Patent Application
20120273275
1. Field of the Invention:
The present invention relates generally to drill bit systems and mechanisms for drilling bores in a wide variety of materials such as earth materials for wells, rock materials for mining and various metal and polymer materials. More particularly, the present invention concerns the use of an outer drill bit that is rotated in any suitable manner and accomplishes drilling of a primary borehole. This invention also concerns an independently driven inner rotary drill bit, within the outer drill bit and which is arranged to simultaneously rotate and to move in orbital fashion to continuously and efficiently cut away the central region of the formation material that is not cut away by the outer drill bit. The present invention also concerns a drilling system that minimizes the weight or force that is applied during rotary drilling and permits efficient cutting of the formation material to achieve maximum drill bit penetration through the formation material.
2. Description of the Prior Art:
While the present invention is discussed in this specification particularly from the standpoint of well drilling for the oil and gas industry, it is to be borne in mind that the spirit and scope of the present invention is applicable to the drilling of bores in other materials such as hard rock in the mining industry and for the drilling of bores in metal, wood, plastics and a wide variety of composite materials. Thus, the term “formation”, within the scope of the present invention is intended to encompass most materials that are typically capable of being drilled or machined by rotary drilling apparatus.
Drilling of oil and gas wells employs a rotary system whereby a drill bit is rotated against formation material by a “drill string” to drill a wellbore. The drill string, which is composed of connected sections of tubular drill pipe, provides a method by which a fluid, typically called “drilling fluid” or “drilling mud” is pumped through the tubular drill string allowing the fluid to exit outlet openings of a drill bit at the location of formation cutting or removal. The pumped drilling fluid provides for cooling of the drill bit and serves to flush away the drill material (soil), also called “drill cuttings”, from the drill bit location in the borehole and to convey the drill material to the surface. At the surface the drill material is separated from the drilling fluid and discarded, thereby permitting the cleaned drilling fluid to be again pumped through the drill string to the drill bit assembly. This process is generally known as drilling fluid “circulation”.
Depending on the type of material to be drilled and the design of the bit, the size of the drill bit unit will differ. The earth formation materials to be drilled have different hardness and toughness. The drilling industry has developed many different types of drill bits to accommodate the drilling of boreholes of different depths and conditions. The drilling equipment may be provided in different sizes depending on the well depth and the subsurface formation conditions that are expected to be encountered. Drilling equipment may be “onshore”, such as when land based drilling rigs are employed or may be “offshore”, such as when well drilling is accomplished from floating drilling vessels or drilling systems that are operated from stationary offshore drilling platforms that are supported by the sea floor.
The speed or rate of penetration at which wellbores are drilled in earth formations determines, in part, the overall cost of the oil or gas wells. Therefore, the efficiency of the actual drilling operations determines the length of time that is required to drill the borehole and determines the time and expense of maintaining a well drilling rig at a well site. In general, the oil and gas industry has improved the “rate of penetration”, i.e. drilling speed to a fairly efficient level over the years. Poly Diamond Crystalline “PDC” drill bits have contributed materially to the general improvement of borehole drilling. Typical PDC drill bits have some disadvantages, however, which are addressed in this specification, and which limit the rate of drill bit penetration in typical formation materials. In fact, the formation penetrating rate of most current drilling systems can be significantly improved by simple changes in drill bit design and function.
There is one area in which the oil and gas industry has failed to maximize the “rate of drill bit penetration” and that area is in hard rock drilling, which is typically encountered when wells of considerable depth are drilled or when drilling relatively hard formation material that is located at or near the surface. These areas of hard rock drilling are encountered at various depths both onshore and offshore. In the case of offshore locations, the rental or amortization costs of surface drilling equipment can be 20,000 to 500,000 US Dollars per day. It is possible that the depth of the wells can exceed depths of 30,000 feet. Therefore, large areas of hard rock drilling are typically encountered in order to reach the depth of a production formation containing paying reserves of petroleum products. In hard rock materials the drilling “rate of penetration” can be as low as one foot per hour when conventional PDC drill bits are employed. Therefore, the cost of wells can be as much as 20,000 US Dollars per foot of drilling, thus being potentially detrimental to the desired return of investment. Clearly there has been a need for a considerable period of time to provide a system for well drilling in a hard rock environment that provides for significant improvements in the rate of drill bit penetration, so that wells can be drilled and completed for production at costs that are not prohibitive.
As can be understood, any improvement in the drilling speed will significantly reduce the cost of well drilling and completion. The drilling of hard rock is being conducted at the present time through the use of “PDC” Poly Diamond Crystalline bits. The PDC bit is presently the best method to drill hard rock using PDC bits and associated systems. PDC bits employ a machining method or formation cutting action in the removal of relatively hard formation materials. As in metallic machinery or milling, a specific depth of cut is determined, (i.e. depth of cut). Similar to the metal cutting action in metallic machining, the bore material is removed by the cutting elements of the drill bit as the bit is rotated against the formation material. The number of revolutions of a drill bit per unit time and the depth of cut causes the mill to machine the bore material at a desired rate of penetration.
Drilling of oil and gas formations employs a system to remove the formation material by machinery. Therefore, the speed of rotation and “depth of cut” determines the “rate of drill bit penetration” into the formation. The above stated method is considered to be the “state of the art” at the present time. However, during drill bit rotation the cutting elements of conventional PDC drill bits achieve efficient cutting of formation material near the outer periphery of a drill bit because cutter speed relative to the formation material is optimum at the outer peripheral region of the bit. This formation cutting efficiency degrades in relation to the distance of the PDC cutting elements from the axis of rotation of the drill bit. At the inner region of a conventional PDC bit the cutter elements have much slower cutting speed relative to the formation material, which causes the efficiency of the formation cutting activity of the innermost cutting elements to be diminished. Due to the inefficient cutting capability of the cutting elements near the central portion of a drill bit the central region of the wellbore being drilled is not cut away efficiently and serves to resist forward movement of the drill bit through the formation even though the cutter elements of the outer portion of the drill bit cutting face have the capability for efficient formation cutting activity. The inefficiently cut central region of the wellbore functions as a drilling resistance region by propping up or resisting forward movement of the entire drill bit, thus retarding the rate of penetration that could otherwise be achieved. Thus, the inefficiently cut central region of a the formation being drilled to form a borehole is referred to as a “resistance region”.
During wellbore drilling as hard formation material is encountered roller cone type drill bits are typically employed for the drilling process. The roller cones of these bits have teeth that are typically faced with a hard wear resistant material such as tungsten carbide. The roller cones may also have tungsten carbide inserts when very hard formation material is encountered. As the roller cones rotate the teeth of the cones essentially chisel, chip or flake away the formation material rather than cutting it away. As certain types of hard formation material is encountered, PDC drill bits are employed and have multiple diamond cutting elements that are positioned cut away the formation material as the drill bit is rotated. As even harder formation material is encountered drill bits are employed having cutting faces that are formed of a metal substrate in which diamond cutting elements are embedded. As drilling progresses the metal substrate material will be worn away by the abrasive action of the formation material, exposing other embedded diamond cutting elements. These embedded diamond type drill bits are typically driven at higher rotary speed than other drill bits.
Regardless of the type of drill bit that is employed for drilling in hard formations the cutting elements at the outer portions of the cutting face are rotated at a speed for efficient drilling, but the innermost cutting elements, due to their much slower cutting speed, accomplish very little cutting of the formation material. Thus, as the drill bits are rotated against the formation material an inefficiently cut region of the formation at the center region of the wellbore remains and resists drill bit penetration. To enhance the efficiency of well drilling the operator of the drilling rig will typically apply relatively high drill stem weight to the drill bit so that the resistance region of the formation material being drilled is crushed by the weight of the drill string and drill bit rather than being cut away. A drill bit weight in the range of about 20,000 pounds, for example, is the typical weight for efficient cutting of the formation material by the cutting elements at the outer portion of the drill bit. Because of the efficiency retarding effect at the central resistance region of the wellbore, the driller may need to apply a drill bit weight in the range of 70,000 pounds, for example, to accomplish continual crushing of the resistance region of the formation that results due to the degradation of cutting efficiency that results from the relatively slow movement of the central cutting elements against the formation. It is desirable therefore to provide a method of formation drilling which accomplishes efficient cutting of the formation material at both the central and outer regions of a wellbore, thus eliminating the need for application of formation crushing drill bit weight and permitting the cutting elements at both the outer region and the central region of the drill bit to accomplish efficient cutting of the formation material, thus resulting in efficient drill bit penetration.
Drilling systems for deep wells typically employ a drill collar in the drill string above the drill bit. The drill collar is typically composed of stiff tubular material such as steel that resists flexing as drilling weight is applied via the drill string. The drill collar may have a length in the range of 1000 feet for deep well drilling. When a sufficiently high drill string weight is applied for crushing the formation material at the central region of the wellbore, as indicated above, even a stiff drill collar will be flexed to the point of having a portion of it establish contact with the wellbore wall. When this condition occurs the cutting face of the drill bit will be oriented at a slight angle with respect to the centerline of the drill collar, thus causing the wellbore being drilled to deviate slightly from the intended centerline of the intended wellbore. It is desirable, therefore, to provide a method for well drilling that permits the use of a sufficiently low drill bit weight that the drill collar resists any tendency for flexing and permits efficient straight ahead drilling.
The invention which is described in this specification and illustrated in the appended drawings teaches a different and improved approach to the drilling of oil and gas boreholes, whereby the “rate of penetration” of a drilling unit is significantly enhanced and the cost of well drilling is minimized.
It is a principal feature of the present invention to provide a novel well drilling system for hard formation drilling which employs a drilling unit having an outer drill bit that is rotated by a primary power source and within an passage of the outer drill bit an inner drill bit is rotated by a secondary power source and has both rotation and orbital movement relative to the outer drill bit for continuously cutting away formation material at the central region of the wellbore being drilled while the outer drill bit efficiently cuts away the major portion of the formation material that is removed to define the wellbore.
It is another feature of the present invention to provide a novel well drilling system having an outer drill bit driven by the rotary drill string and an inner orbital drill bit within the outer drill bit which is driven by the hydraulic system of a drilling rig, such as the hydraulic pumps that pump drilling fluid through the drill string from the surface and which achieves rapid drill penetration by intregating the full horsepower of the rotary drill stem at the drill bit assembly for driving the outer drill bit and the full horsepower of the hydraulic system of the drilling rig at the inner drill bit.
It is another feature of the present invention to provide a novel well drilling system for hard formation drilling which employs an outer drill bit having cutter elements and is rotated at a desired speed for efficient penetration into the formation material and an inner drill bit which can be rotated at a greater speed that the outer drill bit and is moved orbitally by the outer drill bit for continuously and efficiently cutting away the formation material of the central region of the borehole being drilled.
It is another feature of the present invention to provide a novel borehole drilling system for hard formation drilling wherein an outer drill bit, driven by a primary power source, defines a primary axis of rotation and defines an inner drill bit passage intersecting the cutting face of the outer drill bit and having an inner drill bit within the inner drill bit passage that is driven by a secondary power source and defines a secondary axis of rotation being laterally offset from the primary axis of rotation and being of sufficient circular dimension that an outer portion of the inner drill bit passes across the primary axis of rotation and cuts away formation material at the central region of the borehole being drilled.
It is also a feature of the present invention to provide a novel borehole drilling system for hard formation drilling wherein an inner drill bit within an inner bit passage of an outer drill bit can be designed to rotate at a faster rotary speed as compared with the rotary speed of the outer drill bit and may be rotated in the same rotary direction or in the opposite rotary direction as compared with the direction of rotation of the outer drill bit.
Briefly, the various objects and features of the present invention are realized through the provision of an outer PDC drill bit having a cutting face to which is fixed a multiplicity of PDC cutter elements that are oriented for cutting away hard rock formation material to drill a borehole. Within the outer drill bit is defined an inner bit passage having an inner PDC drill bit that is rotatably driven by a separate power source such as a fluid energized turbine or mud motor. The rotation speed of the inner drill bit is variable and is typically significantly faster than the rotary speed of the outer drill bit. The inner drill bit is typically driven by a shaft that is rotated by the rotor of a mud motor by drilling fluid that is pumped through the space between the rotor and the rubber stator of the motor. The drilling fluid powering the turbine or mud motor is then discharged into the borehole from drilling fluid outlet passages of the inner drill bit for the purpose of cooling and for drill cutting removal. The drilling fluid can also be discharged into the borehole from drilling fluid outlet passages of the outer drill bit if desired.
The inner bit passage is located eccentric with respect to the axis of rotation of the outer drill bit thus causing the inner drill bit to have orbital motion within the wellbore as it is driven rotationally by a secondary power source. This orbital motion can be caused by an offset relation of the outer drill bit with respect to its drill collar or drill stem or can result from offset location of the cutting face of the inner drill bit relative to the outer drill bit or by an angular relation of the axis or rotation of the inner drill bit relative to the axis of rotation of the outer drill bit. As the outer drill bit rotates against the formation its cutter elements cut away the major portion of the formation material at the outer region of the wellbore being drilled. The orbital rotational movement of the inner drill bit, together with its high speed rotational movement, clockwise or counter-clockwise, causes efficient cutting of the inner region of the formation material, thus eliminating the formation material that typically forms the resisting region that is described above. With the inner resisting region of the formation material continuously and efficiently removed by the cutting elements of the inner drill bit, the PDC cutting element from the central region toward the outer region of the cutting face of the outer drill bit will have exceptional formation cutting efficiency across its entirety. The drilling system of this invention is capable of achieving rapid penetration into the formation due to the efficiency of its formation cutting activity across its entire cutting face. Efficient drilling penetration of the drill bit is also enhanced by providing the full horsepower of the rotary drive mechanism of the drilling rig for rotation of the outer drill bit and also providing the full horsepower of the hydraulic system of the drilling rig for rotation of the inner drill bit. Thus the drilling system essentially provides double or multiple horsepower at the drill bit assembly for enhancing drill bit penetration.
Thus, the present invention relates generally to drill bit systems and mechanisms for drilling bores in a wide variety of materials such as earth materials for wells, rock materials for mining and various metal and polymer materials. More particularly, the present invention concerns the use of an outer drill bit that is rotated in any suitable manner and accomplishes drilling of a primary borehole. Within the outer bit is recessed an inner drill bit that is capable of rotating at a different, typically faster speed as compared with the rotary speed of the outer drill bit. This invention also concerns location of the inner drill bit in eccentric relation with respect to the axis of the outer drill bit so that during rotation of the primary drill bit the drilling face of the inner orbital bit is caused to pass across the central formation region of the primary wellbore and continuously cuts away the central penetration resisting region of the formation that typically results from the drilling inefficiency that typically results from rotation of a conventional PDC drill bit.
Typically, wells are drilled for oil and gas production by rotating a drill stem in the clockwise direction. The inner drill bit may also be rotated in the clockwise direction, typically at a greater rotational speed as compared with the rotation speed of the outer drill bit. In the alternative, however, the inner drill bit may be driven in a rotational direction that is opposite the rotational direction of the outer drill bit. For example, the outer drill bit may be rotated in a clockwise direction and the inner drill bit may be driven in a counter-clockwise rotational direction. If a drilling system is designed to rotate an outer drill bit in a counter-clockwise rotational direction, then the inner drill bit could be rotated clockwise. However, virtually all well drilling systems are designed for clockwise rotation of a drill bit, so the counter rotational direction for the inner drill bit is counter-clockwise as viewed from a drilling rig floor.
At the present time “state of the art” PDC drilling methods are being employed in all areas of the world, via land based drilling systems and subsea drilling systems. The invention described herein employs a specific downhole assembly, employing PDC cutters. The basic theory of this invention is to provide a method in which a center, centerless borehole is formed. The center hole provides a method in which the center area is removed by a separate drilling operation, which is efficient and removes only a small percentage of the total borehole to be formed. The center hole removes approximately 4%-25% of the required final borehole volume.
The center, centerless borehole is generated by a special bit which can operate at a high rotational speed. The high rotational speed can set the maximum “rate of penetration” of the drilling operation. The high speed quality of the center, centerless hole bit is supported by the pattern in which the center, centerless bit is simultaneously rotated about its longitudinal axis and also is rotated orbitally about the longitudinal axis of the primary or outer drill bit. The orbit motion of the inner or secondary drill bit is provided to cause the center portion of the borehole being drilled to be void of an actual center point. The orbit path of the center, centerless drill bit system is provided by an off-center outer or reamer drill bit assembly which has dimensions equal to the internal dimension of the desired final borehole. The reamer assembly removes the remaining and the majority volume of material to form the finished borehole. This invention incorporates separate power sources which supports the center, centerless bit and reamer assembly.
The present invention is described as per the following statement:
“The downhole drilling system employs a dual speed, dual torque power system. The drilling system employs a method which drills a center, centerless hole using a high rotating speed. The center, centerless drill bit path travels in an orbital orbiting pattern due to the rotary motion of the drill stem and is simultaneously rotated in a selective direction by the hydraulic system of the drilling rig. The reamer unit which guides the final borehole is offset, which causes the orbiting pattern of the center, centerless drill bit.”
So that the manner in which the above recited features, advantages and objects of the present invention are attained and can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the preferred embodiment thereof which is illustrated in the appended drawings, which drawings are incorporated as a part hereof.
It is to be noted however, that the appended drawings illustrate only a typical embodiment of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.
In the Drawings:
Referring now to the drawings and first to
According to the preferred embodiment of the present invention the horsepower of a primary rotary drive mechanism, being powered by the rotary drive mechanism 2 at the surface, is employed to drive a primary or outer drill bit. Simultaneously the horsepower of the hydraulic system of the drilling rig, i.e., the drilling fluid pumps 7 and the hydraulic fluid control mechanism, is employed to provide for separate rotary driving of a secondary or inner drill bit of the drilling assembly. This feature essentially provides the full horsepower of the mechanically energized rotary drive mechanism of the drill string and the full horsepower of the fluid energized rotary drive mechanism for the simultaneous energization of the outer and inner drill bits of the drill bit assembly. Moreover, this feature also permits the outer and inner drill bits to be rotated at different speeds and different directions of rotation as desired. The present invention therefore provides a dual speed, dual torque arrangement for highly efficient drilling.
The drilling system of the present invention employs a dual speed, dual torque power system and employs a method which drills a center, centerless borehole with the inner drill bit moving in an orbital pattern and using a high inner bit rotating speed. The inner drill bit is movable in an orbital pattern for efficiently cutting away the central portion of the formation material primarily due to the offset relation of the inner drill bit with the outer drill bit. The outer drill bit can be offset with respect to its axis or rotation or the inner drill bit can be laterally offset or eccentric with respect to the axis of rotation of the outer drill bit. Alternatively, the outer and inner drill bits can be arranged concentrically, with the outer drill bit removing a major portion of the formation material, without drilling at the central portion of the borehole, while the inner drill bit is rotated at the same or different speed and the same or different direction or rotation to effectively remove the centermost portion of the formation material.
With reference to
As shown best in
Within the stabilizer sub 34 of the drilling system is provided a bearing chamber shown generally at 56 which contains bearing assemblies to provide for rotary support of the secondary or inner rotary bit 54, which may also be described as a “core removal bit”. The bearing assembly which is shown generally at 56 has upper and lower bearing packs, the upper bearing pack 58 being secured relative to the upper annular shoulder 60 of an internal flange 62 of the bearing chamber 56 by an upper bearing pack outer compression spacer 64. An upper bearing jam collar 66 is mounted within the bearing chamber 56 by a threaded connection 68 and serves to secure the upper bearing outer compression spacer against an internal annular shoulder 70. The outer compression spacer 64 of the upper bearing pack engages and retains an outer radial bearing assembly 72 and a thrust bearing assembly 74 of the upper bearing pack.
An inner compression spacer 76 of the upper bearing pack assembly is secured relative to the tubular inner bit mandrel 42 by drilling fluid flow through tube lock nuts 78 to maintain desired positioning of an inner radial bearing pack member 80 that in turn bears against and secures an upper thrust bearing assembly 82 in seated relation with the annular shoulder 60. Below the annular internal flange 62 is located a lower thrust bearing assembly 84 that is retained against a lower annular shoulder 86 of the annular internal flange 62 by the upwardly facing shoulder 88 of a bearing retainer 90. The bearing retainer 90 extends into an inner drill bit chamber 92 of the primary or outer drill bit 52 and is in turn supported in place by a spacer member 94. The bearing retainer and spacer member are preferably composed of a hardened or wear resistant material such as Stellite or any of a number of commercially available hard-facing materials. The secondary or inner rotary bit member 54 is shown to have a generally cylindrical external configuration which is defined by an exterior layer or coating 96 of wear-resistant material. The inner drill bit 54 may be formed integrally with the tubular inner bit mandrel 42 as shown, or if desired may be connected with the tubular inner bit mandrel by a threaded connection, by welding or my any other suitable means. The upper end of the tubular inner bit mandrel may be threaded to the coupling 40 or may be secured in any other manner that will permit the rotatable power transmission flex shaft 30 to rotate the tubular inner bit mandrel 42 and the inner rotary bit member 54.
As shown in
The bottom wall structure 102 of the primary drill bit 52 defines a central opening 114 of generally circular configuration and further defines a plurality of lateral relief areas 116 that extend from the central opening and provide for drilling fluid flow during drilling activity. During rotation of the primary drill bit 52 about its axis of rotation 118 in response to rotation of the drill string, since no formation cutting elements 108 are located at the center portion of the cutting face 103 due to the presence of the central opening 114, a small core of uncut formation material will be present within the central opening. The lateral relief areas 116 will provide for the flow of drilling fluid past this small core and will provide for cooling of the cutting elements and the cutting face and will also transport drill cuttings away from the formation material being drilled.
As is also shown in the longitudinal sectional view of
As best shown in
With reference to
A secondary or inner drill bit shown generally at 168 is supported for rotation by the inner bit mandrel 42 and the bearing assembly 56 for rotation by the hydraulic motor 16 within the inner drill bit chamber or passage 156 of the outer drill bit 152. The inner drill bit defines a cutting face 170 that is defined by a plurality of spaced, curved radial lands 172 and spaced grooves or relief areas 174 defined between the lands. The lands 172 define leading edges 176 having a multiplicity of inner bit cutting elements 178 being mounted thereto in position and orientation for cutting away an inner region of formation material as the inner bit is rotated independently of the outer drill bit about its axis of rotation 161 as it is simultaneously rotated orbitally about the axis 162 of rotation of the outer drill bit. It should be borne in mind that the orientation of the curved radiating lands will determine the direction of rotation of the inner drill bit as it cuts away the inner region of the formation material of the borehole. If the direction of inner bit rotation is opposite that of the outer drill bit then the orientation of the curved radiating lands and the location of the leading edges of the lands will be opposite that of the outer drill bit. The fluid flow passage 44 of the inner bit mandrel 42 is intersected by a plurality of angulated branch fluid distribution passages 179 that intersect the cutting face 170 and ensure adequate flow and distribution of drilling fluid to both the inner drill bit and the outer drill bit. Since the central portion of the formation material is continuously cut away by the inner drill bit, the outer drill bit is enabled to achieve efficient cutting of the majority of the formation material and the dual speed, dual torque drilling system will penetrate the formation material at a greater rate and will run much cooler than is currently possible with standard PDC drill bits and will have significantly extended service life.
In
Referring now to
To minimize the excessive heat generation problem of conventional drill bits, which results from poor formation cutting characteristics of the cutting elements that traverse the central portion of a borehole being drilled at a much slower cutting speed than is desirable, the drilling system set forth in
The embodiment of
A secondary or inner drill bit 244 which has a cylindrical side wall that is clad with wear resistant material 246, such as is described above and shown at 96 in
In
The drill bit body 270 defines an inner bit chamber 274 of generally cylindrical configuration having a secondary or inner drill bit 276 positioned for rotation therein. The inner bit chamber 274 is eccentrically located relative to the center-line or axis of rotation 278 of the drill bit body 270 so that the downwardly facing opening 280 at the intersection of the inner bit chamber 274 with the cutting face 282 of the outer drill bit 268 will be rotated in orbital fashion about the axis of rotation 278 of the outer drill bit as the outer drill bit is rotated by the drill string. The inner drill bit 276 is mounted to an inner bit mandrel 284 which is supported for rotation within a tubular motor housing 286 of a hydraulic motor, shown generally at 288, by means of a bearing assembly. The stabilizer 266 defines a lower internal transverse support wall 290 having a housing mounting opening 292 within which the lower end portion of the tubular motor housing 286 is positioned for location and support.
The inner bit mandrel 284 and the inner drill bit 276 are rotatably driven about an axis 294 of inner drill bit rotation by the fluid energized hydraulic motor 288. The rotation axes 278 and 294 of the outer and inner drill bits are oriented in substantially parallel relation due to the laterally offset positioning of the hydraulic motor 288 and the inner drill bit 276 within the tubular housing 262. The lateral spacing between the rotation axes 278 and 294 determine the orbital excursion of the cutting face 296 of the inner drill bit as the outer drill bit 268 is rotated.
During this orbital movement the cutting face of the inner drill bit causes efficient cutting of the formation material at the central region of the borehole being drilled, thereby permitting the cutting face 282 of the outer drill bit to accomplish efficient cutting of a majority of the formation material. The rotation speed and torque of the outer drill bit is controlled by the rotational speed of the drill string while the rotational speed and torque of the inner drill bit is controlled by the volume and pressure of the drilling fluid that flows through the hydraulic motor. Typically the rotational speed of the inner drill bit is from 2 to 8 times faster than the rotational speed of the outer drill bit. Thus each of the dual drill bits is provided with the full torque that is generated by its individual rotary drive mechanism.
The outer drill bit drive mandrel 326 defines an enlarged tubular portion 332 which is shown at the lower portion of
As shown in
Within the stabilizer sub 346 is provided a bearing assembly shown generally at 370 which provides bearing support for a secondary drill bit mandrel 372 which is connected in driven relation with the power transmission flex shaft 374 and the motor output shaft 376 of the secondary hydraulic motor 340. The outer bit body 352 defines a generally cylindrical inner bit chamber 378 within which is located a secondary or inner drill bit 380 which is rotatably driven by the inner bit mandrel 372 in response to fluid energized operation of the secondary hydraulic motor 340. The inner drill bit defines a generally circular cutting face 382 having a plurality of radiating curved lands 384 and grooves 386. The radiating lands each define a leading edge 388 that may be of curved configuration as shown in
The outer drill bit body 352 is located in eccentric relation with the axis that is defined by the tubular housing 342 and is thus rotated about a longitudinal axis 392. The inner bit chamber 378 defines a central longitudinal axis 394 that is laterally offset form the longitudinal axis 392, thus causing the inner drill bit 380 to have orbital rotation movement about the axis 392 as the outer drill bit is rotated by the primary hydraulic motor. The circular cutting face 382 of the inner drill bit is disposed in spaced relation with the internal surface of the wall 356 but is positioned so that a portion of the cutting face 382 overlies the central opening 358. Thus, as the inner drill bit is moved orbitally due to rotation of the outer drill bit the small core that is left by the outer drill bit is continuously cut away by the cutting elements of the inner drill bit. Since the radially outer portion of the cutting face of the inner drill bit achieves cutting of the formation core, the cutting elements of the inner drill bit have efficient cutting speed with respect to the formation material and thus inner bit formation cutting occurs at optimum efficiency and without any tendency to become overheated by the formation cutting activity. Moreover, formation cutting by the inner drill bit causes the outer drill bit to also achieve optimum efficiency since its cutting elements are not required to cut away the formation material at the central portion of the borehole. The primary and secondary hydraulic motors can be set to rotate at optimum speed and torque for optimum formation cutting capability.
The partial sectional views of
As shown in the lower portion of
As borehole drilling progresses by rotation of the outer drill bit by its primary hydraulic motor the cutting elements 445 will cut away a major circular portion of the formation material, leaving a central portion of the formation material uncut. The cutting elements of the outer drill bit will be moved at an optimum range of cutting speed for formation cutting and for minimum heat generation during cutting. Simultaneously, the inner drill bit will be rotated by the inner bit drive mandrel 434 in response to operation of the secondary hydraulic motor of the drilling system. During drilling the cutting face of the inner drill bit will encounter and cut away the remaining central portion of the formation material. The inner drill bit will be rotated by its independent hydraulic motor as a speed of rotation that will move the formation cutting elements of the inner drill bit at a optimum cutting speed relative to the formation material for efficient cutting activity and minimal heat generation.
With reference to
Within the tubular stabilizer housing 452 is mounted a support partition 466 having a motor positioning opening 468 within which is positioned the upper end portion of a secondary hydraulic motor shown generally at 470. A similar support partition 465 within the lower end of the stabilizer sub defines a support opening 467 within which is received the lower end portion of the hydraulic motor 470. The secondary hydraulic motor incorporates a cross-over sub 472 at its upper end for channeling a portion of the drilling fluid flow into the upper fluid chamber 474 of the secondary hydraulic motor and has an internal lobed stator 476 and lobed rotor 478 which responds to fluid flow to develop rotary motion of the rotor. The secondary hydraulic motor 470 has an elongate tubular motor housing 480 which contains a bearing assembly, not shown, for rotational support of an inner drill bit drive mandrel 482. A secondary or inner drill bit 484 is integral with or connected with the inner drill bit drive mandrel serves to impart rotary motion to the inner drill bit in response to fluid energized operation of the secondary hydraulic motor 470. The inner drill bit chamber 464 is protected by wear resistant sleeves 486 and 488 and an exterior wear resistant sleeve or hardfacing 490 is employed for minimizing wear of the inner drill bit during drilling activity.
The outer drill bit has an axis of rotation 492 which is concentric with the tubular housing 452 and the stabilizer sub. Due to the angulated position of the secondary hydraulic motor within the housing 452 the secondary drill bit 484 is rotatable about an axis 494 that is disposed in angular relation with the axis of rotation 492. This arrangement positions the cutting face 496 of the inner drill bit in laterally offset relation with the axis of rotation 492 of the outer drill bit. The inner drill bit chamber 464 intersects the cutting face 497 of the outer drill bit at a position that is off center with respect to the axis of rotation 492. By virtue of its off center positioning as the outer drill bit is rotated by the primary hydraulic motor the inner drill bit will be rotated orbitally about the axis 492. Simultaneously the inner drill bit will be rotated about its axis 494 either clockwise or counter-clockwise depending on the design of the drilling system. The cutting elements 498 of the outer drill bit will cut away a majority of the formation material to form the borehole, leaving a small central portion of the formation material. The cutting elements 495 of the inner drill bit are position essentially co-extensive or substantially flush with the cutting elements 497 of the outer drill bit and accomplish continual cutting of the remaining formation material at the central region of the borehole. This feature permits the outer drill bit to be rotated at an optimum speed for efficient cutting of the formation material without necessitating the generation of excessive heat and permits the inner drill bit to be rotated at its optimum speed for efficient cutting of the formation material and for minimizing heat generation.
Referring to
Within the upper portion of the tubular housing 508 a transverse support partition 528 is fixed and defines a support opening 530 within which the upper cross-over sub 532 of a secondary hydraulic motor shown generally at 534 is secured. The secondary hydraulic motor 534 is located along an inner surface 536 of the tubular housing 508 and thus defines a center-line or axis of rotation 538 that is disposed in parallel relation with a center-line or axis of rotation 540 of the tubular housing 508, the stabilizer 512 and the primary or outer drill bit 514. An internal support partition 542 is located within the lower portion of the stabilizer 512 and defines a support opening 544 within which a lower portion of the tubular housing 546 of the secondary hydraulic motor is secured. Within the tubular housing 546 is provided a tubular internally lobed stator member 548 and an elongate lobed rotor member 550. Drilling fluid which enters the secondary hydraulic motor from the fluid passage 552 flows through the secondary hydraulic motor and imparts rotation to the rotor member 550. The rotor member has an output shaft that is coupled in driving relation with the inner drill bit drive mandrel 526 thus providing for rotation of the inner drill bit within the inner drill bit chamber with the rotational speed and torque that is determined by the flow of drilling fluid.
The inner drill bit drive mandrel 526 defines a central fluid flow passage 554 that conducts the flow of drilling fluid through the mandrel and through the inner drill bit. A plurality of angulated branch passages 556 within the inner drill bit intersect the central fluid flow passage 554 and provide for even distribution of the flowing drilling fluid to the cutting faces of both the inner drill bit and the outer drill bit. As is evident in
Rotation of the outer drill bit will cause the cutting elements 558 to cut away a major portion of the formation material of the borehole, leaving a small central region uncut. Due to the laterally offset position of the inner drill bit chamber 522, upon rotation of the outer drill bit 514 the inner drill bit will be caused to rotate orbitally, with the axis of rotation 540 of the orbit being the center of rotation 540 of the outer drill bit. This feature permits the cutting elements of the outer drill bit to have an optimum range of cutting speed relative to the formation material for efficiency of cutting activity, without generation of excessive heat. The cutting elements of the smaller diameter inner drill bit will also be caused to have movement at an optimum range of cutting speed relative to the formation material with minimal heat generation. The rate of penetration of this drilling system into the formation material is exceptional and the resulting service life of the drilling system will be significantly extended in comparison with conventional drill bits.
In view of the foregoing it is evident that the present invention is one well adapted to attain all of the objects and features hereinabove set forth, together with other objects and features which are inherent in the apparatus disclosed herein.
As will be readily apparent to those skilled in the art, the present invention may easily be produced in other specific forms without departing from its spirit or essential characteristics. The present embodiment is, therefore, to be considered as merely illustrative and not restrictive, the scope of the invention being indicated by the claims rather than the foregoing description, and all changes which come within the meaning and range of equivalence of the claims are therefore intended to be embraced therein.
