Patent Application
20060237234
The invention relates to tools for forming bores in the earth, especially rock, and particularly to rotary drill bits for use in oil and gas exploration and mining.
Drag bits for drilling through rock are typically outfitted with hard, durable cutters. To improve wear, the cutters often possess contact surfaces made from diamond, typically in the form of polycrystalline diamond compact (PDC). PDC is an extremely hard and wear resistant material.
Although PDC cutters are known to have one of the lowest rates of wear when operated at cooler temperatures, thermal damage to the diamond layer of the cutter begins at temperatures of approximately 700 degrees Celsius. Thermal damage lowers wear resistance and the PDC cutters become more susceptible to abrasive wear and breakage from impact.
Greater tangential cutter velocity causes more friction, thus generating more heat. Cutters moving at higher tangential velocities will thus tend to operate at higher temperatures. At some velocity, frictional heat reaches a level sufficient to cause cutter wear rates to accelerate, reducing the life of the cutters. In conventional PDC drag bits, the tangential velocity of a cutter, when measured relative to the material being cut, depends on the distance of the cutter from the center of rotation of the drill bit. For a given angular velocity, the tangential velocity of cutter increases with the distance of the cutter from the bit's axis of rotation. Thus, a PDC cutter's intolerance of high temperatures limits, in practice, the diameter of the bit.
Increased application of force also generates more heat. Cutters require more force to penetrate harder rock. Cutters dragging through harder rock have higher wear rates due to the increased application of force. Therefore, the critical point at which the wear rate begins to accelerate is also a function of hardness of rock in addition to the rotational velocity of the drill bit to which the cutter is attached. In softer rocks, accelerated wear rates do not occur until higher rotational speeds are used; in harder rocks, acceleration of the wear rate occurs at much lower rotational speeds.
A number of additional factors also shorten the life of PDC cutters.
First, a cutter's abrupt contact with rock formations also increases the rate of wear of PDC cutters. Drilling with conventional PDC drag bits require application of weight and torque to a drill string to turn the drilling tool face and drive the face into the formation. Torque rotates the bit, dragging its PDC cutters through the formation being cut by the cutters. Dragging generates chips, which are removed by drilling fluids, thereby forming a bore or drilled hole. The drilling action causes a reverse, corresponding torque in the drill string. Because of the length of the drill string, the torque winds the drill string like a torsion spring. If a bit releases from consistent contact with the formation being drilled, the drill string will unwind and rotate backward. Changing the tension in the drill string causes the drill bit to come into irregular, abrupt contact either with the sides of the bore or the exposed formation surface being cut. These irregular contacts can cause impact damage to the cutters.
Second, drill strings will also vibrate, sometimes severely. Under typical drilling conditions, a drill string rotates at 90 to 150 rpm. These vibrations can also damage a drill bit, including the cutters, as well as the drill pipe, MWD equipment, and other components in the drilling system.
Third, “bit whirl” further contributes to impact loads on PDC cutters. This complex motion of the drill bit is thought to occur due to a combination of causes, including lateral forces on the drill bit due to vibration of the drill string vibration, heterogeneous rock formations, bit design, and other factors in combination with the radial cutting ability of PDC bits. Whirl of a drill bit in a bore subjects PDC cutters on the bit to large impact loads as the bit bounces against rock or other material in the bore. Cutters on these drill bits will lose large chips of PDC from impact, rather than from gradual abrasion of the cutter, thereby shortening the effective life of the cutters and the drill bit.
Drilling tools disclosed in U.S. Pat. No. 6,488,103 of Dennis et al., and in U.S. application Ser. No. 10/988,722, filed Nov. 15, 2004, both of which are incorporated herein by reference, address these problems by reducing the thermal and impact stresses on the cutters. The tools employ a plurality of satellite mills surrounding a central pilot bit. The satellite mills reduce the tangential velocity of the cutters along the periphery of the bore hole.
The invention pertains to an earth boring tool, or aspects thereof, having PDC cutters that overcomes one or more of these problems by combining on the same rotational axis a central bit and a relatively larger diameter reamer that extends beyond the central bit. In effect, the central bit bores the center of the hole and the reamer enlarges it. By turning the reamer at a relatively low angular velocity relative to the earth, the tangential velocity of the cutters on the reamer are kept low enough to reduce wear and other adverse affects associated with higher tangential velocities of the cutters. The central bit is allowed to rotate relatively faster, thereby permitting larger diameter holes to be bored without adversely affecting cutter performance or drilling rate. Cutting speed can be optimized, allowing the maximum efficiency without excess wear of the cutters.
Several additional benefits are possible with such a tool. It will tend to create less vibration and chatter. Less force on the drilling tool is required for cutting. This in turn lowers the torque on the drill string, lessening the chance of the drill string of wrapping up. Lighter force applied to the tool also permits use of a lighter tubing having thinner walls to be used.
Details of an example of such an earth boring tool are described below.
In the following description, like numbers throughout the figures refer to like elements.
Briefly, in the following example of an earth boring tool, the pilot bit and reamer are each driven by a separate motor, thereby avoiding the complexities of gears and problems occasioned by them. Examples of such problems include structural complexities necessary to have seals, with the attendant potential for failure. If seals are not used, there is a substantial risk of gear failure or jamming that is not easily addressed by merely hardening the gears.
Counter-rotating the reamer and drill bit will reduce torque on the string and stress on the cutting tool. With this configuration, the angular velocity of motor 12 must overcome the opposite rotation of the output 22 of motor 10. Preferably, the central, high-speed bit rotates right, to tighten threaded connections, and the low-speed reamer turns left.
Using conventional positive displacement motors (PDMs)—also called “mud motors”—for motors 10 and 12 permits the motors to be powered by drilling fluid pumped down a drilling string. With their axes aligned with each other and the tool, drilling fluid will flow from one into the next, and then out the end of the tool in a manner to cool the cutters and clear cutting debris. A central stator of the first mud motor, motor 10 in the preceding schematic, remains stationary with respect to the casing of the tool and the drill string. An outer, sleeve-shaped rotor functions as output 22. This outer rotator is then coupled with an outer, sleeve-shaped stator of the second mud motor, which corresponds with motor 12. The construction of the second motor is the inverse of the first mud motor: the stator, or stationary part, is disposed on the outside of the mud motor, with the rotor formed on an internal, rotating shaft. This inverse construction or arrangement allows the two motors to be coupled for drilling fluid to flow straight from one into the other. It also permits the reamer to be easily coupled to the rotor of the first motor or the stator of the second motor.
Mounted within the main body of each of the tools include an upper positive displacement motor (PDM) 40 and a lower PDM 42. One purpose of PDM 40 is to provide a relatively low-speed rotational output for turning a reamer. One purpose of PDM 42 is to provide a relatively high-speed rotational output for turning a pilot bit. However, PDM 42 is rotated by PDM 40 and, therefore, the true angular velocity of the “high speed” PDM 42 may not necessarily be higher than the angular velocity of the output of the upper, “low speed” PDM 40.
The upper, low speed PDM is coupled to a lower end of the flex joint 36 in a substantially non-rotating or fixed relationship by attaching stator 44 to flex joint 36. Rotor 46 of upper PDM 40, which is an elastomer, rotates an outer body 48 of the upper PDM 40. Fluid under pressure flows from the drilling string (not shown) into passage 50, which in turn carries it to the upper PDM 40, causing the rotor 48 and, thus also, body 52 of the upper PDM to turn. Small arrows throughout the figures indicate the direction of fluid flow during operation.
Body 54 of the lower PDM 42 connects to body 52 of the upper PDM. This connection is, in the example, threaded, though other types of connections may be used. The connection causes the body of the lower PDM to rotate with the body of the upper PDM. Stator 56 of the lower PDM 42 is thus coupled to, and turns with, the rotor 48 of the upper PDM 40. Rotor 58 of the lower PDM is connected to a flex shaft 59, which in turn is connected to lower shaft 60. The flex shaft provides, in essence, a flexible coupling between the output of the lower PDM and the lower shaft that accommodates the eccentric movement of the rotor 58 with respect to the center line of the tool. A drill bit 62, on which a plurality of cutters (not shown) are mounted, is attached to the free end of shaft 60. The shaft includes a passageway 64 through its center. A portion of the drilling fluid exiting the lower PDM is diverted through the passageway to the drill bit.
Reamer 66 couples to body 54 of the lower PDM 42 through inner bearing housing 68. In the illustrated embodiments, reamer 66 is attached to inner bearing housing 68 by a threaded connection, and the bearing housing 68 is connected to the body 54 of the lower PDM by a threaded connection.
Several sets of radial bearings support rotating components within the body of the tool, namely radial bearing assemblies 70 and 78 support the relative rotation of the upper and lower PDMs in each of the tools, and radial bearing assemblies 71 and 73 support rotation of the lower shaft. Radial bearing assembly 70 includes a radial bearing 72 and a bearing wear surface layer 76 disposed between the tool casing 39 and upper bearing housing 74. The upper bearing housing is connected to body 52 of the upper PDM, and thus rotates with the body of the upper PDM. Bearing assembly 78 includes a radial bearing 80 disposed between lower bearing housing 68 and outer bearing housing 82. The outer bearing housing is connected to casing 39 of the tool, preferably by a threaded connection. Bearing assemblies 71 and 73 are located at opposite ends of the lower shaft 60. They include radial bearings 75 and 79, respectively, each with a wear surface 79.
A set of thrust bearings limit movement of rotating components along the axis of the tool. Upper thrust bearing assembly 84 include a pair a fixed bearings 86 and 88, and a pair of moving bearings 90 and 92, each having a wear surface 113. Spacer 94 acting against radial bearing 72 prevents upward movement of the fixed bearing 86, and thus also of thrust bearing assembly 84. Locking nut 96 stops upward movement of the radial bearing. Ledge 98, which is integrally formed in casing 39, prevents downward movement of fixed bearing 88 and thus also of the thrust bearing assembly. Moving bearings 90 and 92 are trapped by the fixed bearings. Ledge 100 transfers the load on the rotating components to the thrust bearing assembly. Some amount of lateral movement of elements of the thrust bearing assembly is desirable, as it permits drilling fluid to migrate into and down through outer passageway 102, through the upper radial bearing assembly and then through the upper thrust bearing assembly. Spacer 103 prevents downward movement of bearing wear surface layer 76.
Lower thrust bearing assembly 105 has a construction similar to that of the upper thrust bearing, with fixed bearings 106 and 108 and moving bearings 110 and 112, each with a wear surface 113. The thrust bearing is trapped by the set of radial bearings 71 and 73, with shoulder or ledge 114 stopping upward lateral movement of the bearings. Spacers are used to space apart the bearings and facillitate flow of drilling fluids through the bearings. Spacer 116 keeps fixed bearings 106 and 108 spaced apart at the correct distance. Lock nut 118 screws onto a threaded interior surface of inner bearing housing 68 to prevent downward movement of the radial bearing assemblies 71 and 73 and thrust bearing assembly 105. Like the other radial and thrust bearings, this thrust bearing assembly is also lubricated and cooled by drilling fluid. However, it is cooled by fluid exiting lower PDM 42.
It is preferred that at least the thrust bearings, due to expected high loading, be made of a wear resistant material, such as a polycrystalline diamond compact or similar material.
The bearing assemblies are, in the example tools described above and shown in
Referring now just to
