Patent Application
20090152011
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, so as 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 following steps are carried out: the model is reduced so to retain only pertinent modes, at least two values Rf and Rwob are calculated, Rf being a function of the principal oscillation frequency of weight on hook WOH divided by the average instantaneous rotating speed at the surface, Rwob being 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, such sub having 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.
In one aspect of the present invention, a section of a drill string has a drill bit with a body intermediate a shank and a working face, the working face having 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 rotary source. 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 may comprise a sleeve. The sleeve may comprise an internal geometry adapted to interlock with an at least one external feature of 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 surfaces, elliptical 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.
Referring now to
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 203, generator 204, 205, computational board 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 geartrain 209. The geartrain 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 geartrain 209 and the jack element 201 may be part of the tool string component 301.
In some embodiments the jack element 201 comprises a primary deflecting surface 1001 disposed on a distal end of the jack element 201. The deflecting surface 1001 may form an angle relative to a central axis 307 of the jack element 201 of 3 to 75 degrees. The angle 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, 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 may comprise 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 comprise carbide. The distal end of the jack element 201 may have rounded edges so that stresses exerted on the distal end 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 at least one bearing. 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 to rotate in a direction opposite the drill string 100.
In some embodiments two position feedback sensors 202 are disposed proximate the tool string component 301. A first sensor 308 is disposed proximate a coupler 310 on a geartrain 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 geartrain 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 position feedback sensors 202. In some embodiments a plurality of position feedback sensors 202 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 202.
The drive shaft 309 comprises at least two portions, a first portion 401 comprising the portion of the drive shaft 309 secured within the bore 324 of the tool string component 301 and a second portion 402 comprising the portion of the drive shaft 309 secured within the bore 325 of the drill bit 104. The first and second portions 401, 402 may comprise a 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 are connected by a box and pin connection 403. The box and pin connection 403 may be adapted such that the first and second portions 401, 402 are automatically connected as the tool string component 301 is mechanically coupled to the drill bit 104. The first portion 401 may comprise the box 404 and the second portion 402 may comprise 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
The at least one feature 501 may comprise polygonal surfaces 601. In some embodiments the first and second portions 401, 402 may comprise a Reuleaux triangle surface 601 or cross-section. The sleeve 406 may comprise an internal geometry 502 adapted to mate with the polygonal surface 601 of the first and second portions 401, 402. 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 may comprise 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 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 of the drive shaft 309 as it is inserted into the sleeve 406 or box 404 of the connection 403.
The first portion 401 may be press-fit to the inside of the sleeve 406 and the second portion 402 may rest in the sleeve 406. The second portion 402 may be press-fit to the inside of the sleeve 406 and the first portion 401 may rest in the sleeve 406. Both the first and second portions 401, 402 may be press-fit to the inside of the sleeve 406. Both the first and second portions 401, 402 may rest in the sleeve 406. A hole may be formed in the side of the sleeve 406 so as to allow air to exit the sleeve 406 as the first portion 401 and the second portion 402 are inserted into the sleeve 406.
In some embodiments some or all of the features of the first portion 401 may be applied to the second portion 402 and in some embodiments some or all of the features of the second 402 portion may be applied to the first portion 401.
The at least one feature 501 may comprise an elliptical surface 1002 such as the embodiment disclosed in
Referring now to
The cavity 1502 may be disposed in second portion 402. The carbide distal end 1501 may comprise a shank 1602. The shank 1602 may be adapted to fit within the cavity 1502. The shank 1602 may be brazed or press-fitted within the cavity 1502. Both the shank 1602 and the cavity 1502 may comprise a rectangular, elliptical, or polygonal geometry to help prevent the braze or press-fit between the cavity 1502 and the shank 1602 from failing in torsion.
Referring now to
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.
