1. Field of the Invention
This invention relates to apparatus for straight and directional drilling of underground formations. More particularly, the invention relates to drill bits for earth-boring drill strings for navigational drilling.
2. State of the Art
The ability to steer a drill string in a preferred direction in earth formations has been developing for several decades. At least two technologies are required.
First, the drilling crew must be able to navigate. That is, the crew must be able to tell where a drill bit at the bottom of the drill string is located in terms of direction, rotational orientation and distance. In recent decades, downhole navigational technology has greatly improved the ability to find the exact position and orientation of a tool at the bottom of a drill string.
The second requirement is the mechanical technology of downhole tools for orienting the bit at the end of the drill string to drill directionally at some angle away from a straight path.
In recent years, navigation technology and directional drilling technology have been employed in a new type of drilling in which a single drill string may be used in drilling both straight and nonlinear segments of the bore hole without pulling or "tripping" the drill string for replacement of bottom hole assembly components. This new type of drilling, generally called "steerable drilling" or "navigational drilling," employs both a rotatable drill string and a downhole motor (generally a Moineau principle mud motor, although turbines have also been employed) for rotation of the drill bit independently from drill string rotation. Another key component for navigational drilling is a means for orienting or tilting the drill bit at a small angle (typically less than 4.degree.) to the motor and drill string above. Navigational drilling is then effected with such a string by orienting the drill bit and drilling under motor-powered bit rotation alone for drilling a curve, and rotating the drill string in addition to driving the bit with the motor for drilling a straight bore hole. The first patents directed to this technique and various bottom hole assemblies for carrying it out are U.S. Pat. Nos. 4,465,147; 4,485,879 and 4,492,276.
U.S. Pat. No. 4,465,147 (Feenstra et al., 1984) discusses a method and means for controlling the course of a bore hole which uses a downhole motor having an eccentric stabilizer mounted on each end of the housing. This system uses the drill bit attached to the output shaft of the hydraulic motor offset in the bore hole to cant the hydraulic motor off the axis of the main drill string. The axis of rotation of the downhole motor attached to the drill bit and the drill bit itself precesses when the drill string rotates for straight drilling.
U.S. Pat. No. 4,485,879 (Kamp et al., 1984) discusses a method and means for controlling the course of a bore hole which uses a downhole motor having a housing having a preferential tendency to bend in a particular longitudinal plane. As with the '147 patent, the bottom hole assembly of the '879 patent will cause precession of the drill bit, perhaps to a lesser magnitude but with even greater lack of predictability due to the increased preferential bending elasticity of the motor housing.
U.S. Pat. No. 4,492,276 (Kamp, 1985) discloses a downhole drilling motor and method for directional drilling of bore holes which uses a tilted bearing unit to support and incline an output shaft relative to the axis of the motor housing. In this way, the central axis of the output shaft intersects the longitudinal axis of the motor housing rather than coinciding with it.
In addition to the foregoing patents, U.S. Pat. No. 4,667,751 (Geczy et al., 1987) discloses a system and method for controlled rotational drilling which employs a bent housing (tilt unit) attached to a drill string below a downhole motor. Stabilizers are used above and below the bent housing with a stationary drill string to set the direction of the drill bit for drilling a curved hole or a straight hole in the manner previously described. One notable deficiency with this system, as with other navigational drilling bottom hole assemblies, is the drilling of a hole which is oversized from the nominal size of the drill bit when both the hydraulic motor and the drill string are rotated.
U.S. Pat. No. 4,739,842 (Kruger et al., 1988) discusses an apparatus for optional straight or directional drilling of underground formations, which in some embodiments is virtually identical to that of the '751 patent. The '842 patent discusses a downhole motor having an output shaft connected to the drill bit either through a single tilted output shaft, or a shaft assembly having two opposite tilts to minimize the lateral offset of the drill bit from the drill string above. Either concentric or eccentric stabilizers may be employed.
With all navigational drilling bottom hole assemblies, a change in drilling direction and the act of nonlinear drilling itself causes stresses in the bottom hole assembly which are transmitted to the drill bit, causing excessive friction between the drill bit and the wall of the bore hole.
As discussed in the '842 patent, when the drill string is not rotating, the bottom hole assembly with drill bit and stabilizers define points on a curve, the radius of which defines the angle of curvature drilled by the bottom hole assembly in a directional drilling mode. Upon rotation of the drill string, the bottom hole assembly rotates eccentrically in the bore hole. The drill bit, although drilling a hole which is axially aligned with the main drill string, drills an oversized hole. The axis of rotation of the bit rotating on the downhole hydraulic motor precesses around the axis of the straight bore hole.
As noted previously, the basic approach of navigational drilling is to have a drill string comprised of lengths of drill pipe threadedly connected and extending from a drilling rig into the earth formation. The drill string is attached to a rotary table or top drive on the drill rig. In the first case, the drill string itself is keyed to the rotary table so that it can axially move through the rotary table but must rotate with it. If a top drive is used, the drive is lowered as the drill string progresses. As a drill bit attached to the extreme distal end of the drill string cuts its way further into the earth formation, additional drill pipe is attached to the drill string and lowered into the bore or hole.
For purposes of lubrication of parts, sealing the bore, cooling the face of the bit, powering downhole motors, and for carrying away the debris from the earth formation being drilled, drilling mud is pumped down through the drill string. The drill pipe has a sufficient inside diameter for mud flow, discharging the mud through ports in the face of the drill bit crown. Ports in the drill bit face may aim numerous flows of mud toward the cutting elements in the bit crown. Passages for carrying the mud along the face of the bit crown are designed into the bit along with junk slots along the gage of the bit to pass the debris upward into the annulus formed by the drill string and the wall of the well bore. The drill pipe being of smaller diameter than the gage of the drill bit, the annulus formed between the drill string and the bore wall can accommodate the dense mud as it entrains and carries the debris upward to be removed at the surface before the mud is recycled down the well hole.
High pressures are required to pump drilling mud from the surface to the face of a drill bit at the bottom of several thousand feet of mud column. High flows to carry debris and to cool cutters mean extremely high horsepowers at these pressures. Tremendous energy is coursing through the flow of mud. In addition, the hydrostatic pressure at the bottom of the hole is several thousand pounds per square inch.
The high energy content of the high pressure mud flow permits the use of a second prime mover in addition to the engine rotating the drill string from the top of the well. A special hydraulic motor, which may comprise a turbine but which is generally a Moineau-principle type motor, is attached in the drill string to extract energy from the mud flow. The outer casing of the downhole hydraulic motor is engaged to rotate with the drill string while an output shaft extending downwardly from the hydraulic motor turns at some angular velocity with respect to the drill string. Thus, the output shaft from the hydraulic motor rotates at the angular velocity of the output shaft with respect to the drill string plus the angular velocity of the drill string rotating with respect to the earth formation.
The essential concept of navigational drilling employs a mechanism above or usually below the hydraulic motor in the drill string to cant or tilt the drill bit at a slight angle to the well bore axis, normally on the order of a fraction of a degree to four degrees. To drill in a direction away from the current path of the bore hole, the drilling crew rotates the drill string through an arc of less than 360.degree. to orient the drill bit connected to the output shaft of the downhole hydraulic motor. If driven only by the hydraulic motor, the bit points in the desired direction of drilling. In that orientation, the drill string is not rotated; only the output shaft of the hydraulic motor is rotated. As the hydraulic motor output shaft rotates, the drill bit cuts, chips, grinds, or crushes the formation before it to form a bore hole path shaped in a long arc. That is, as the drill bit moves ahead, the canting or tilting mechanism which forces the bit to cut to one side on an angle from the drill string follows the bit into the hole, continuing to force the bit to cut at that same angle. Thus, the drill bit moves ahead in a long arc until the bore is aiming in a desired direction. Having cut a directional hole arcing away from some original path to a new desired orientation, the drill string is rotated as the motor also independently rotates the drill bit. The drill bit then drills straight ahead.
Pulling the drill string out and replacing it, called "round tripping," is an expensive proposition which loses drilling time, and navigational drilling techniques alleviate the need to round trip between straight and curved sections of well bore. Thus, rather than removing the angle drilling equipment from the end of a drill string, a drilling crew simply begins anew to rotate the drill string. As the drill string rotates, its own rotation of the hydraulic motor and tilt unit is superimposed on the rotation of the bit with respect to the hydraulic motor casing and drill string. Thus, the motor-rotated drill bit is moved around the outside perimeter of the hole by the drill string rotation.
Drill bits are designed for drilling a collinear path with respect to an axis of rotation. Particularly, in diamond bits which have polycrystalline diamond compacts as cutting elements attached to a bit face or to studs protruding from the bit face, each cutting element should sweep a specific region in the formation on each rotation of the bit. A drill bit design presumes attachment directly to a coaxially-rotating prime mover. A hydraulic motor at the end of a non-rotating drill string approaches the design conditions, as does bit rotation by drill string rotation, if no tilt mechanism is installed. In these cases, the bit contacts the formation in an orientation for which the bit was designed. Each cutting element sweeps the surface which it is designed to cut, making repeated sweeps at its diametral position. Along its rotating path, it advances at or near its design rate of penetration into the formation.
However, for straight drilling with a navigational drilling bottom hole assembly, the bit crown rotates with the output shaft of the hydraulic motor but the axis of rotation shared by the output shaft and bit crown precesses around the bore hole. Therefore, an individual cutting element on the bit does not continue to rotate at a constant diametral position in the bore. Further, since the bit is canted off the axis of the hole, each cutting element follows a complex, irregular helical path in the formation.
In contrast, a cutting element located on the nose of a bit at the end of a straight hole drill string should cut an annulus in the earth formation at a radius equal to the distance of that cutting element from the axis of rotation of the bit crown. On each rotation, the cutting element should continue in the same annular track seeing over and over that same annulus as it continues to cut into the formation. Likewise, other cutting elements will cut in their own respective, advancing, rotating paths. On the flank or shoulder portion of a bit crown, a cutting element should be working on an advancing, slightly spiraling groove. The radius corresponds to the distance of the cutting element from the axis of rotation. The spiral advances at the rate of penetration of the bit into the formation. Cutting elements on the gage portion of the crown likewise spiral ahead at the gage radius and the rate of penetration of the drill bit.
However, bit damage is excessive during straight drilling with a navigational drilling bottom hole assembly due to the loads experienced by cutters on a precessing, tilted bit. As the bit's axis of rotation sweeps eccentrically around the centerline of the hole, it creates nonuniform, off-design, and impact loading on the cutting elements.
As the entire bit in such situations is rotating rapidly about the drill string axis as well as about a canted axis defined between the motor and the drill bit, virtually all points on the bit actually precess around the centerline of the advancing hole. The hypocycloidal, tilted path thus defined by each precessing cutting element does not cut in an advancing circle in a single plane into the formation, but distorted circles of varying depth around an ever-changing center.
As a result of the precession and the tilt of the bit, the cutting elements are not in continuous contact with the formation so a reduced number of cutting elements can be in contact with the formation at any time. This reduced number of cutters must still support all the loads generated by drilling. Further, the orientation (side rake and back-rake) of cutting elements with respect to the formation being drilled varies on a continuous basis, inducing off-design and non-uniform loads. Meanwhile, the angle of the rotating bit with respect to the drill string also rotating results in cutters which alternately move impotently into empty space, revolving back to contact the formation. The result is a shock or impact load on a cutter as it slams back into the formation. Clearly, at any instant of time, certain cutting elements on the bit face are overloaded, while others see virtually no load.
Thus, several adverse effects result from the motion of the individual cutting elements on a bit disposed on a navigational drilling bottom hole assembly that is drilling a straight hole. First, the hole is oversized, reducing efficiency and requiring that a substantial additional volume of the formation be drilled to advance the bore hole. Second, not seeing the same simple circle or spiral path continuously, a given cutting element is exposed to repeated impact as it moves between the empty bore and the bore wall or uncut formation face, or crosses the paths cut by other cutting elements at random. Third, the cutting elements in general are not uniformly loaded as they were designed to be but see higher and more abrupt maximum loads and lower minimum loads so individual cutting elements are more likely to experience catastrophic failure. Fourth, the effective rate of penetration is slowed since numerous cutting elements are not properly loaded continuously, instead alternately having too little and too much formation material to cut. Fifth, the irregular contacts due to the combination of the cutters' irregular paths and the canting of the drill bit to one side of the oversized hole cause bouncing or chattering of the cantilevered drill bit against the formation. Sixth, cutting elements located at certain positions on the bit, such as at the nose or shoulder, will continue to be loaded more often and more heavily than others.
The end result on the drilling assembly is fatigued parts in the drill string, spalling and fracturing of cutting elements, and premature abrasion and erosion of the drill bit. Exaggerated, uneven wear regions appear in addition to damage to overloaded individual cutting elements.