WO2008076625A2

WO2008076625A2 - System for steering a drill string

Info

Publication number: WO2008076625A2
Application number: PCT/US2007/086323
Authority: WO
Inventors: David R. Hall; Jim Shumway; Paula Turner; David Lundgreen
Original assignee: Hall David R
Priority date: 2006-12-15
Filing date: 2007-12-04
Publication date: 2008-06-26
Also published as: CA2672658A1; MY155017A; AU2007334141B2; NO20092420L; CN101563520B; EP2092153A2; AU2007334141A1; WO2008076625A3; MX338284B; CN101563520A; CA2672658C; EP2092153A4; BRPI0718338A2; MX2009006368A

Abstract

In one aspect of the present invention, a drill bit assembly has a body portion intermediate a shank portion and a working portion The working portion has at least one cutting element and at least a portion of a shaft is disposed within the body portion and protrudes from the working portion The shaft has a distal end rotationally isolated from the body portion and is in communication with a subterranean formation A motor is adapted to rotationally control the distal end.

Description

System for steering a drill string

BACKGROUND OF THE INVENTION

This invention relates to drill bits, specifically drill bit assemblies for use in oil, gas, geothermal, and horizontal drilling. The ability to accurately adjust the direction of drilling in downhole drilling applications is desirable to direct the borehole toward specific targets. A number of steering systems have been devised for this purpose.

One such system is disclosed in U.S. Patent No. 5,803,185, which is herein incorporated by reference for all that it contains. It discloses a steerable rotary drilling system with a bottom hole assembly which includes, in addition to the drill bit, a modulated bias unit and a control unit, the bias unit comprising a number of hydraulic actuators around the periphery of the unit, each having a movable thrust member which is hydraulically displaceable outwardly for engagement with the formation of the borehole being drilled. Each actuator may be connected, through a control valve, to a source of drilling fluid under pressure and the operation of the valve is controlled by the control unit so as to modulate the fluid pressure supplied to the actuators as the bias unit rotates. If the control valve is operated in synchronism with rotation of the bias unit the thrust members impart a lateral bias to the bias unit, and hence to the drill bit, to control the direction of drilling.

BRIEF SUMMARY OF THE INVENTION

In one aspect of the present invention, a drill bit assembly has a body portion intermediate a shank portion and a working portion The working portion has at least one cutting element and at least a portion of a shaft is disposed within the body portion and protrudes from the working portion. The shaft has a distal end rotationally isolated from the body portion and is in communication with a subterranean formation. A motor is adapted to rotationally control the distal end. The motor may be an electric motor, a hydraulic motor, a positive displacement motor, or combinations thereof, the electric motor is a stepper motor, an AC motor, a universal motor, a three-phase AC induction motor, a three-phase AC synchronous motor, a two -phase AC servo motor, a single-phase AC induction motor, a single- phase AC synchronous motor, a torque motor, a permanent magnet motor, a DC motor, a brushless DC motor, a coreless DC motor, a linear motor, a doubly- or singly- fed motor, or combinations thereof. The motor may be powered by a turbine, a battery, or a power transmission system from the surface or downhole.

The motor may be in communication with a downhole generator. The generator may have magnets made of samarium cobalt.

A gear assembly may be intermediate and in communication with the shaft and the motor. The shaft may be in communication with the motor through a second gear assembly. The second gear assembly may be a planetary gear system. The second gear assembly may have a gear ratio of at least 2:1. The shaft may protrude from the working portion 6 to 20 inches. A sensor disposed within the drill bit assembly may measure the orientation of the shaft with respect to the drill bit assembly. The distal end may be asymmetric.

A sensor secured to the drill bit assembly may measure and maintains the orientation of the drill bit assembly with respect to a subterranean formation. The sensor may be a gyroscope, an inclinometer, a magnetometer or combinations thereof.

The drill bit assembly may be in communication with a downhole telemetry system.

BRIEF DESCRIPTION OF THE DRAWINGS

Fig. 1 is a cross-sectional diagram of an embodiment of a drill string suspended in a bore hole.

Fig. 2 is a cross- sectional diagram of an embodiment of a drill bit assembly. Fig. 3 is a cross- sectional diagram of another embodiment of a drill bit assembly. Fig. 4 is a cross- sectional diagram of an embodiment of a portion of a tool string. Fig. 5 is a sectional diagram of an embodiment of a gear assembly in a downhole tool string component.

Fig. 6 is a schematic diagram of an embodiment of a generator in communication with a load. Fig. 7 is a schematic diagram of another embodiment of a generator in communication with a load.

Fig. 8 is a cross- sectional diagram of another embodiment of a portion of a drill bit assembly.

Fig. 9 is a sectional diagram of another embodiment of a gear assembly in a drill bit assembly.

Fig. 10 is a cross-sectional diagram of another embodiment of a drill string suspended in a bore hole.

Fig. 11 is a perspective diagram of various embodiments of a drilling rig.

Fig. 12 is a perspective diagram of an embodiment of a distal end of a shaft. Fig. 13 is a perspective diagram of another embodiment of a distal end of a shaft.

Fig. 14 is a perspective diagram of another embodiment of a distal end of a shaft.

Fig. 15 is a perspective diagram of another embodiment of a distal end of a shaft.

Fig. 16 is a perspective diagram of another embodiment of a distal end of a shaft.

Fig. 17 is a perspective diagram of another embodiment of a distal end of a shaft. Fig. 18 is a perspective diagram of another embodiment of a distal end of a shaft.

Fig. 19 is a perspective diagram of another embodiment of a distal end of a shaft.

Fig. 20 is a perspective diagram of another embodiment of a distal end of a shaft.

Fig. 21 is a perspective diagram of another embodiment of a distal end of a shaft.

DETAILED DESCRIPTION OF THE INVENTION AND THE PREFERRED

EMBODIMENT Fig. 1 is an embodiment of a drill string 100 suspended by a derrick 101. A bottom- hole assembly 102 and/or drill bit assembly 102 is located at the bottom of a bore hole 103 and comprises a drill bit 104. As the drill bit 104 rotates downhole the drill string 100 advances farther into the earth. The drill string may penetrate soft or hard subterranean formations 105. The drill bit assembly may comprise data acquisition devices which may gather data. The data may be sent to the surface via a transmission system to a data swivel 106. The data swivel 106 may send the data to the surface equipment. Further, the surface equipment may send data and/or power to downhole tools and/or the drill bit assembly 102. Fig. 2 discloses a cross- sectional diagram of the drill bit assembly 102. The drill bit assembly may comprise a mud turbine 201, a battery 201 or a power transmission system from the surface or downhole used to power electronic instrumentation devices and tools disposed in the drill bit assembly 102. The turbine 201 may be in communication with power generators 203 creating a power supply for the drill bit assembly 102 and drill string 100. The drill bit assembly 102 may also comprise power converters 204 to adapt the electrical output of the power source 201 to an AC power source.

The drill bit assembly 102 may also comprise a steering motor 205 adapted to rotationally control a shaft 202 disposed within a body portion 209 of the drill bit 104 and protrudes from a working portion 210 of the drill bit 104. The shaft 202 may protrude from the working portion 210 6 to 20 inches. The shaft 202 may comprise a distal end 211 rotationally isolated from the body portion 209 and in communication with the subterranean formation 105. The shaft 202 and its distal end 211 may be utilized to steer the drill bit assembly 102 and drill string 100 through the formation 105.

The motor 205 may be an electric motor, a hydraulic motor, a positive displacement motor, or combinations thereof. The electric motor may be a stepper motor, an AC motor, a universal motor, a three-phase AC induction motor, a three-

- A - phase AC synchronous motor, a two -phase AC servo motor, a single-phase AC induction motor, a single-phase AC synchronous motor, a torque motor, a permanent magnet motor, a DC motor, a brushless DC motor, a coreless DC motor, a linear motor, a doubly- or singly- fed motor, or combinations thereof. The drill bit assembly 102 may comprise a steering motor control 204 adapted to provide control of the motor 205. A sensor may be disposed within the drill bit assembly 102 to measure the orientation of the shaft 202 with respect to the drill bit assembly 102.

The drill bit assembly may also comprise a gear assembly 206 to control the rpm of the shaft 202. Inclination and direction sensors 207 may also be disposed within the drill bit assembly to detect and measure the location of the drill bit assembly 102 downhole. The direction sensors 207 may also maintain the orientation of the drill bit assembly with respect to a subterranean formation 105. The sensors 207 may be gyroscopes, inclinometers, magnetometers or combinations thereof. A telemetry network link 208 may also be disposed within the drill bit assembly 102. Figs. 3 and 4 disclose an alternative embodiment of the present invention. The drill bit assembly 102 may comprise a first rotor 300 disposed within a bore 301 of the drill bit assembly 102 adjacent to the drill bit 104, which is in communication with the shaft 202. The first rotor 300 may be part of the turbine 201, though the first rotor 300 may also be part of a motor. The turbine 201 preferably comprises from 3 to 5 impellers 304 fixed to the first rotor. A plurality of stator vanes 305 adjacent each of the impellers 304 may be rotationally fixed with respect to the bore of the assembly 102. A second gear assembly 210 connects the second rotor 307 to the first rotor 300. The second gear assembly may comprise a gear ratio of at least 2:1. The second gear assembly 210 may be adapted to rotate the second rotor 307 faster than the first rotor 300. As drilling fluid passes through the turbine 201 in the bore 301, the impellers 304 rotate, spinning the second gear assembly 210 and the first and second rotors. Preferably the first and second rotors will rotate at different speeds, preferably the second rotor 307 will rotate 1.5 to 8 times faster. The stator vanes 305 in the turbine 201 may help increase the efficiency of the turbine 201 by redirecting the flow of the drilling fluid by preventing the fluid from flowing in a circular path down the bore 301 of the drill string 100.

The second rotor 307 may be a part of an electric generator 308. The electric generator 308 also comprises a stator surrounding the second rotor 307. The stator may comprise an electrically conductive coil with 1 to 50 windings. One such generator 308 which may be used is the ^tro 40 from AstroFlight, Inc. The generator 308 may comprise separate magnetic strips disposed along the outside of the rotor 307 which magnetically interact with the coil as it rotates, producing a current in the electrically conductive coil. The magnetic strips are preferably made of samarium cobalt due to its high curie temperature and high resistance to demagnetization.

The coil is in communication with a load. When the load is applied, power is drawn from the generator 308, causing the second rotor 307 to slow its rotation, which thereby slows the rotation of the turbine 201 and the first rotor 300. Thus the load may be applied to control the rotation of the downhole turbine 201. Since the second rotor 307 rotates faster than the first rotor 300, it produces less torque whereby less electrical current from the load is required to slow its rotation. Thus the second gear assembly 210 provides the advantage of reducing the electrical power requirements to control the rotation of the turbine 201. This is very beneficial since downhole power is a challenge to generate and store downhole.

There may also be a second generator 409 connected to the first generator 308 in order to create more current or to aid in the rotation of the first generator 308. The load may be a resistor, nichrome wires, coiled wires, electronics, or combinations thereof. The load may be applied and disconnected at a rate at least as fast as the rotational speed of the second rotor 307.

The electrical generators 308, 409 may be in communication with the load as part of electrical circuitry 401. The electrical circuitry 401 may be disposed within the bore wall 402 of the drill bit assembly 102. The generator 308 may be connected to the electrical circuitry 401 through a coaxial cable 403. The circuitry 401 may be part of a closed- loop system. The electrical circuitry 401 may also comprise sensors for monitoring various aspects of the drilling, such as the rotational speed or orientation of the drill bit assembly 102 with respect to the formation 105. Sensors may also measure the orientation of the generator 308 with respect to the drill bit assembly 102.

The data collected from these sensors may be used to adjust the rotational speed of the turbine 201 in order to control the shaft 202 and its distal end 211. The distal end 211 may comprise an asymmetric tip which may be used to steer the drill bit 104 and therefore the drill string 101. The control of the turbine 201 controls the speed and orientation of the distal end 211 and therefore the drilling trajectory. The shaft 202 may be connected to the first rotor 300 through the gear assembly 206, which may rotate the shaft 202 in the opposite direction as the turbine 201 is rotating. Thus with the help of controlling the turbine's 201 rotational speed, the shaft 202 may be made to rotate with respect to the drill string 100 while being substantially stationary with respect to the formation 105 being drilled and allowing the distal end 211 to steer the drill string 100.

The load may be in communication with a downhole telemetry system 404. One such system is the IntelliServ system disclosed in U.S. Patent No. 6,670,880, which is herein incorporated by reference for all that it dis closes. Data collected from sensors or other electrical components downhole may be sent to the surface through the telemetry system 404. The data may be analyzed at the surface in order to monitor conditions downhole. Operators at the surface may use the data to alter drilling speed if the drill bit assembly 102 encounters formations 105 of varying hardness. Other types of telemetry systems 404 may include mud pulse systems, electromagnetic wave systems, inductive systems, fiber optic systems, direct connect systems, wired pipe systems, or any combinations thereof. In some embodiments, the sensors may be part of a feed back loop which controls tie logic controlling the load. In such embodiments, the drilling may be automated and electrical equipment may comprise sufficient intelligence to avoid potentially harsh drilling formations 105 while keeping the drill string 100 on the right trajectory. In some embodiments, drilling may be fully automated where the desired trajectory and location of the pay load is programmed into the electrical equipment and allowed to run itself without the need for manual controls.

Stabilizers 312 may be disposed around the shaft 202 and within the bore 301 of the drill bit 104 or drill bit assembly 102, which may prevent buckling or decentralizing of the shaft 202.

The turbine 201, gear assemblies 206, 210, and/or generators 308, 409 may be disposed within a protective casing 3 15 within the bore 301 of the drill bit assembly 102. The casing 315 is secured to the bore wall 402 such that anything disposed within may be axially fixed with respect to the center of the bore 301. The casing 315 may comprise passages at locations where it is connected to the bore wall 402 such that the drilling fluid may be allowed to pass through.

The second gear assembly 210 in the embodiment of Fig. 5 is a planetary gear system which may be used to connect the shaft 202 to the first rotor 300. The planetary gear system comprises a central gear 500 which is turned by the first rotor 300 connected to the turbine 201. As the central gear 500 rotates, a plurality of peripheral gears 501 surrounding and interlocking the central gear 500 rotate, which in turn cause an outer gear ring 502 to rotate. The rotational speed ratio from the central gear 500 to the outer gear ring 502 depends on the sizes of the central gear 500 and the plurality of peripheral gears 501. The second gear assembly 210 also comprises a support member 503 for the purpose of maintaining the peripheral gears 501 axially stationary.

The planetary gear system is disposed within the casing 315 such that there is a gap 504 between the outer gear ring 502 and the casing 315 so that the gear ring 502 may rotate. The casing 315 may also comprise an inner bearing surface 505 such that the second gear assembly 210 and the casing 315 may be flush with the gear ring 502 and may still rotate. The casing 315 may also comprise a plurality of passages 506 wherein drilling fluid may pass through the bore 301 of the drill bit assembly 102. Referring now to Fig. 6, the load 600 is a resistor in an electrical circuit 401 which is electrically connected to the generator 308. The rotation of the generator 308 produces an AC voltage across the two generator terminals 601, 602. The circuit comprises a bridge rectifier 603, which converts the AC voltage into a DC voltage. The circuit also comprises a DC switch 604, such as a field-effect transistor (FET), which is driven by logic instructions 605 that turn it on or off. When the DC switch 604 is on, the circuit is completed, causing the DC voltage to drop across the load 600 and drawing power from the generator 308, which thereby causes the rotational speed of the generator 308 to slow. When the DC switch 604 is off, however, the circuit is an open circuit and no power is drawn from the generator 308. A FET switch may be a low cost option for completing the circuit, though it requires DC currents to operate.

Fig. 7 shows another embodiment of a circuit comprising an AC switch 700. The AC switch 700 may be a triode for alternating current (triac), which allows the load to be turned on or off with AC current. The triac may switch whenever the AC voltage crosses zero, which may happen at half cycles of the generator 308 output, depending on the logic instructions 605 driving the switch. An AC switch 700 alternative to the triac is an insulated gate bipolar transistor (IGBT). An advantage to using an IGBT is that the IGBT is able to switch on and off at a rate independent of the cycle period or zero crossing of the AC voltage from the generator 308, though the IGBT is more expensive and complex than the triac.

Referring to Fig. 8, the distal end 211 is adapted such that it may be used as a steering system for the drill string 100. The distal end 211 may comprise an asymmetric tip such that one side 801 has more surface area exposed to the formation 105. The gear assembly 206 is adapted such that the rotational speed of the turbine 201 is from 10 to 25 times faster than the rotational speed of the distal end 211. As the drill string rotates, the turbine 201 may rotate such that the distal end 211 remains rotationally stationary with respect to the formation 105. When the distal end 211 is engaged against the formation 105 and is rotationally stationary with respect to the formation 105, it is believed that the asymmetry of the distal end 211 will deviate the direction of the drill string 100. The orientation of the distal end 211 may be adjusted by the logic which is h communication with the load. The sensors may indicate the position of the distal end 211 and through a feed back loop the logic may adjust the load to reorient the distal end 211. With such a method, the complex drilling trajectories are possible. By causing the distal end 211 of the shaft 202 to rotate with the drill bit 104, it is believed to cause the drill string 100 to drill in a generally straight direction.

Referring to Fig. 9, the second gear assembly 210 may comprise spur gears. A first spur gear 900 may be attached to the first rotor 300 and be in communication with a second spur gear 901. The second spur 901 gear may be attached to an intermediate shaft 902 supported by the casing 315. The second shaft 902 may also comprise a third gear 903 which is in communication with a fourth gear 904 attached to the second rotor 307. The sizes of the gears are adapted such that the second rotor 307 rotates faster than the first rotor 300. The casing 315 and /or the intermediate shaft 902 may comprise bearing surfaces 905 to reduce friction where the casing 315 supports the intermediate shaft 905.

Referring now to Fig. 10, a drill string 100 may be suspended by a derrick 101. A drill bit assembly 102 is located at the bottom of a wellbore 103 and comprises a drill bit 104. As the drill bit 104 rotates downhole the drill string 100 advances farther into the earth. The drill string 100 may be steered in a preferred direction. In some embodiments, a sensor 207 may be disposed on drill string assembly 102 and may be adapted to receive acoustic signals 1001 produced by the drill bit 104. The acoustic signals 1001 produced by the drill bit 104 may be returned from the formation 105. This may be useful in determining different formation 105 characteristics.

Fig. 11 illustrates embodiments of drilling rigs used in various steering applications. In one embodiment, a drilling rig 1100 may be positioned so that a directional relief wellbore 1155 may be drilled to intersect another well 1150 in case of an emergency, such as a blowout, in order to reduce subsurface pressure in a controlled manner. A drilling rig 1110 may be used in a drilling application in which multiple reservoirs 1140, such as oil or gas reservoirs, are located approximately along a vertical trajectory. In such circumstances, it may be beneficial to drill in a substantially straight trajectory 1151 adjacent the reservoirs 1140 and from the substantially straight trajectory 1151, drill multiple trajectories 1152 branching off the main trajectory 1151 toward the reservoirs 1140. Also, it may be necessary during a drilling operation for a wellbore 1115 to be formed around obstacles 1103 such as boulders, hard formations, salt formations, or low pressure regions. Multiple reservoirs 1160 may be reached with one drilling rig 1120 when using a steerable drill string. A wellbore 1125 may be drilled toward a first reservoir. If other wellbores are located near the first wellbore, the steering capabilities of the drill string may allow each reservoir to be drilled without removing the drill string and repositioning the drilling rig 1120 for each drilling operation. In some situations, a reservoir 1170 may be located beneath a structure 1101 such that a drilling rig 1130 cannot be positioned directly above the reservoir and drill a straight trajectory. Thus, a wellbore 1135 may need to be formed adjacent the structure 1101 and follow a curved trajectory toward the reservoir using the steering capabilities of the drill string. Such tool string may be equipped to drill in off-shore applications as well as on-shore applications. Figs. 12 through 15 illustrate embodiments of various distal ends 211. Fig. 12 shows a primary deflecting surface 1206 having a slightly convex geometry 1200. In the embodiment of Fig. 13, the primary surface 1206 may comprise a flat geometry 1300. In Fig. 14, the distal end 211 may also have a slightly convex geometry 1400, but may comprise a greater radius of curvature than the embodiment shown in Fig. 12. The primary deflecting surface may comprise a .750 to 1.250 inch radius. It is believed that a convex geometry 1400 will allow the distal end 211 to crush the formation 105 through point loading, verses through surface loading which may occur in embodiments with flats. It is believed that point loaded is preferred for steering applications. Fig. 15 shows a primary surface 1206 having a slightly concave geometry 1500. The distal end 211 may have a polygonal shape along it length.

Fig. 16 shows an asymmetric distal end 211 with a substantially flat surface 1600, the surface 1600 intersecting a central axis 1601 of the shaft 202 at an angle 1602 between 1 and 89 degrees. Ideally, the angle 1602 is within 30 to 60 degrees. Fig. 17 shows an asymmetric geometry of the distal end 211 comprising a cut 1701. The cut 1701 may be concave, convex, or flat. Fig. 18 shows a geometry of a flat face 1800 with an offset protrusion 1801. The embodiment of Fig. 19 shows an offset protrusion 1801 with a flat face 1900. The asymmetric geometry of Fig. 20 is generally triangular. In other embodiments, the asymmetric geometry may be generally pyramidal. Fig. 21 shows an asymmetric geometry of a generally triangular 2100 distal end 211 with a concave side 2101.

Whereas the present invention has been described in particular relation to the drawings attached hereto, it should be understood that other and further modifications apart from those shown or suggested herein, may be made within the scope and spirit of the present invention.

Claims

CLAIMSWhat is claimed is:

1. A drill bit assembly, comprising: a body portion intermediate a shank portion and a working portion; the working portion comprising at least one cutting element; at least a portion of a shaft is disposed within the body portion and protrudes from the working portion; the shaft comprising a distal end rotationally isolated from the body portion and in communication with a subterranean formation; and a motor adapted to rotationally control the distal end.

2. The drill bit assembly of claim 1, wherein the motor is an electric motor, a hydraulic motor, a positive displacement motor, or combinations thereof.

3. The drill bit assembly of claim 1, wherein the distal end is asymmetric.

4. The drill bit assembly of claim 1, wherein the motor is in communication with a downhole generator.

5. The drill bit assembly of claim 4, wherein the generator comprises magnets made of samarium cobalt.

6. The drill bit assembly of claim 1, wherein a gear assembly is intermediate and in communication with the shaft and the motor.

7. The drill bit assembly of claim 1 , wherein the shaft is in communication with the motor through a second gear assembly.

8. The drill bit assembly of claim 7, wherein the second gear assembly is a planetary gear system.

9. The drill bit assembly of claim 7, wherein the second gear assembly comprises a gear ratio of at least 2:1.

10. The drill bit assembly of claim 1, wherein a sensor disposed within the drill bit assembly measures the orientation of the shaft with respect to the drill bit assembly.

11. The drill bit assembly of claim 1, wherein a sensor secured to the drill bit assembly measures and maintains the orientation of the drill bit assembly with respect to a subterranean formation.

12. The drill bit assembly of claim 11, wherein the sensor is a gyroscope, an inclinometer, a magnetometer or combinations thereof.

13. The drill bit assembly of claim 2 wherein the electric motor is a stepper motor, an AC motor, a universal motor, a three-phase AC induction motor, a three-phase AC synchronous motor, a two -phase AC servo motor, a single-phase AC induction motor, a single-phase AC synchronous motor, a torque motor, a permanent magnet motor, a DC motor, a brushless DC motor, a coreless DC motor, a linear motor, a doubly- or singly- fed motor, or combinations thereof.

14. The drill bit assembly of claim 1, wherein the drill bit assembly is in communication with a downhole telemetry system.

15. The drill bit assembly of claim 1, wherein the motor is powered by a turbine, a battery, or a power transmission system from the surface or downhole.

16. The drill bit assembly of claim 1, wherein the shaft protrudes from the working portion 6 to 20 inches.