reservoir, and a valve may be positioned within the onshore drilling tool and configured to regulate flow through an opening in the first reservoir.
    [0006] [0006] In additional embodiments, a cartridge for a terrestrial drilling tool may comprise a cylinder wall defining a first hole and a piston comprising at least one retractable insert positioned at least partially within the first hole. In addition, the cartridge may comprise a first reservoir within the first bore adjacent to the piston, an opening for the first reservoir, and a valve positioned and configured to regulate the flow of fluid through the opening.
    [0007] [0007] In other embodiments, a drill bit for onshore drilling may comprise a plurality of cavities on one of its faces, and a retractable insert coupled to a first piston located at least partially within each cavity of the plurality. The drill bit for land drilling can additionally comprise a substantially incompressible fluid in contact with the piston and contained within a first reservoir, and a plurality of holes in fluid communication with the plurality of cavities and in contact with the fluid substantially incompressible. In addition, a second piston can be located at least partially within each hole of a plurality of holes; and an oscillating plate can be operationally coupled to each second piston.
    [0008] [0008] Still in additional modalities, a method of operating a land drilling tool may comprise drilling a well hole with a land drilling tool with at least one retractable insert protruding from a face of the land drilling tool adjacent to, at least a sharp structure. The method may further comprise opening a valve within the onshore drilling tool to release a fluid from a first reservoir positioned below at least one retractable insert and reducing the amount of protrusion of at least one retractable insert from the face of the tool onshore drilling while inside the borehole, and restart drilling after reducing the amount of protrusion from at least one retractable insert from the face of the onshore drilling tool.
    [0009] [0009] In still other embodiments, a method of forming a curved well hole may comprise extending at least one retractable insert positioned within a face of a drill bit on a first side of a well hole during drilling, and retracting the at least retractable insert on a second side of the well bore during drilling. BRIEF DESCRIPTION OF THE VARIOUS VIEWS OF THE DRAWINGS
    [0010] [0010] FIG. 1 shows a schematic view of a drilling rig including a drill bit according to an embodiment of the present disclosure.
    [0011] [0011] FIG. 2 shows an isometric view of a drill bit including retractable inserts according to an embodiment of the present disclosure.
    [0012] [0012] FIG. 3 shows a view of the bottom of the drill bit shown in FIG. two.
    [0013] [0013] FIG. 4A shows a schematic view of a portion of the drill bit of FIG. 2, showing the fluid channels through a drill bit body and showing the retractable inserts in an extended position.
    [0014] [0014] FIG. 4B shows a schematic view of the drill bit portion shown in FIG. 4A, with the retractable inserts in a stowed position.
    [0015] [0015] FIG. 5A shows a cartridge assembly including a retractable insert for use in a drill bit, as shown in FIG. 2, the retractable tablet shown in an extended position.
    [0016] [0016] FIG. 5B shows the assembly of the cartridge of FIG. 5A with the retractable insert shown in a stowed position.
    [0017] [0017] FIG. 6A shows a cartridge assembly including a retractable insert and a second piston for use in a drill bit, as shown in FIG. 2, the retractable tablet shown in an extended position.
    [0018] [0018] FIG. 6B shows the assembly of the cartridge of FIG. 6A with the retractable insert shown in a stowed position.
    [0019] [0019] FIG. 7A shows a cartridge assembly including a retractable insert and a diaphragm for use in a drill bit, as shown in FIG. 2, the retractable tablet shown in an extended position.
    [0020] [0020] FIG. 7B shows the assembly of the cartridge of FIG. 7A with the retractable insert shown in a stowed position.
    [0021] [0021] FIG. 8 shows an exploded view of a drill bit and electronics module of the drill bit of FIG. two.
    [0022] [0022] FIG. 9 shows a cross-sectional view of the rod of FIG. 8.
    [0023] [0023] FIG. 10 shows a perspective view of the electronics module of FIG. 8.
    [0024] [0024] FIG. 11 shows a schematic diagram of the electronics module of FIG. 8.
    [0025] [0025] FIG. 12 shows a partial cross-sectional view of a drill bit including an oscillating plate according to an embodiment of the present disclosure.
    [0026] [0026] FIG. 13 shows a partial cross-sectional view of a drill bit including a valve according to an embodiment of the present disclosure. DETAILED DESCRIPTION
    [0027] [0027] The illustrations presented here are not intended to be actual views of any particular device or related method, but are merely idealized representations, which are used to describe modalities of the present invention. In addition, elements common to the figures may retain the same numerical designation.
    [0028] [0028] Although some modalities of the present disclosure are described as being used and employed in drag drills, people of ordinary skill in the art will understand that the modalities of this disclosure can be used in hybrid drill bits or other drill bit configurations. drilling. Consequently, the term "onshore drilling tool" and, as used here, means and includes any type of drill bit or other onshore drilling rig for use in drilling or enlarging well holes or wells in onshore formations.
    [0029] [0029] FIG. 1 shows an example of an apparatus for performing underground drilling operations. The drilling rig 10 may include a drilling tower 12, tower floor 14, a drill rig 16, a hook 18, a swivel 20, Kelly junction (square or hexagonal shank) 22, and a rotating table 24. One drilling column 30, which may include a section of the drill pipe 32 and a section of the drill collar 34, extends downward from the drilling platform 10 into a hole in the well 40. The section of the drill pipe 32 can include a number of members of tubular drill tubes or filaments connected together and the drill collar section 34 can also include a plurality of drill collars. Optionally, the drilling column 30 can include a subset of the measurement log during drilling (MWD) and a subset of auxiliary mud pulse telemetry data transmission, which are collectively referred to as a MWD 50 communication system, as well as other communication systems known to those of ordinary skill in the art.
    [0030] [0030] During drilling operations, the drilling fluid can be circulated from a mud tank 60 through a mud pump 62, through a damper 64, and through a mud supply line 66 in the swirl 20. The drilling mud (also referred to as the drilling fluid) flows through the Kelly junction (square or hexagonal shank) 22 and into an axial central hole in the drill bit 30. Eventually, it comes out through the nozzles or other openings, which are located on a drill bit 100, which is connected to the lowest portion of the drill string 30. The drill mud flows back up through an annular space 42 between the outer surface of the drill string 30 and the inner surface of the well bore 40, to be circulated to the surface where it is returned to the mud tank 60 through a mud return line 68.
    [0031] [0031] An agitator filter (not shown) can be used to separate formation gravels from the drilling mud before returning to the mud tank 60. The optional MWD communication system 50 can use a pulse telemetry technique mud to communicate data from a bottom location to the surface while drilling operations take place. To receive the data on the surface, a mud pulse transducer 70 is provided in communication with the mud supply line 66. This mud pulse transducer 70 generates electrical signals in response to pressure variations in the drilling fluid in the drilling line. sludge feed 66. These electrical signals are transmitted by a surface conductor 72 to an electronic surface processing system 80, which is conventionally a data processing system with a central processing unit to execute program instructions, and to respond to user commands entered either via a keyboard or a graphic pointing device. The mud pulse telemetry system is provided for communication data for the surface referring to the various conditions of the bottom of the well detected by the well log and measurement systems that are conventionally located within the MWD 50 communication system. Mud pulses that define the data propagated to the surface are produced by equipment conventionally located within the MWD 50 communication system. Such equipment typically includes a pressure pulse generator operating under the control of electronics contained in an instrument housing to allow the mud drill through a hole extending through the wall of the drill collar. Each time the pressure pulse generator induces such a purge, a negative pressure pulse is transmitted to be received by the mud pulse transducer 70. A conventional alternative arrangement generates and transmits positive pressure pulses. As is conventional, the circulating drilling mud can also provide a power source for a subset of the turbine drive generator (not shown) which can be located near a bottom well assembly (BHA). The turbine drive generator can generate electrical energy for the pressure pulse generator and for various circuits including those circuits that form the operational components of the measurement tools during drilling. As an alternative or supplementary source of electricity, batteries can be provided, particularly as a support for the turbine drive generator.
    [0032] [0032] For directional drilling, drilling column 30 may include a mud motor 90 and a folded substitute and / or a steering substitute 92 in a location close to drill bit 100. When drilling a segment of the straight well hole , the steering substitute 92 and the drill bit 100 can both be rotated in relation to the well hole 40. In view of this, the drill bit 100 can be rotated out of the center and can drill a slightly over-dimensioned hole due to the steering substitute 92 by rotating and rubbing along the well hole wall. Optionally, a steering insert in the steering substitute 92 can be moved to a stowed position, which can allow the drill bit 100 to be rotated in the center, while drilling a segment of the well hole in a straight line.
    [0033] [0033] When drilling a curved borehole segment, the mud motor 90 can be used to rotate the drill bit 100 relative to the well hole 40, while the drill column 30 located above the mud motor 90 , cannot rotate in relation to the borehole 40. In view of this, the drill bit 100 can be rotated in the center and the steering substitute 92 cannot rotate in relation to the borehole 40 and can consistently apply a lateral force on one side of the well hole 40, which can induce the drill bit 100 to follow a curved path through the formation. If steering substitute 92 includes a movable steering insert, the steering insert may be positioned in an extended position, forming the curved segment of the well hole.
    [0034] [0034] However, in some embodiments, a folded substitute and / or direction substitute 92 cannot be included for directional drilling. In such embodiments, the formation of a curved well hole segment can be facilitated using the devices and methods according to the present disclosure without using a folded substitute and / or a direction substitute 92, as discussed herein with reference to Figs. . 12 and 13.
    [0035] [0035] As shown in FIG. 2, the drill bit 100 may comprise a drill body 110 and a shank 112. The drill body 110 may include a number of blades 114 and the fluid channels 116 located between blades 114 defining an outer surface of the drill body 110. The drill body 110 can additionally include a plurality of nozzles 118 (FIG. 3), which can be located in the drill body 110 to direct fluid through fluid channels 116. Blades 114 can include a plurality of cutting structures 122 (for example, compact polycrystalline diamond cutters (PDC)), such as in a crown or face region of drill bit 100 and blades 114 may include wear inhibiting structures 124 (for example, example, tungsten carbide wear buttons), such as in a 100 drill bit gauge region.
    [0036] [0036] As shown in FIGS. 2 and 3, the drill body 110 of the drill bit 100 may include a plurality of retractable inserts 128 located on the face of the drill. The face of the drill is shown in FIG. 3, and it is the main region of the drill bit 100 that engages the bottom part of a well hole during drilling operations (i.e., the portion of the bit that is opposite the shank 112). For example, each retractable insert 128 can be located on a blade 114 of the drill body 110 in a rotationally position by dragging a row of cutting structures 122. In other embodiments, each retractable insert 128 can rotationally drive a row of cutting structures 122 .
    [0037] [0037] As shown in FIGS. 4A and 4B, the drill body 110 can additionally include the fluid channels 130 within the drill body 110, which can extend from a central fluid channel 132 and into nozzles 118 and cavities 136 of the drill body 110 containing the retractable inserts 128. The central fluid channel 132 can extend outwardly from the drill bit 100 through an opening in the stem 112 (FIG. 8).
    [0038] [0038] In some embodiments, each adjustable insert 128 can be included in a cartridge assembly 140, 180, 200, as shown in FIGS. 5A, 5B, 6A, 6B, 7A and 7B, which can be positioned inside the cavity 136 in the blade 114 of the drill body 110.
    [0039] [0039] As shown in FIGS. 5A and 5B, a cartridge assembly 140 may include a cylinder wall 142 defining a hole, a piston 144 positioned within the hole, a perimeter of piston 144 sealed against the cylinder wall 142. Piston 144 may include a conveyor 146, such as a steel conveyor, which can include a seal ring equipped with seals 148 to prevent fluid from passing between the sealed perimeter of piston 144 and cylinder wall 142, and can also be equipped with a bearing ring or wear . Piston 144 also includes retractable insert 128, which may be coupled to, or integrally formed with conveyor 146. For example, retractable insert 128 may be comprised of carbide, or other wear-resistant material, and may be amended or welded to conveyor 146. After insertion into the bore, a surface 150 of piston 144 and cylinder wall 142 can define a fluid reservoir 152. Cartridge 140 can further include an opening 154 for fluid reservoir 152 and a valve 156 (such as a piezoelectric valve) located and configured to control the passage of fluid through the opening 154 to the fluid reservoir 152. As the reservoir 152 is defined by the cylinder wall 142 and the surface 150 of the piston 144, the reservoir 152 may vary in size, depending on the position of piston 144 within the well bore. A substantially incompressible fluid can substantially fill reservoir 152 by contacting the surface 150 of piston 144. In view of this, after closing opening 154 by valve 156, the incompressible fluid can be contained within reservoir 152 and piston 144 can be held in position by means of hydraulic pressure. Non-limiting examples of substantially incompressible liquids that can be used include mineral oil, vegetable oil, silicone oil and water.
    [0040] [0040] The cartridge assembly 140 can be dimensioned for insertion in the cavity 136 of the drill body 110 (Figs. 4A and 4B), and can include a flange 160 that can be used to position the cartridge assembly 140 at a predetermined depth inside the cavity 136 and can also be used to join the cartridge assembly 140 to the drill body 110. For example, the flange 160 can be welded to the face of the drill bit 100 (FIG. 2), which can maintain the cartridge assembly 140 within the drill body 110 and can also provide a fluid impermeable seal between the cartridge assembly 140 and the drill body 110. In addition, wiring 162 can be provided and routed through the drill body 110 to provide electrical communication between valve 156 and an electronics module 310 (described in more detail here with reference to FIG. 8-11).
    [0041] [0041] In another embodiment, shown in FIGS. 6A and 6B, a cartridge assembly 180 may include a first cylinder wall 182 defining a first hole and a first piston 184 positioned within the hole, a perimeter of the first piston 184 sealed against the first cylinder wall 182. In addition, the cartridge assembly 180 may include a second piston 186, and a valve 187 positioned between the first and second pistons 184 and 186, respectively, and configured to regulate the flow between a first reservoir 189 and a second reservoir 191.
    [0042] [0042] Similar to piston 144 of the cartridge assembly 140, shown in FIGS. 5A and 5B, the first piston 184 of the cartridge assembly 180 may include a conveyor 188, such as a steel conveyor, which may include a seal ring equipped with seals 190 to prevent fluid from passing between the perimeter of the first piston 184 and the first cylinder wall 182, and can also be equipped with a bearing or wear ring. The first piston 184 can also include a retractable insert 192, which can be coupled to, or formed integrally with, the conveyor 188.
    [0043] [0043] The second piston 186 can be positioned inside a second hole defined by a second wall of the cylinder 194, a perimeter of the second piston 186 sealed against the second wall of the cylinder 194. The second piston 186 can also include a seal 196, such as one or more of a round ring, a square ring, a square ring, a cam, a support ring, and another conditioner, which can provide a seal between the second piston 186 and the second wall of the cylinder 194.
    [0044] [0044] Although in the embodiment shown in FIGS. 6A and 6B show the surfaces of the first and second pistons 184 and 186, respectively, exposed to incompressible fluid and drilling fluid having similar sizes. The surface areas of the opposing surfaces of the second piston 186 can be sized differently, such as to provide a pressure multiplier to increase the pressure of the incompressible fluid relative to the pressure applied by the drilling fluid. In addition, the surface areas and the size of the first piston 184 may be different from the surface areas and the size of the second piston 186.
    [0045] [0045] In still other embodiments, a cartridge assembly 200 may include a flexible diaphragm 202 to provide an expandable fluid reservoir 204, as shown in FIGS. 7A and 7B. For example, an elastomeric member can be positioned along one end of the cartridge assembly 200 and provide a fluid barrier, but still allows the fluid pressure to be communicated from the drilling fluid within the drill body 110 ( FIG. 2) through a valve 206 to a first reservoir 208 behind a piston 210, including a retractable insert 212.
    [0046] [0046] As shown schematically in FIGs. 4A and 4B, the fluid channels 130 of the drill body 110 can connect the central fluid channel 132 of the drill bit 100 (FIG. 2) to the cavity 136 containing the retractable insert 128. In view of this, the fluid channels 130 can provide a fluid communication between the central fluid channel 132 of the drill bit 100 to a cartridge 140, 180, 200, as described with reference to FIGS. 5A, 5B, 6A, 6B, 7A and 7B, positioned inside cavity 136. A valve can selectively allow fluid communication between the central fluid channel 132 and the retractable pad 128. For example, a valve such as valve 156 , 187, 206 described with reference to cartridges 140, 180, 200 can be used to selectively allow fluid communication between the central fluid channel 132 and the retractable pad 128, 192, 212. Valve 156, 187, 206 can be electrically driven (for example, a piezoelectric valve) and can in electrical communication with and operated by an electronics module 310 that can be located on the stem 112 of the drill bit 100, as described in US Patent Applications Numbers US 12 / 367,433 and 12 / 901,172 and US Patent Numbers US 7,497,276; 7,506,695; 7,510,026; 7,604,072; and 7,849,934, each for Pastusek et al., each entitled "METHOD AND APPLIANCE FOR COLLECTING DRILLING DRILL PERFORMANCE DATA", and each given to the assignee of this application, the disclosure of which is incorporated herein by reference in its entirety.
    [0047] [0047] As shown in FIG. 8, shank 112 includes a central hole 300 formed through the longitudinal axis Z of shank 112. In conventional drill bits, a central hole is configured to allow the drilling mud to flow through it. In this embodiment, at least a part of the central hole 300 of the stem 112 is given a sufficient diameter to accept an electronics module 310, which can be configured as a substantially annular ring. Thus, the electronics module 310 can be placed inside the central hole 300, on the end cap 312, which extends through the inner diameter of the annular ring of the electronics module 310 to create an annular chamber impermeable to the fluid with the wall from the central hole 300 and seal the electronics module 310 in place inside the rod 112.
    [0048] [0048] The end cap 312 includes a hole in the cap 314 formed through it, so that the drilling mud can flow through the end cap 312, through the central hole 300 of the stem 112 to the other side of the stem 112 and then in the central fluid channel 132 of the drill bit 100. FIG. 9 shows a cross-sectional view of the end cap 312 arranged on the stem 112 without the electronics module 310, illustrating an annular chamber 320 formed between the end cap 312 and the walls of the central hole 300 of the stem 112. A first ring of seal 322 and a second seal ring 324 form a fluid impermeable protective seal on end cap 312 and the center hole wall 300 to protect electronics module 310 (FIG. 8) from adverse environmental conditions. The protective seal formed by the first seal ring 322 and the second seal ring 324 can also be configured to keep the annular chamber 320 at approximately atmospheric pressure.
    [0049] [0049] In some embodiments, the first seal ring 322 and the second seal ring 324 can be formed of a material suitable for a high temperature environment, at high pressure, such as, for example, a round ring of Hydrogenated Rubber Butadiene Nitrile (HNBR) in combination with a PEEK support ring. In addition, end cap 312 can be attached to stem 112 by a number of connection mechanisms, such as, for example, a secure pressure fitting using seal rings 322 and 324, a threaded connection, an epoxy connection , a configured memory server, a weld, and a splice.
    [0050] [0050] The electronics module 310, can be configured as a flexible circuit board, shown in the flat configuration in FIG. 10. The configuration of the flexible circuit board can facilitate the folding and shaping of the electronics module 310 into a ring in a generally annular shape, as shown in FIG. 8, suitable for arrangement around end cap 312 and in central hole 300. The flexible circuit board may include a reinforced, high-strength structure (not shown) to facilitate the reliable transmission of accelerating forces to sensors in the control module. such as accelerometers. In addition, other areas of the flexible circuit board, which can carry electronic components without sensors, can be connected to the end cap 312 in a suitable way to at least partially attenuate the acceleration forces resulting from drilling operations through the use of a material such as a viscoelastic adhesive.
    [0051] [0051] In addition to operating valves 156, 187, 206 to control fluid communication between the central fluid channel 132 and retractable pads 128, 192, 212, electronics module 310 can be configured to perform a variety of data collection and / or data analysis functions.
    [0052] [0052] In some embodiments, as shown in FIG. 11, electronics module 310 may include a power supply 340 (for example, a battery), a processor 342 (for example, a microprocessor), and a memory device 344 (for example, a random access memory device (RAM) and read-only memory device (ROM)). The electronics module 310 may additionally include at least one sensor 346, 348, 350 configured to measure physical parameters related to the drill bit, which may include the condition of the drill bit, the conditions of drilling operation, and the environmental conditions close to the drill bit. In one embodiment, sensors 346, 348, 350 can include an acceleration sensor 346, a magnetic field sensor 348, and a temperature sensor 350.
    [0053] [0053] The 346 acceleration sensor can include three accelerometers configured in an orthogonal arrangement (that is, each of the accelerometers can be arranged at a right angle to each of the other accelerometers). Likewise, the magnetic field sensor 348 can include three magnetometers configured in an orthogonal arrangement (that is, each of the magnetometers can be arranged at right angles to each of the other magnetometers). Although orthogonal arrangements (for example, Cartesian coordinate system) using three sensors are described here, other numbers of sensors and arrangements can also be used.
    [0054] [0054] The communication port 352 can also be included in the electronics module 310 for communication with external devices, such as a MWD 50 communication system and a remote processing system 354. The communication port 352 can be configured to a direct communication link 356 to the remote processing system 354 using a direct wire connection or a wireless communication protocol, such as, for example only, infrared, Bluetooth®, and 802.11a / b / g protocols . Using the direct communication link 356, the electronics module 310 can be configured to communicate with a remote processing system 354, such as, for example, a computer, a portable computer and a personal digital assistant (PDA) when the drill bit is used. drilling 100 is not at the bottom of the well. Thus, the 356 direct communication link can be used for a variety of functions, such as downloading software and software updates, to allow installation of electronics module 310 by downloading configuration data, and loading data sample and analysis data. Communication hole 352 can also be used to consult electronics module 310 for information related to drill bit 100, such as drill bit number, electronics module serial number, software version, time total elapsed from drill operation, and other drill bit data over the long term, which can be stored in memory device 344.
    [0055] [0055] As valves 156, 187, 206 can be located inside the drill body 110 of the drill bit 100 and the electronics module 310 that operates the valves 156, 187, 206 can be located on the stem 112 of the drill bit 100, the control system for the retractable inserts 128, 192, 212 can be included completely within the drill bit 100.
    [0056] [0056] In certain methods of operating the drill bit 100, the retractable inserts 128, 192, 212 of the drill bit 100 may initially be positioned in an extended position, such as a fully extended position, as shown in FIGS. 5A, 6A and 7A. With the retractable inserts 128, 192, 212 positioned in an extended position, a curved segment of the well hole can be formed with the drill bit 100 using directional drilling techniques, such as for the transition of a vertical segment of the well hole for a horizontal orientation. In the extended position, the retractable inserts 128, 192, 212 can provide a cutting depth limiting feature that can provide a reduced aggressiveness of the drill bit 100 which can facilitate drilling of the well bent hole by limiting the effective exposure of structures sharps 122 adjacent to retractable inserts 128, 192, 212. In one embodiment, the retractable inserts are located substantially within the cone C region of the drill bit (Fig. 3), adjacent to a CL centerline (Fig. 3) of the drill bit 100. After the curved segment of the well hole is drilled into the formation, the retractable inserts 128, 192, 212 can then be retracted inside the body of the drill 110, increasing the depth of cut and the aggressiveness of the drill bit 100 for increasing the effective exposure of the cutting structures 122 adjacent to the retractable inserts 128, 192, 212, which increased aggressiveness can facilitate f efficient forming of a substantially straight segment of the well hole, such as a horizontal well hole segment, increasing the ROP to a given rotational speed of drill bit 100.
    [0057] [0057] To retract the retractable inserts 128, 192, 212, a signal can be provided to the electronics module 310. In some embodiments, an acceleration of the drill bit 100 can be used to provide a signal to the electronics module 310. For example, drill bit 100 can be rotated at different speeds, which can be detected by accelerometers from the 346 acceleration sensor. The predetermined rotational speed, or a predetermined series (for example, a pattern) of various rotation speeds within a certain period of time, it can be used to signal the electronics module 310 to retract the retractable inserts 128, 192, 212. To facilitate the reliable detection of accelerations correlating with the standard signal or rotational speed signal predetermined by the electronic system 310, the weight in drill (WOB) can be reduced, as for substantially zero pounds (zero Kg) WOB.
    [0058] [0058] In other embodiments, another force acting on the drill bit 100 can be used to provide a signal to the electronics module 310. For example, the drill bit 100 may include a voltage meter in communication with the drill module. 310 electronics that can detect WOB. A predetermined WOB, or a predetermined series (for example, standard) of WOB, can be used to signal electronics module 310 to retract retractable inserts 128, 192, 212. To facilitate reliable WOB detection by correlating to the predetermined WOB signal by the electronics module 310, the rotational speed of the drill bit 100 can be maintained at a constant speed of rotation (i.e., consistent revolutions per minute (RPM)). In some embodiments, the rotational speed of the drill bit 100 can be maintained at a speed of substantially zero RPM, while detecting the WOB signal.
    [0059] [0059] After electronics module 310 detects the signal to retract the retractable inserts 128, 192, 212 (for example, accelerations correlating with the signal of predetermined rotational speed or voltage measured by the voltage meter correlating with the predetermined WOB signal) , an electric current can be supplied for valves 156, 187, 206 corresponding to retractable inserts 128, 192, 212 and valves 156, 187, 206 can open, allowing fluid through it. For example, an electrical circuit can be provided between the power source 340 (for example, the battery) of the electronics module 310 and valves 156, 187, 206, like valves 156, 187, 206, may require relatively little power to function (for example, valves 156, 187, 206 can be piezoelectric valves that can be in a normally closed mode and each uses about 5 watts of power to open).
    [0060] [0060] After sending the signal or signals to retract the retractable inserts 128, 192, 212, weight can be applied to the drill bit 100 via the drill column 30, and a force can be applied to the retractable inserts 128 , 192, 212 for the underlying formation. After opening the valves 156, 187, 206, the force applied to the retractable inserts 128, 192, 212 by WOB in the unperforated formation ahead of the drill bit 100 can induce the substantially incompressible fluid into the associated reservoir 152, 189, 208 to flow out of the reservoir 152, 189, 208 through valve 156, 187, 206 and induce the retractable inserts 128, 192, 212 to be retracted from the drill body 110, as shown in FIGS. 5B, 6B, and 7B. In modalities that use an open cartridge assembly 140, the incompressible fluid can flow out of reservoir 152 and mix with the drilling fluid in the drill body 110. In modalities that use a cartridge assembly 180, 200 with a second reservoir 191 , 204, the incompressible fluid can flow out of the first reservoir 189, 208 and into the second reservoir 191, 204, causing the volume of the second reservoir 191, 204 to expand, as shown in FIGS. 6B and 7B.
    [0061] [0061] In some embodiments, the retractable inserts 128, 192, 212 can be extended into the well bore after they have been retracted. To extend the retractable inserts 128, 192, 212 into the well, another signal, such as a similar signal, or the same as, the signal to retract the retractable inserts 128, 192, 212 can be supplied to the electronics module 310. By receiving the signal, an electric current can be supplied to the valves 156, 187, 206 corresponding to the retractable inserts 128, 192, 212 and the valves 156, 187, 206 can open allowing fluid through them. Drill bit 100 can be positioned outside the bottom of the well hole and drill fluid can be pumped into the central fluid channel 132 of drill bit 100. The fluid pressure within the central fluid channel 132 of drill 100 it can then induce the fluid to flow through valves 156, 187, 206 and into associated reservoirs 152, 189, 208, inducing the volume of reservoirs 152, 189, 208 to expand and retractable inserts 128, 192, 212 to extend from the face of the drill. After the retractable inserts 128, 192, 212 have been moved to the extended position, as shown in FIGS. 5A, 6A, and 7A, valves 156, 187, 206 can be closed to maintain the expanded volume of reservoirs 152, 189, 208, keeping the retractable inserts 128, 192, 212 in the extended position, and drilling can begin.
    [0062] [0062] In embodiments that include a second reservoir 191, 204, as shown in FIGS. 6A, 6B, 7A, and 7B, pressure can be applied to the fluid in the second reservoir 191, 204, such as through the second piston 186, or through the flexible diaphragm 202, through the fluid within the central fluid channel 132 of the drill bit 100 and the fluid inside the second reservoir 191, 204 can be fluid into the first reservoir 189, 208. In embodiments without a second reservoir 191, 204, the drilling fluid can direct the incompressible fluid into the reservoir 152 (FIG. 5A). In other embodiments without a second reservoir 191, 204, the drilling fluid can be used as the incompressible fluid. In such embodiments, where the drilling fluid is used as the incompressible fluid, a filter or other filter medium (not shown) can be used to inhibit solid debris from passing through valve 156.
    [0063] [0063] In additional embodiments, a drill bit 400, 500, including retractable inserts 410, 510 can be configured to selectively retract and extend individual retractable inserts 410, 510 from the drill bit 400, 500, respectively, as shown in FIGS. 12 and 13. In these modalities, the extension and retraction of the retractable inserts 410, 510 during drilling can be used to drill a curved segment of the well hole by varying the aggressiveness of the cutting structures 122 (FIG. 2), in different locations on the face of the drill.
    [0064] [0064] In some embodiments, a drill bit 400 may include a piston 402 in fluid communication with each retractable insert 410 and each piston 402 may be coupled to an oscillating plate 420, as shown in FIG. 12. The oscillating plate 420 may comprise an upper plate 422 and a lower plate 424, which rotate relative to each other at an interface 426. The upper plate 422 cannot rotate in relation to the well hole, and the lower plate 424 it can rotate with the drill bit 400. For example, the upper plate 422 can be connected to one or more bars 430 that prevent the upper plate 422 from rotating in relation to the well hole. A plurality of pistons 402 can be coupled to the lower plate 424 by an articulated connection, such as a ball and plug connection 440, and the lower plate 424 can rotate, together with the drill bit 400 and the pistons 402, with respect to the upper plate 422. The pistons 402 may extend through the holes 450 in the drill body 452 and be in fluid communication with the retractable inserts 410.
    [0065] [0065] In operation, the upper plate 422 and the lower plate 424 can be inclined in relation to the longitudinal main axis of the drill bit 400, such as by manipulating one or more of the bars 430 connected to the upper plate 422, which can induce the pistons 402 to reciprocate inside the holes 450 in the drill body 452 under rotation of the drill bit 400. The reciprocal pistons 402 can then induce the retractable inserts 410 to move in and out relative to the face of the drill bit that the drill bit 400 rotates inside the well bore as a result of the hydraulic pressure forces generated by the reciprocal pistons 402 acting on the retractable inserts 410. The oscillating plate 420 can induce the pistons 402 to move downwards and induce the inserts retractable pads 410 extend when the retractable inserts 410 pass on a first side of the well hole and to move up and induce the retractable inserts 410 to retract as the p retractable hoppers 410 pass on a second side of the well hole. In view of this, the depth of cut for the drill bit 400 can be greater on the second side of the well hole than on the first side and the drill bit 400 can remove more material from the second side of the well hole and the directional drilling can be achieved. In addition, the direction reached (for example, the degree of deviation from a straight path) can be determined by the angle that the oscillating plate 420 is oriented in relation to the main longitudinal axis of the drill bit 400.
    [0066] [0066] In other embodiments, as shown in FIG. 13, each retractable insert 510 of a drill bit 500 may be in fluid communication with a valve 520, such as a valve similar to the valve described with reference to U.S. Patent No. 5,553,678 to Barr et al, entitled "INDUCTION UNITS MODULATED FOR DIRECTIONAL ROTARY DRILLING SYSTEMS ", whose disclosure is hereby incorporated by reference in its entirety. The valve 520 can be coupled to a bar 522 which can prevent the valve 522 from rotating relative to the well hole during drilling operations. The drill body 530 may include fluid channels 532 therein to provide fluid communication between valve 520 and shrink inserts 510. In addition, drill body 530 may include fluid channels 534 that provide fluid communication between valve 520 and a drill bit 500 exterior. As shown in FIG. 13, fluid channels 534 can provide fluid communication to the outside of drill bit 500 at a location in or near the bore region of drill bit 500. In other embodiments, fluid channels 534 can be directed to down through the drill body 530 and provide fluid communication to the outside of the drill bit 500 through the nozzles 118, located in the face region of the drill bit 500. The fluid channels 532, 534 formed through the drill body 530 will rotate with drill bit 500 during drilling operations, thus they will rotate relative to valve 520. Valve 520 can be configured with at least two different circumferential regions 540, 542. A first circumferential region 540 can provide a fluid communication between a central fluid passage 544 in the drill body 530 and the fluid passage 532 to a retractable insert 510, while blocking communication fluid flow between a corresponding fluid passage 534 between the central fluid passage 544 and the outside of drill bit 500. A second circumferential region 542 of valve 520 can provide fluid communication between a retractable insert 510 and an outer portion of the drill bit 500, preventing fluid communication between the central fluid passage 544 and one of the fluid channels 532 and 534 corresponding to the retractable insert 510.
    [0067] [0067] In operation, the central fluid passage 544 of the drill bit 500 can be pressurized with respect to a fluid around the outside of the drill bit 500. When the fluid channels 532 and 534 corresponding to a retractable insert 510 pass through the first circumferential region 540 of valve 520, the retractable insert 510 can be pressurized. During the pressurization process (for example, as the fluid channel 532 passes through the first circumferential region 540 of the valve 520), the fluid channel 532 for the retractable insert 510 can be opened for the pressurized fluid within the central passage of fluid 544 from drill bit 500 and retractable insert 510 can become extensive in response to fluid pressure. As the drill bit 500 rotates, fluid channels 532 and 534 corresponding to retractable inserts 510 pass in the second circumferential region 542 of valve 520 and a fluid communication between fluid channel 532 and fluid channel 534 is provided through valve 520, resulting in purging. During the purging process (for example, as fluid channel 532 passes through the second circumferential region 542 of valve 520), fluid communication is provided between a retractable insert 510 and the outside of drill bit 500, which can result in purging and a reduction in fluid pressure in communication with the retractable insert making it reduced and the retractable insert 510 retracting. Valve 520 can be oriented with respect to a well hole to induce the retractable inserts 510 to move into a location corresponding to a first side of the well hole and outwardly relative to a second side of the well hole as the drill bit 500 rotates into the well bore. In view of this, the depth of cut for the drill bit 500 can be greater on the second side of the well hole than on the first side, and the drill bit 500 can remove more material from the second side of the well hole and directional drilling can be achieved. In addition, the direction reached (for example, the degree of deviation from a straight path) can be determined by the position of valve 520 in relation to the well bore and the fluid pressure supplied to the central fluid passage 544 of the drill bit drilling 500.
    [0068] [0068] Although the present invention has been described herein with respect to certain modalities, those skilled in the art will recognize and understand that it is not so limited. On the contrary, many additions, deletions and changes to the modalities described herein can be made without departing from the scope of the invention as claimed below. In addition, the characteristics of one embodiment can be combined with the characteristics of another embodiment while remaining within the scope of the invention as contemplated by the inventor.
    权利要求:
    Claims (13)
    [0001]
    Cartridge for a land drilling tool, the cartridge characterized by comprising: a cylinder wall defining a first hole; a piston comprising at least one retractable insert positioned at least partially within the first bore; a first reservoir within the first hole adjacent to the piston; an opening for the first reservoir; a valve positioned and configured to regulate the flow of fluid through the opening; another cylinder wall defining a second hole and having a second reservoir in this position for fluid communication with the first reservoir through the valve, in which the valve is positioned between the first reservoir and the second reservoir.
    [0002]
    Cartridge according to claim 1, further comprising: a second piston positioned inside the second hole adjacent to the second fluid reservoir.
    [0003]
    Cartridge according to claim 1, further comprising: a diaphragm enclosing at least a portion of the second hole adjacent to the second fluid reservoir.
    [0004]
    Drill for land drilling, characterized by comprising: a plurality of cavities on one face of the land-based drill; a retractable insert coupled to a first piston located at least partially within each cavity of the plurality of cavities; a substantially incompressible fluid in contact with the first piston and contained within a first reservoir; a plurality of holes in fluid communication with the plurality of cavities and in contact with the substantially incompressible fluid; a second piston located at least partially within a second reservoir in each hole of the plurality of holes; a valve positioned between the first reservoir and the second reservoir at each hole of the plurality of holes, the valve configured to selectively flow fluid between the first reservoir and the second reservoir; and an oscillating plate operatively coupled to each second piston.
    [0005]
    Method of operating a land drilling tool, the method characterized by comprising: drilling a hole with a land drilling tool with at least one retractable insert protruding from a face of the land drilling tool adjacent to at least one cutting structure; opening a valve inside the land drilling tool to release a fluid from a first reservoir positioned under at least one retractable insert and reducing the amount of protrusion of at least one retractable insert from the face of the land drilling tool, while inside the hole; restart drilling after reducing the amount of protrusion from at least one retractable insert from the face of the land drilling tool; pressurize a fluid inside the land drilling tool, while positioning the land drilling tool outside the bottom; open the valve; and extend to at least one retractable tablet.
    [0006]
    Method according to claim 5, characterized in that it further comprises detecting at least one change in the rotational speed of the land drilling tool and opening the valve in response to the change detected in the rotational speed of the land drilling tool.
    [0007]
    Method according to claim 5, characterized in that it further comprises detecting at least a change in weight in the land drilling tool and opening the valve in response to the detected change in weight in the land drilling tool.
    [0008]
    Method according to claim 7, characterized in that it further comprises maintaining a rotational speed of the land drilling tool, while detecting at least a change in weight in the land drilling tool.
    [0009]
    Method according to claim 8, characterized in that maintaining the rotational speed of the land drilling tool comprises maintaining a rotational speed that is substantially zero rotation per minute.
    [0010]
    Method according to claim 5, characterized in that it further comprises releasing fluid from the first reservoir in a drilling fluid channel of the onshore drilling tool at the valve opening.
    [0011]
    Method according to claim 5, characterized in that it further comprises releasing the fluid from the first reservoir into a second reservoir at the valve opening.
    [0012]
    Method according to claim 11, characterized in that it further comprises moving a second piston inside the onshore drilling tool in response to the release of the fluid from the first reservoir.
    [0013]
    Method according to claim 12, characterized in that it further comprises deflecting a diaphragm inside the onshore drilling tool in response to the release of the fluid from the first reservoir.
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    同族专利:
    公开号 | 公开日
    WO2012174206A2|2012-12-20|
    CN103703209A|2014-04-02|
    MX2013014902A|2014-02-17|
    US9970239B2|2018-05-15|
    EP2721243A2|2014-04-23|
    BR112013032031A2|2016-12-20|
    US20180258705A1|2018-09-13|
    US9080399B2|2015-07-14|
    US10731419B2|2020-08-04|
    CN103703209B|2016-02-24|
    EP2721243B1|2018-05-23|
    US20120318580A1|2012-12-20|
    CA2838732A1|2012-12-20|
    WO2012174206A3|2013-04-25|
    NO2834208T3|2018-08-04|
    RU2014100613A|2015-07-20|
    EP2721243A4|2016-04-06|
    CA2838732C|2016-08-02|
    US20150292268A1|2015-10-15|
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    法律状态:
    2017-03-28| B11A| Dismissal acc. art.33 of ipl - examination not requested within 36 months of filing|
    2017-08-29| B04C| Request for examination: reinstatement - article 33, solely paragraph, of industrial property law|
    2018-12-11| B06F| Objections, documents and/or translations needed after an examination request according art. 34 industrial property law|
    2019-11-19| B06U| Preliminary requirement: requests with searches performed by other patent offices: suspension of the patent application procedure|
    2020-09-29| B09A| Decision: intention to grant|
    2020-12-01| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 14/06/2012, OBSERVADAS AS CONDICOES LEGAIS. |
    优先权:
    申请号 | 申请日 | 专利标题
    US13/160,015|US9080399B2|2011-06-14|2011-06-14|Earth-boring tools including retractable pads, cartridges including retractable pads for such tools, and related methods|
    US13/160,015|2011-06-14|
    PCT/US2012/042400|WO2012174206A2|2011-06-14|2012-06-14|Earth boring tools including retractable pads, cartridges including retractable pads for such tools, and related methods|
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