Downhole drive shaft connection

This application is a continuation in-part of U.S. patent application Ser. No. 11/306,976, filed Jan. 18, 2006, now U.S. Pat. No. 7,360,610. This application in herein incorporated by reference for all that it contains.

This invention relates to drill bits, specifically drill bit assemblies for use in oil, gas and geothermal drilling. Drill bits are continuously exposed to harsh conditions during drilling operations in the earth's strata. Bit whirl in hard formations for example may result in damage to the drill bit and reduce penetration rates. Further loading too much weight on the drill bit when drilling through a hard formation may exceed the bit's capabilities and also result in damage. Too often unexpected hard formations are encountered suddenly; and damage to the drill bit occurs before the weight on the drill bit may be adjusted. When a bit fails, it reduces productivity resulting in diminished returns to a point where it may become uneconomical to continue drilling. The cost of the bit is not considered so much as the associated down time required to maintain or replace a worn or expired bit. To replace a bit requires removal of the drill string from the bore in order to service the bit which translates into significant economic losses until drilling can be resumed.

The prior art has addressed bit whirl and weight on bit issues. Such issues have been addressed in the U.S. Pat. No. 6,443,249 to Beuershausen, which is herein incorporated by reference for all that it contains. The '249 patent discloses a PDC-equipped rotary drag bit especially suitable for directional drilling. Cutter chamfer size and backrake angle, as well as cutter backrake, may be varied along the bit profile between the center of the bit and the gage to provide a less aggressive center and more aggressive outer region on the bit face, to enhance stability while maintaining side cutting capability, as well as providing a high rate of penetration under relatively high weight on bit.

U.S. Pat. No. 6,298,930 to Sinor which is herein incorporated by reference for all that it contains, discloses a rotary drag bit including exterior features to control the depth of cut by cutters mounted thereon. Sinor seeks to control the volume of formation material cut per bit rotation as well as the torque experienced by the bit and an associated bottomhole assembly. The exterior features preferably precede, taken in the direction of bit rotation, cutters with which they are associated, and provide sufficient bearing area so as to support the bit against the bottom of the borehole under weight on bit without exceeding the compressive strength of the formation rock.

U.S. Pat. No. 6,363,780 to Rey-Fabret which is herein incorporated by reference for all that it contains, discloses a system and method for generating an alarm relative to effective longitudinal behavior of a drill bit fastened to the end of a tool string driven in rotation in a well by a driving device situated at the surface, using a physical model of the drilling process based on general mechanics equations. The model is reduced to retain only pertinent modes. At least two values, Rf and Rwob, are calculated. Rf a function of the principal oscillation frequency of weight on hook (who) divided by the average instantaneous rotating speed at the surface. Rwob is a function of the standard deviation of the signal of the weight on bit (WOB) estimated by the reduced longitudinal model from measurement of the signal of the weight on hook (WOH), divided by the average weight on bit defined from the weight of the string and the average weight on hook. Any danger from the longitudinal behavior of the drill bit is determined from the values of Rf and Rwob.

U.S. Pat. No. 5,806,611 to Van Den Steen which is herein incorporated by reference for all that it contains, discloses a device for controlling weight on bit of a drilling assembly for drilling a borehole in an earth formation. The device includes a fluid passage for the drilling fluid flowing through the drilling assembly, and control means for controlling the flow resistance of drilling fluid in the passage in a manner that the flow resistance increases when the fluid pressure in the passage decreases and that the flow resistance decreases when the fluid pressure in the passage increases.

U.S. Pat. No. 5,864,058 to Chen which is herein incorporated by reference for all that is contains, discloses a down hole sensor sub in the lower end of a drillstring. The sub has three orthogonally positioned accelerometers for measuring vibration of a drilling component. The lateral acceleration is measured along either the X or Y axis and then analyzed in the frequency domain as to peak frequency and magnitude at such peak frequency. Backward whirling of the drilling component is indicated when the magnitude at the peak frequency exceeds a predetermined value. A low whirling frequency accompanied by a high acceleration magnitude based on empirically established values is associated with destructive vibration of the drilling component. One or more drilling parameters (weight on bit, rotary speed, etc.) is then altered to reduce or eliminate such destructive vibration.

A section of a drill string has a drill bit with a body intermediate a shank and a working face. The working face at least one cutting element. A jack element is disposed within the drill bit body and has a distal end substantially protruding from the working face. A drive shaft is in communication with the jack element and a source of rotational power. The drive shaft has a first portion secured within a bore of a tool string component in the tool string and a second portion secured within a bore of the drill bit. The first and second portions of the drive shaft are connected at a pin and box connection wherein the first and second portions are automatically connected as the tool string component is mechanically coupled to the drill bit.

The connection of the first and second portions may a sleeve that has an internal shape with an at least one external feature to interlock either the first or second portion, or both. The at least one feature may be selected from the group consisting of splines, threads, keys, polygonal (in section) surfaces, elliptical (in section) surfaces, or combinations thereof.

The connection may be a threaded connection. The connection may comprise a guide. The connection may comprise a bore adapted to receive the guide. The guide may comprise a geometry selected from the group consisting of splines, keys, polygonal surfaces or combinations thereof.

The drive shaft and jack element may advance the drill string further into a formation by rotating. The drive shaft and jack element assist in advancing the drill string further into the formation by oscillating back and forth with respect to the formation.

The pin and box connection may comprise a press-fit. The first portion may be press-fit into the sleeve. The second portion may be press-fit into the sleeve. The first portion may comprise a material selected from the group consisting of cemented metal carbide, steel, manganese, nickel, chromium, titanium, or combinations thereof. The second portion may comprise a material selected from the group consisting of cemented metal carbide, steel, manganese, nickel, chromium, titanium, or combinations thereof.

The second portion may comprise a generally conical region The at least one feature may have a length of 2.5 inches to 3.75 inches. The at least one feature may have a length of 3 inches.

The first portion and the second portion may comprise at least one coating. The at least one coating may comprise a material selected from the group consisting of a material selected from the group consisting of gold, silver, a refractory metal, carbide, tungsten carbide, cemented metal carbide, niobium, titanium, platinum, molybdenum, diamond, cobalt, nickel, iron, cubic boron nitride, and combinations thereof. The first portion and the second portion may comprise a cemented metal carbide distal end.

FIG. 1 is a perspective 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 string.

FIG. 3 is a cross-sectional diagram of an embodiment of a section of a drill string.

FIG. 4 is a cross-sectional diagram of another embodiment of a section of a drill string.

FIG. 5 is a perspective diagram of another embodiment of a section of a drill string.

FIG. 6 is a perspective diagram of an embodiment of a drive shaft portion

FIG. 7 is a perspective diagram of another embodiment of a drive shaft portion.

FIG. 8 is a perspective diagram of another embodiment of a drive shaft portion

FIG. 9 is a perspective diagram of another embodiment of a drive shaft portion.

FIG. 10 is a perspective diagram of another embodiment of a drive shaft portion

FIG. 11 is a perspective diagram of another embodiment of a drive shaft portion.

FIG. 12 is a perspective diagram of another embodiment of a drive shaft portion

FIG. 13 is a perspective diagram of another embodiment of a section of a drill string.

FIG. 14 is a perspective diagram of another embodiment of a drive shaft portion

FIG. 15 is a perspective diagram of another embodiment of a drive shaft portion.

FIG. 16 is a perspective diagram of another embodiment of a drive shaft portion

FIG. 17 is a perspective diagram of another embodiment of a drive shaft portion.

FIG. 1 is a perspective diagram of an embodiment of a drill string 100 suspended by a derrick 101 . A bottom-hole assembly 102 is located at the bottom of a wellbore 103 and includes a drill bit 104 . As the drill bit 104 rotates downhole, the drill string 100 advances farther into the subterranean formations. The drill string 100 may penetrate soft or hard subterranean formations 105 . The drill bit 104 may be adapted to steer the drill string 100 in a desired trajectory. Steering may be controlled by rotating a jack element (see FIG. 2 ) that is disposed at least partially within the drill bit 104 around a central axis of the jack element. The bottom-hole assembly 102 and/or downhole components 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 bottom-hole assembly 102 . U.S. Pat. No. 6,670,880 which is herein incorporated by reference for all that it contains, discloses a telemetry system that may be compatible with the present invention; however, other forms of telemetry may also be compatible such as systems that include mud pulse systems, electromagnetic waves, radio waves, and/or short hop. In some embodiments, no telemetry system is incorporated into the drill string 100 .

Referring now to FIG. 2 , a cross-sectional diagram of a portion of the drill string 100 shows a bottom-hole assembly (BRA) 102 . The drill bit 104 may be part of the BRA 102 and which includes a jack element 201 . The jack element 201 may oscillate towards and away from the formation 105 and/or the jack element 201 may rotate with respect to the drill bit body 304 . The drill string 100 may comprise at least one position feedback sensor 202 that is adapted to detect a position and/or orientation of the jack element 201 . Monitoring the position and/or orientation of the jack element 201 may aid in steering the drill string 100 . Rotation of the jack element 201 may be powered by a rotary source, such as a downhole motor 203 . The downhole motor 203 may be an electric motor, a mud motor, or combinations thereof. In some embodiments, drill string 100 includes an upper generator 204 and a lower generator 205 . Both generators 204 , 205 are powered by the flow of drilling mud (not shown) past one or more turbines 206 disposed intermediate the two generators 204 , 205 . In some embodiments only one generator may be used, and in other embodiments another method of powering the motor 203 may be employed.

The upper generator 204 may provide electricity to a direction and inclination (D&I) package 207 . D&I package 207 may monitor the orientation of the BHA 102 with respect to some object, such as the center of the planet, the moon, the surface of the planet, a satellite, or combinations thereof. The lower generator 205 may provide electrical power to a computational board 208 and to the motor 203 . The computational board 208 may control steering and/or motor functions. The computational board 208 may receive drill string orientation information from the D&I package 207 and may alter the speed or direction of the motor 203 .

In some embodiments a tool string component 301 is disposed in a terminal section 210 of the drill string 100 and may be adapted to rotate with respect to the drill string 100 while the motor 203 may be rotationally fixed to the drill string 100 . In some embodiments one or more motor like motor 203 , generators 204 , 205 , computational boards 208 , D&I package 207 , or some other electrical component, may be rotationally isolated from the drill string 100 .

In some embodiments, the motor 203 connects to the jack element 201 via a gear train 209 . The gear train 209 may couple rotation of the motor 203 to rotation of the jack element 201 at a ratio of 25 rotations to 1 rotation and may itself be rotationally fixed to the drill string 100 . In some embodiments a different ratio may be used, such as, but not limited to 15-30 rotations to 1 rotation. The gear train 209 and the jack element 201 may be part of the tool string component 301 .

FIGS. 3 through 4 are cross-sectional diagrams of embodiments of portions of the tool string component 301 . The tool string component 301 is part of the drill string 100 ( FIG. 1 ) and may be disposed within the BRA 102 . The tool string component 301 has a bore 324 adapted to house at least one component of the tool string component 301 . The jack element 201 is disposed on a distal end 302 of tool string component 301 ; and the jack element 201 substantially protrudes from a working face 303 of the drill bit 104 , and is adapted to move with respect to the bit body 304 of the bit 104 . The bit body 304 is disposed intermediate a shank 305 and the working face 303 . The bit body 304 has a bore 325 formed in it. The working face 303 has at least one cutting element 306 . In some embodiments the working face comprises a plurality of cutting elements like element 306 A-C. The drill bit 104 may advance the drill string 100 further into the formation 105 ( FIG. 1 ) by rotating, thereby allowing the cutting elements 306 to dig into and degrade the formation 105 . The jack element 201 may assist in advancing the drill string 100 further into the formation 105 by oscillating back and forth with respect to the formation 105 .

In some embodiments the jack element 201 has a primary deflecting surface 1001 disposed on a distal end 330 of the jack element 201 . The deflecting surface 1001 may form an angle 332 relative to a central axis 307 of the jack element 201 of 3 to 75 degrees. The primary deflecting surface may cause the distal end to be asymmetric. The angle 332 may create a directional bias in the jack element 201 . The deflecting surface 1001 of the jack element 201 may cause the drill bit 104 to drill substantially in a direction indicated by the directional bias of the jack element 201 . By controlling the orientation of the deflecting surface 1001 in relation to the drill bit 104 , the direction of drilling may be controlled. In some drilling applications, the drill bit 104 , when desired, may drill 3 to 20 degrees per 100 feet drilled. In some embodiments, the jack element 201 may be used to steer the drill string 104 in a straight trajectory if the formation 105 comprises characteristics that tend to steer the drill string 104 in an opposing direction.

The primary deflecting surface 1001 of the jack element 201 has a surface area of 0.5 to 4 square inches. The primary surface 1001 may have a radius of curvature of 0.75 to 1.25 inches. The jack element 201 may have a diameter of 0.5 to 1 inch, and may be made of carbide. The distal end 330 of the jack element 201 may have rounded edges so that stresses exerted on the distal end 330 may be efficiently distributed rather than being concentrated on corners and edges.

The jack element 201 may be supported by a bushing 314 and/or bearing and may be in communication with another bearing 334 . The bushing 314 may be placed between the jack element 201 and the drill bit body 304 in order to allow for low-friction rotation of the jack element 201 with respect to the drill string 100 . The bushing 314 may be beneficial in allowing the jack element 201 to be rotationally isolated from the drill bit body 304 . Thus, during a drilling operation, the jack element 201 may steer the drill string 100 as the drill bit body 304 rotates around the jack element 201 . The jack element 201 may be driven by the motor 203 ( FIG. 2 ) to rotate in a direction opposite to the rotation of the drill string 100 .

In some embodiments two position feedback sensors 308 and 313 are disposed proximate the tool string component 301 . A first sensor 308 is disposed proximate a coupler 310 on a gear train side 311 of the coupler 310 . A drive shaft 309 may rotationally couple the jack element 201 to the coupler 310 and may be disposed intermediate the motor 203 and the jack element 201 . The coupler 310 may connect the gear train 209 that is disposed intermediate the motor 203 and the drive shaft 309 to the drive shaft 309 . A bearing 312 facilitates rotation of the coupler 310 with respect to the drill string 100 .

A second sensor 313 may be disposed proximate the jack element 201 in the drive shaft 309 . Both the first sensor 308 and the second sensor 313 may be embodiments of a position feedback sensors. In some embodiments a plurality of position feedback sensors disposed proximate the tool string component 301 may all be first sensors 308 , or they may all be second sensors 313 . In other embodiments a drill string 100 may comprise no more than one position feedback sensor like sensor 308 or sensor 313 .

The drive shaft 309 has a first portion 401 secured within the bore 324 of the tool string component 301 . A second portion 402 of the drive shaft 309 is secured within the bore 325 of the drill bit 104 . The first and second portions 401 , 402 may be made of material selected from the group consisting of cemented metal carbide, steel, manganese, nickel, chromium, titanium, or combinations thereof.

The first and second portions 401 , 402 of the drive shaft 309 are connected by box 404 and pin connection 403 . The box and pin connection 403 may be adapted such that the first and second portions 401 and 402 respectively are automatically connected as the tool string component 301 is mechanically coupled to the drill bit 104 . The first portion 401 may include the box 404 ; and the second portion 402 may included the pin 405 or vise versa. A sleeve 406 may be used to form the box 404 in the box and pin connection 403 .

Referring now to FIGS. 5 through 6 , the first and second portions 401 A, and 402 A have at least one external torque transferring feature 501 , such as a spline. The box 404 ( FIG. 3 ) or sleeve 406 A of the pin connection 403 A of FIG. 5 may have an internal opening 502 adapted to interlock with the at least one external torque transferring feature 405 A and 405 B of the first and second portions 401 A and 402 A. As the first portion 401 A of the drive shaft 309 is rotated, it is believed that the at least one external feature like external feature 50 A and 501 B will allow torque to be transferred from the first portion 401 A to the second portion 402 A of the shaft 309 .

The at least one feature 501 may include shapes with surfaces to be polygonal 601 in section. In some embodiments, the first and second portions 401 A and 402 A have may be shaped to have surfaces 601 to be a Reuleaux triangle in cross-section. The sleeve 406 A of FIG. 5 has an internal opening 502 formed to mate with the surface 601 of the first and second portions 401 A and 402 B. The at least one feature 501 may have a length of 2.5 to 3.75 inches. In some embodiments the at least one feature 501 has a length of 3 inches.

The second portion 402 B of the shaft 309 in FIG. 6 may include a generally conical region 602 . The generally conical region 602 may be formed such that the at least one feature 501 of the second portion 402 B may converge into a point 603 of the conical region 602 . It is believed that the generally conical region 602 will assist in guiding the second portion 402 B of the drive shaft 309 as it is inserted into a sleeve like sleeve 406 A or box 404 ( FIG. 3 ) of the pin connection 403 .

The first portion 401 A in FIG. 5 may be press-fit to the inside of the sleeve 406 A; and the second portion 402 A may rest in the sleeve 406 A. The second portion 402 A may be press-fit to the inside or opening 502 of the sleeve 406 A; and the first portion 401 A may rest in the sleeve 406 B. Both the first and second portions 401 A and 402 A may be press-fit to the inside of the sleeve 406 A. Both the first and second portions 401 A and 402 B may rest in the sleeve 406 A. A hole 410 may be formed in the side of the sleeve 406 A to allow air to exit the sleeve 406 A as the first portion 401 A and the second portion 402 A are inserted into the sleeve 406 A.

In some embodiments some or all of the features of the first portion 401 A may be applied to the second portion 402 A and in some embodiments, some or all of the features of the second 402 A portion may be applied to the first portion 401 A.

FIG. 7 discloses a connection wherein the first and second portions 401 C and 402 C have threads 700 A and 700 B as the at least one feature 501 C. The sleeve 406 C is internally threaded. The threads 700 A of the first portion 401 C may be right-handed; and the threads 700 B of the second portion 402 C may be left-handed, or vise versa. The inside of the sleeve 406 C may have corresponding both right-handed and left-handed threads 700 A and 700 B. The threads 700 A and 700 B may cause the first and second portions 401 C and 402 C to have a reduced diameter portion 701 A and 701 B at the connection. It is believed that the reduced diameter 701 A and 701 B of the first and second portions 401 A, 402 B at the pin connection 403 C may prevent the sleeve 406 C from wandering away from the connection 403 .

FIGS. 8 through 9 disclose more embodiments for connecting portions of shaft 309 like portion 402 D and 402 E to a sleeve like sleeves 406 D and 406 E. The portions 402 D and 402 E have the at least one feature 501 D and 501 E which here are surfaces 601 D and 601 E that are polygonal in section. The surface 601 D may be star-shaped in section; and the surface 601 E is square shaped in section and sized to register with opening 502 E. The surfaces 601 D and 601 E may also be shaped to be in section one of but not limited to, triangles, rectangles, pentagons, hexagons, heptagons, octagons, or combinations thereof. The edges 801 D and 801 E of the surfaces 601 D and 601 E may be rounded so as to reduce wear and stress buildup in the connection 403 D and 403 E. The surface 601 E has a pyramid formation 602 at its end with a tip 603 .

The at least one feature 501 F may be an to be elliptical surface 1002 in section extending from the portion 402 F of shaft 309 as seen in the embodiment of FIG. 10 . The elliptical surface 1002 has a conical end 602 F with a truncated tip 603 F for insertion into the opening 502 F in sleeve 406 F.

The at least one feature 501 G of FIG. 11 shows the portion 402 G of the shaft 309 having an end 1101 with a key 1102 sized to register with a slot 1110 in the opening 502 G of the sleeve 406 G. The key 1102 may also a bead, groove, notch, teeth, or combinations thereof with similar. The key 1102 is shaped to effectively lock the second portion 402 G to the sleeve 406 G.

Referring now to FIG. 12 , the at least one feature 501 H may comprise at least one spline 1201 formed at the end of portion 402 H. The at least one spline 1201 may be selected from a group consisting of helical splines, straight splines or a combination thereof. The opening 1202 of the sleeve 406 H may be internally splined to mate with the at least one spline 1201 of the second portion 402 H.

FIGS. 13 though 14 disclose a pin connection 403 J and 403 K wherein the second portion 402 J and 402 K of the shaft 309 includes a guide 1301 J and 1301 K respectively. The guides 1301 J and 1301 K may be formed to have a shape of one of the group consisting of splines, keys, polygonal surfaces, elliptical surfaces, or combinations thereof. The first portions 401 J and 401 K may include a recess 1303 J and 1303 K adapted to receive their guides 1301 J and 1301 K. The recesses 1303 J and 1303 K have a tapered opening 1304 J and 1304 K that tapers into the recess 1303 J and 1303 K, respectively. The recesses 1303 J and 1303 K may be adapted to accommodate the shape of the guides 1301 J and 1301 K, respectively. It is believed that as the drill bit 104 J is connected to the tool string component 301 J, the tapered opening 1304 J will direct the guide 1301 J into the recess 1303 J which will in turn guide the second portion 402 J into the sleeve 406 J causing the external features to align. Similarly for the embodiment of FIG. 14 , it is believed that as the drill bit, like drill bit 104 J, is connected to the tool string component, like component 301 J, the tapered opening 1304 K will direct the guide 1301 K into the recess 1303 K which will in turn guide the second portion 402 K into the sleeve 406 K causing the portions 401 K and 402 K to align. Also shown in FIG. 13 is at least one centering element 5000 A and 5000 B may be used to help keep one or both of the portions of the drive shaft 309 centered within the bore 324 and 325 of the downhole components.

FIGS. 15 through 16 disclose an embodiment wherein the second portions 402 L and 402 M have a cemented metal carbide distal ends 1501 L and 1501 M. The carbide distal ends 1501 L and 1501 M may include the at least one external torque transferring feature like feature 501 M. The carbide distal ends 1501 L may have a cavity 1502 L. The cavity 1502 L may be formed to receive a shank 1520 of the second portion 402 L. The second portion 402 L may be brazed or press-fitted within the cavity 1502 L. The cavity 1502 L may have a rectangular, elliptical, or polygonal geometry. It is believed that a rectangular, elliptical or polygonal geometry will help prevent the braze or press-fit between the cavity 1502 L and the second portion 402 L from failing in torque.

The cavity 1502 M in FIG. 16 may be disposed in second portion 402 M. The carbide distal end 1501 M may include a shank 1602 M. The shank 1602 M may be shaped to fit within the cavity 1502 M. The shank 1602 M may be brazed or press-fitted within the cavity 1502 M. Both the shank 1602 M and the cavity 1502 M may be formed to be rectangular, elliptical, or in some other polygonal geometry to help prevent the braze or press-fit between the cavity 1502 M and the shank 1602 M from failing in torque.

Referring now to FIG. 17 , the second portions 402 N may have a section 1702 formed for connection to a sleeve like sleeve 406 . The portion 1702 has at least one coating 1701 . The at least one coating 1701 may be made from a material selected from the group consisting of gold, silver, a refractory metal, carbide, tungsten carbide, cemented metal carbide, niobium, titanium, platinum, molybdenum, diamond, cobalt, nickel, Iron, cubic boron nitride, and combinations thereof.

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.