STEERABLE WELL DRILLING SYSTEM

Abstract

A steerable dual drilling bit having an outer reamer bit defining a central opening and having an inner core removal bit being rotatably driven by a mud motor that is supported within a tubular housing by the outer reamer bit. The dual drilling bit is capable of being threaded to the bit box of a rotary drill string or a straight or bent housing drilling system. The dual drilling mechanism is of sufficiently limited length that it is capable is being efficiently steered for directional drilling. The reamer and core removal bits are arranged to continuously cut away a formation core and to employ the core for rotational stabilization of the reamer bit during drilling.

Description

RELATED PROVISIONAL APPLICATION

Applicant hereby claims the benefit of U.S. Provisional Patent Application No. 61/886,498, filed on 3 Oct. 2013 by Edwin J. Broussard, Jr. and entitled “Steerable Well Drilling System”, which provisional application is incorporated herein by reference for all purposes.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates generally to well drilling systems and particularly to well drilling mechanisms having a reamer bit defining a central opening within which a formation core is permitted to enter as the reamer bit progresses into the formation. The well drilling system of the present invention has a core removal bit that is located within the reamer bit and is independently rotated for continuously cutting away the core of formation material that is not cut away by the rotating cutters of the reamer. The present invention also concerns dual drill bit well drilling systems having a housing to which is mounted a reamer bit and having a mud motor mounted to the reamer bit and positioned within the housing and disposed in driving relation with a core removal bit that is rotatable within the reamer bit for continuous core removal. Both the reamer bit and core removal bit preferably incorporate polycrystalline diamond (PDC) formation cutting elements that are supported by a matrix material but may also incorporate hardened metal cutting elements or rotary cone cutting elements, if desired. Even further, the present invention concerns a wellbore drilling system having a reamer that leaves a central core of formation material during drilling and having a smaller, mud motor driven core removal bit that it either located concentrically or eccentrically with respect to the reamer bit for efficiently removing the remaining core material. The present invention particularly concerns a method for well drilling in consolidated formations by mounting a short straight or directional mud motor powered dual rotary bit well drilling mechanism, typically having a length in the range of about 4′, below the bend structure of a typical bent housing well drilling mechanism and selectively orienting the bent housing and short drilling system for directional steering of the wellbore being drilled.

2. Description of the Prior Art

Dual PDC well drilling systems having an external reamer bit and an interior mud motor driven core removal bit are disclosed by U.S. Pat. No. 7,562,725 of Edwin J. Broussard, Jr. and Herman J. Schellstede. A reamer bit is mounted to and rotated by a rotary drill string that extends from a rotary drilling rig at the surface. The core removal bit is rotated by a mud motor that is located within a drilling unit, the mud motor being driven by the flow of drilling fluid that is pumped through the drill string from the surface. Another somewhat similar drilling system is disclosed by U.S. Pat. No. 8,201,642 of Steven J. Radford, et al, wherein a reamer bit is rotated in one direction by the drill string and a concentric bit is located within the reamer bit and is rotated in a counter rotational direction by a downhole motor such as a positive displacement motor (PDM). It is noted that the smaller centrally located bit is located entirely within the outer reamer bit, with its cutting elements engaging the central portion of the formation within which the wellbore is being drilled. The drill cuttings of the smaller bit will tend to build up on the cutting interface of the smaller bit, thus further interfering with its formation cutting capability. Though these types of drilling systems will function and achieve wellbore drilling, typically no provision is made for controlling the delivery of drilling fluid for reamer drilling, core removal bit drilling, mud motor operation and bearing cooling for the mud motor and other components of the drilling system.

During well drilling with a conventional PDC bit, it is known that the most central of the PDC cutter members will be rotated against the formation being drilled at a slower speed as compared with the PDC cutter members that are located further from the center portion of the bit. This difference in formation cutting speed is due to the circumferential distance each of the PDC cutter members travel during each revolution of drill bit rotation. The cutter members at the outer periphery of a drill bit travel at a greater formation cutting speed than the cutters near the center of the bit. The slower cutting speed of the more centrally located cutters causes inefficient formation cutting at the central portion of the borehole being drilled, so that the central portion of the drill bit cutting face tends to crush, rather than cut the formation material, and thus retards the overall penetration rate of the bit. It is considered desirable therefore, to employ the benefits of PDC cutter members for rotary well drilling without having the well drilling efficiency hampered by inefficient formation cutting at the central portion of a drill bit.

It has been determined that by relieving the central portion of the cutting face of a drill bit, the formation cutting efficiency and penetration rate of the bit will be significantly enhanced. However, such a drill bit will permit a central formation core to remain. This core must be removed so that it will not interfere with the drilling process. According to U.S. Pat. No. 7,562,725 of Edwin J. Broussard and Herman J. Schellstede, a dual PDC drilling system is provided having an outer reamer bit for cutting away a major part of the formation during drilling and having an inner core removal bit that is independently rotated, such as by means of a mud motor or other rotary power system of the drilling mechanism and which functions to continuously and completely cut away the remaining central formation core that is not cut away by the reamer bit. U.S. Pat. No. 8,201,642 discloses a dual bit well drilling system having a reamer bit and a small centrally located bit within the reamer bit that is rotated in a direction that is opposite the rotation of the reamer bit. Another well drilling system has been developed which employs a rotary PDC reamer bit for primary drilling and employs a fixed PDC element at the center of the reamer bit to fracture away or crush the formation core material that is not cut away by the reamer bit.

PDC drill bits typically drill an oversize wellbore, and thus allow for lateral movement of the drill bit within the formation while drilling. This lateral drill bit movement is undesirable because it causes the resulting borehole to be oversize or out of gauge and will often cause the PDC cutters to be sheared from the bit. Drill bit manufacturers recognize this potential problem and are known to design the PDC bits to have a somewhat concave cutting face and rounded towards the outer periphery. This bit geometry causes wedging of the drill bit into the borehole and thus minimizes the potential for lateral bit movement during drilling and also minimizes the development of shearing forces on the PDC cutter members. However, these concave PDC bit designs cause the cutter area of the bits to be increased and thus cause the cost of the resulting bit to also be increased. This increased drill bit cost is a commercial disadvantage to the well drilling industry.

The dual PDC drill bit arrangement of the present invention achieves more rapid penetration in most hard subsurface formations because drilling penetration is not resisted by poor drilling capability of the central portion of the bit and by the presence of a formation core that develops between the PDC bit blades and retards penetration movement of the bit. The larger the core diameter is and longer it is, (to a point) will significantly stabilize the bit during its drilling rotation and thus minimize the lateral movement that is typically inherent in causing the drilling of oversize wellbores by PDC drill bits. The faster the rate of penetration, the more properly gauged the resulting wellbore will be and the better the bit will be stabilized during its rotational operation. With these advantageous features of bit design incorporated, a flatter PDC bit could be built, having less surface cutter area, thereby minimizing the number of PDC cutters that are employed in bit designs and minimizing the application of torque force to the drill string.

SUMMARY OF THE INVENTION

It is a principal feature of the present invention to provide a novel well drilling system that is adapted for threaded mounting to a bit box of a drill string or mud motor for straight drilling and is adapted to be mounted immediately below the bend of a bent housing type mud motor for directional drilling.

It is another feature of the present invention to provide a novel well drilling system that is of limited length, the limited length contributing to the capability of the drilling system to be selectively oriented for directional steering for drilling a directional well.

It is also another feature of the present invention to provide a novel well drilling system that may incorporate any of a number of different types of formation cutting elements, such as polycrystalline diamond cutting elements, hardened metal cutting elements, rotary cone type rock bits within the spirit and scope of the present invention.

It is also a feature of the present invention to provide a novel well drilling system having a reamer bit that is rotationally driven by a drill string or by any other rotary drive mechanism and a core removal bit that is rotated along or near the longitudinal axis of the reamer bit.

It is another feature of the present invention to provide a novel well drilling system having fluid flow control features to ensure optimum drilling by a reamer bit and a core removal bit and to further ensure optimum flow of drilling fluid for cooling of mud motor bearings and for mud motor operation.

It is an even further feature of the present invention to provide a novel well drilling mechanism having a PDC reamer bit that is capable of being rotationally driven by a rotary drill string or a mud motor that is mounted to a non-rotary drill string and which defines a central bit opening within which is located a formation core removing rotary bit that is independently driven in the direction of rotation of the reamer bit or in the opposite direction of rotation of the reamer bit by a core removal mud motor that is located within a drill housing and is supported by the body structure of the reamer bit.

Briefly, the various objects and features of the present invention are realized through the provision of a steerable well drilling system having a core removal bit assembly that is threaded directly into the bit box of a bent housing mud motor or other straight or directional well drilling system. As drilling fluid is pumped down-hole through the drill string, the fluid will rotate the bit box on the bent housing mud motor thereby rotating the housing structure that contains the core removal bit assembly. The mud motor bent housing is mounted to the lower end of a drill string extending from the drilling rig at the surface and only rotates if the drill string is rotated from above via rotary/kelly or by the top drive of a drilling rig. The steerable drilling assembly simply extends the length from the drill bit to bend of the bent housing. The principal effect the drilling system will have is that the build rate, i.e., borehole deviation, will be less per 100 feet, resulting in borehole curvature of less radius in comparison. The drilling system is steered by selective rotary orientation and linear sliding in substantially the same manner as a conventional bent housing motor is oriented for steering.

The dual bit drilling system of the present invention quite short, having a length of only about 4′ in a typical drilling application. Because of its short length, the drilling system can be used to drill a straight well or it can be threaded into the bit box of a bent housing mud motor and used to drill a directional well. A stabilizer is typically provided on a bent housing mud motor. This stabilizer will likely need to be removed and a different stabilizer will need to be provided along the length of the dual bit drilling system. The stabilizer can be located on the dual bit drilling system at various distances from the drill bit depending on the drilling characteristics that are desired. The stabilizer can also be gauged or under gauged as desired. The rotation speed of the inner core removal bit is determined according to the characteristics of the different types of subsurface formations that are encountered. It is expected that the rate of penetration will increase geometrically since the inner core of the formation is continuously and completely cut away from the top down, rather than being chipped or crushed.

The short well drilling mechanism has a housing to which is mounted reamer bit having a small mud motor located within the housing and supported by the body structure of the reamer bit. This small mud motor is arranged to drive a core removal bit at higher rpm's than that of the reamer bit. The rate of penetration of the well drilling system of the present invention, in comparison with conventional PDC drilling systems, increases geometrically. Because the present invention has a combination of a PDC reamer bit with a mud motor driven core removal bit, which has PDC cutters on the reamer bit, whether the core removal bit be centered or offset from the center-line of the larger reamer bit, achieves efficient removal the formation core while drilling more efficiently with the reamer bit.

The drilling mechanism of the present invention has basically comprises an outer reamer that has been bored for a small mud motor bearing pack, with the core removal bit threaded to the small mud motor, and being positioned within the inner bit body. The mud motor bearing pack has left hand threads to resist the left hand reactive torque that it receives and is threaded into the inner PDC bit body. Because the mud motor is being supported by the reamer only and is subject to reactive torque, all motor connections of the outer body have left hand threads. Left hand reactive torque of the mud motor will be applied to all connections except the connection of the core removal bit to the bit drive shaft. Only a small amount of power is required to rotate a 1¼″ PDC core removal bit. The mud motor power section would be only about 2′ in length. Also the mud motor has a smaller bearing pack with a larger power section driving the PDC core removal bit to ensure adequate rotational power. The inner diameter of the short drive tube will allow a larger power section to be used. The PDC reamer has fluid passages that are nozzled to a specific size, creating internal bit pressure that forces drilling fluid through the mud motor power section, rotating the core removal bit below. Because the lower portion of the mud motor bearing pack is threaded into the inner part of the reamer, this location isolates the bearing pack fluid bypass opening from a high pressure chamber that is located in the upper part of the housing. This feature allows the bearing pack fluid to divert to the lower pressure of the well bore annulus, thereby simultaneously cooling the mud motor bearing back and the core removal bit. A hardened internal reamer sleeve is positioned within a central bore of the reamer bit to prevent wear to the reamer by the core removal bit. The entire drilling assembly is threaded into the bit box of a bent housing mud motor for directional drilling, or is threaded into the bit box of a bottom hole assembly for straight wellbore drilling.

Because the present invention has a combination of a PDC reamer with a mud motor driven core removal bit, which has a PDC point or PDC cutters mounted to it by means of cutter retention matrix or by any other suitable means for cutter retention. Whether the core removal bit be centered or in laterally offset relation with the larger reamer, the core removal bit cuts away the formation core more efficiently while drilling. The optimal offset distance of the core removal bit and the center of the reamer bit will be determined by the well drilling parameters at any point in time.

The dual drill bit system of the present invention would be about 4′ long, comprising of an outer reamer that has been bored for a small mud motor bearing pack, with the core removal bit screwed on, to slide into the inner bit body. The mud motor bearing pack would have left hand threads since its reaction forces will be transmitted directly to the reamer bit body. The mud motor bearing pack is threaded directly into the inner PDC bit body. Because the mud motor is being supported only by the reamer, all motor connections will be in the form of left hand threads, except the core removal bit. Left hand reactive torque of the mud motor will be applied to all connections except the core removal bit. It would not take very much power to turn a 1¼″ PDC core removal bit. The mud motor power section would be about 2′ in length. Also the mud motor will have a smaller bearing pack with a larger power section driving the PDC core removal bit. This will assure adequate rotational power for efficiently rotating the core removal bit. The inner diameter of the short drive tube is sufficiently large to allow a larger power section to be used.

The PDC reamer would have fluid passages that could be nozzled to a specific size, creating predetermined internal bit pressure, thereby forcing drilling fluid through the mud motor power section, rotating the core removal bit below. Because the lower portion of the mud motor bearing pack is threaded into the inner part of the reamer bit, it would isolate the bearing pack fluid bypass opening from the high pressure chamber that is within the housing of the drilling system. This would allow the bearing pack fluid to be diverted to the lower pressure of the well bore annulus, thereby simultaneously cooling the mud motor bearing back and the core removal bit. A hardened internal wear resisting sleeve is located within the reamer bit to prevent wear to the reamer bit by the core removal bit. The complete drilling assembly is adapted to be threaded into the bit box of a bent housing mud motor, for directional drilling or into a bottom hole assembly, for straight hole drilling.

The PDC cutters near the center of the reamers will slightly overlap the reamer core area, cutting the edge of the core and preventing core contact with the reamer. Also because of well bore core removal, minimal bottom hole assembly weight is required to cause the PDC cutters to efficiently penetrate into the formation and drill a straight hole effortlessly. As more weight added to any drill bit, it will force the drill collars above to flex and lay to one side of the well bore, causing the drill bit to be cocked on an angle, thereby drilling off in a selected direction. If drilling continues in the selected direction, the angle of the drill bit will continually increase as additional borehole is drilled. There will also be less heat generated by friction due to the cutting of formation, rather than having the PDC cutters slide on top of the formation rather than cutting it, thereby extending PDC drill bit life dramatically.

Significant vibration is typically experienced when the rotor of the mud motor of the core removal bit is spinning within the stator. For this reason, resilient stabilizers formed of rubber or rubber-like polymer material are added to the mud motor to absorb the vibration. This feature prevents damage to the small PDC coated carbide bit spinning in the core removal bit passage of the reamer bit. The offset core removal bit will be recessed behind the PDC cutters of the reamer bit and is positioned for efficient removal of the formation core that remains as the reamer bit penetrates into the formation. The optimal recessed distance of the core removal bit is determined by the parameters of the formation being drilled; however, it should be borne in mind that the formation core can also serve to stabilize rotation of the reamer bit. With the core removal bit centered within the reamer bit, it can be recessed behind the PDC cutting members on the blades of the reamer bit and protrude out of the reamer bit, provided the core removal bit outer diameter overlaps the PDC cutters in the center of the reamer bit.

Though the mud motor powered rotary drilling system or head may incorporate a variety of formation cutting or eroding elements, such as polycrystalline diamond (PDC) cutting elements and hardened metal rock cutting or chipping elements, for purposes of simplicity the invention is discussed herein as it concerns formation boring by using PDC cutting elements. The steerable drilling mechanism has a tubular housing that is connected with a cross-over sub that is in turn connected with a drill string extending from a drilling rig the surface. The lower end portion of the tubular housing is provided with a vibration isolation member to dampen any vibration forces that are encountered. A reamer bit is connected with the lower end of the tubular housing below a stabilizer that ensures centering of the drilling system within the wellbore being drilled. A mud motor is located within the tubular housing of the well drilling system and includes a rotor having an axis of rotation that can be concentric or eccentric with respect to the longitudinal rotational axis of the tubular housing and reamer. The drilling fluid inlet of the mud motor is in communication with a high pressure fluid chamber that is defined within the tubular housing above a partition and with flow control past the partition being controlled by an interchangeable flow control nozzle.

A partition is preferably present within the tubular housing of the steerable drilling system of the present invention and serves to isolate an internal fluid chamber from the high pressure within the fluid passage of the drill string and bent housing mud motor. An interchangeable orifice flow control nozzle is present within the partition for control of drilling fluid flow past the mud motor for cooling and cleaning of the reamer bit and for cooling and lubricating the bearing pack of the mud motor. The bottom hole steerable drilling mechanism incorporates an external reamer bit having a central portion with no cutting elements, thus permitting a formation core to enter a central opening of the reamer bit as formation drilling progresses. The formation core that remains as the reamer bit is operated is cut away by a mud motor driven core removal bit that is located for mud motor powered rotary movement within a central opening of the reamer bit. Preferably, the core removal bit is a carbide bit having core cutting edges and being formed of carbide material that is preferably coated with PDC material. The core removal bit may have other forms; however it functions to cut away the remaining formation core from the top down as penetration of the reamer bit progresses into the formation. The core removal bit mud motor is mounted within the reamer bit head typically by being threaded into a threaded receptacle of the reamer bit body. The core removal bit is provided with formation cutting elements and is rotated at a different, typically higher rate of rotation as compared with the rate of rotation of the reamer bit. However, if the core removal bit has the same rotary speed as the reamer bit, the rotary speed of the core removal bit will be added to the rotary speed of the reamer bit, causing the core removal bit to rotate at a faster rotary speed than the reamer bit. The reamer and core removal bits work in concert to facilitate a greater overall formation penetration rate as compared with conventional PDC drill bits. The fluid flow that operates the mud motor is also employed for cooling and cleaning of the core removal bit. The core removal bit has a plurality of drilling fluid passages that permit the flow of drilling fluid for cleaning of the cutting elements of the core removal bit and for cooling and lubricating the bearing pack of the core removal bit to promote extended service life thereof. Drilling fluid flow through the reamer passages is selectively adjustable by means of replaceable flow control nozzles that are sized according to well drilling parameters, such as well depth, formation character and hardness, fluid pressure at the drill bits, and the like.

When the core removal or inner bit is rotated about an axis of rotation that is offset from the rotational axis of the reamer bit, the core removing cutting edges of the core removal bit are not centered on the top of the core, but rather cut across the top surface of the core to cut it away. Regardless how big or what the offset of the core removal bit is, the recessed core removal bit will always remove the remaining formation core that is not cut away by the PDC cutter elements of the reamer bit. As the formation core is continuously cut away by the core removal bit, it does not restrict the efficiency of formation penetration by the PDC cutters of the reamer bit.

BRIEF DESCRIPTION OF THE DRAWINGS

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:

FIG. 1 is a schematic illustration showing a well drilling rig that is located at the surface of the Earth's surface and extends a drill string or stem into a wellbore that extends to one or more production zones and shows a well drilling mechanism embodying the principles of the present invention being connected with the drill string and being employed for drilling a straight wellbore section:

FIG. 2 is a schematic illustration that is similar to the illustration of FIG. 1 and shows the well drilling mechanism of FIG. 1 being employed to drill a deviated wellbore section that is directed toward a target formation of interest;

FIG. 3 is a schematic illustration similar to that of FIGS. 1 and 2 and showing the well drilling system of the present invention being connected with a bent housing directional drilling mechanism for controlled drilling of a deviated wellbore that transitions from a vertical wellbore section;

FIG. 4 is a schematic illustration showing the well drilling system of the present invention being mounted to the bit box of a conventional bent housing type directional drilling mechanism

FIG. 5 is a longitudinal sectional view showing a steerable dual bit well drilling system embodying the principles of the present invention, being mounted to the bit box of a drill stem, mud motor or other rotary drive mechanism and having an eccentrically located mud motor powered core removal bit for continuous formation core removal during drilling activity;

FIG. 6 is a longitudinal sectional view showing the upper portion of the steerable well drilling mechanism of FIG. 1 in greater detail and illustrating the eccentrically offset core removal bit and showing the upper portion of the small internal core removal bit mud motor in detail;

FIG. 7 is a longitudinal sectional view showing an enlarged view of the lower portion of the steerable drilling system of the present invention essentially as shown in FIG. 1;

FIG. 8 is a bottom view showing the reamer bit of FIGS. 1-3 as having adjustable fluid flow nozzles for drilling fluid control and showing a laterally offset core removal bit opening within which a core removal bit is located for central formation core removal;

FIG. 9 is a longitudinal sectional view showing a steerable dual bit well drilling system embodying the principles of the present invention, being mounted to the bit box of a drill stem, mud motor or other rotary drive mechanism and having an concentrically located mud motor powered core removal bit for continuous formation core removal during drilling activity;

FIG. 10 is a longitudinal sectional view showing the upper portion of the steerable well drilling mechanism of FIG. 5 in greater detail and illustrating an upper portion of the core removal bit mud motor the concentrically offset core removal bit and showing the upper portion of the small internal core removal bit mud motor in detail;

FIG. 11 is a longitudinal sectional view showing an enlarged view of the lower portion of the steerable drilling system of the present invention essentially as shown in FIG. 5 and illustrating in detail the PDC cutting elements of the reamer bit and concentric core removal bit;

FIG. 12 is a bottom view showing the dual concentric bit drilling mechanism of FIGS. 5-7 and illustrating fluid flow control nozzles of the reamer and core removal bits;

FIG. 13 is a longitudinal sectional view showing a steerable dual bit well drilling system embodying the principles of the present invention, being mounted to the bit box of a drill stem, mud motor or other rotary drive mechanism and having an eccentrically located mud motor powered core removal bit having a splined connection of the core removal bit drive mechanism with the rotor member of the core removal bit mud motor;

FIG. 14 is a longitudinal sectional view showing the upper portion of the steerable well drilling mechanism of FIG. 13 in greater detail and illustrating the splined connection of the core removal bit mud motor in detail;

FIG. 15 is a longitudinal sectional view showing an enlarged view of the lower portion of the steerable drilling system of the present invention essentially as shown in FIG. 13;

FIG. 16 is a bottom view showing the dual bit drilling mechanism of FIGS. 13-15 and illustrating fluid flow control nozzles of the reamer and core removal bits and the PDC core removing cutter members of the eccentric core removal bit;

FIG. 17 is a longitudinal sectional view showing a steerable dual bit well drilling system embodying the principles of the present invention, being mounted to the bit box of a drill stem, mud motor or other rotary drive mechanism and having a concentrically located mud motor powered core removal bit having a splined connection of the core removal bit drive mechanism with the rotor member of the core removal bit mud motor;

FIG. 18 is a longitudinal sectional view showing the upper portion of the steerable well drilling mechanism of FIG. 17 in greater detail and illustrating the splined connection of the core removal bit mud motor in detail;

FIG. 19 is a longitudinal sectional view showing an enlarged view of the lower portion of the steerable drilling system of the present invention essentially as shown in FIG. 17;

FIG. 20 is a bottom view showing the dual bit drilling mechanism of FIGS. 17-19 and illustrating fluid flow control nozzles of the reamer and core removal bits and the PDC core removing cutter members of the eccentric core removal bit;

FIG. 21 is a longitudinal sectional view showing the lower section of the steerable dual bit well drilling system of the present invention with the mud motor and core removal bit of the dual bit well drilling mechanism being laterally offset and having gauge control elements being mounted to ensure formation core controlled stability of the reamer bit against undesired lateral deviation from its intended course during drilling activity;

FIG. 22 is a longitudinal sectional view showing the lower section of the steerable dual bit well drilling system of FIG. 32 and showing a concentrically arranged core removal bit positioned within a gauge lined central core receptacle of the reamer bit;

FIG. 23 is a longitudinal sectional view showing the core removal bit to be eccentrically arranged within the reamer bit and having a gauge lined core receptacle;

FIG. 24 is a longitudinal sectional view showing the lower section of the steerable dual bit well drilling system showing the core removal bit being concentrically arranged within a gauge lined core receptacle;

FIG. 25 is a bottom view showing the lower section of the steerable dual bit well drilling system showing the core removal bit to be eccentrically arranged with the reamer bit and having a gauged core receptacle within the reamer bit for steering control and stability and showing reamer vane or blade overlap of a part of the core removal bit;

FIG. 26 is a longitudinal sectional view showing the lower section of the steerable dual bit well drilling system showing a reamer bit geometry having a depending central projection having internal and external gauge members for stability and steering control;

FIG. 27 is a bottom view of the well drilling mechanism of FIG. 26;

FIG. 28 is a longitudinal sectional view showing the lower section of the steerable dual bit well drilling system showing the core removal bit being concentrically arranged within a PDC gauge lined core receptacle and being of a larger diameter as compared with the diameter of the gauge lined core receptacle of the reamer bit;

FIG. 29 is a bottom view of the dual bit well drilling mechanism of FIG. 28;

FIG. 30 is a bottom view of an embodiment of the present invention having a right hand rotatable reamer bit with PDC cutter supporting blades extending near the axis of bit rotation and showing a left hand rotatable core removal bit being eccentrically located relative to the reamer axis and being of sufficient diameter to overlie a formation core that remains from reamer bit drilling;

FIG. 31 is a bottom view of the dual bit drilling system of the present invention that differs from FIG. 30 only in that the reamer bit and core removal bit have three equally spaced cutter supporting blade members: and

FIG. 32 is a longitudinal section view showing the well drilling mechanism of FIG. 30 and showing further details of the reamer bit and core removal bit and the mud motor drive mechanism for the core removal bit.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENT

While the well drilling system is discussed herein particularly as it concerns PDC drill bits, it is not intended to limit the spirit and scope of the present invention to such, since this invention is adaptable to a variety of drilling systems, including systems for effectively drilling other materials. Referring now to the drawings and first to the schematic illustration of FIG. 1, a well drilling rig 10 is shown that is located at the surface “S” of the Earth. The well drilling rig has a rotary turntable 12, rotary top drive or other rotary drive mechanism for rotating a kelly 14 to which is connected a drill string 16 that is composed of multiple sections of drill pipe, also known as drill stem. The drill string 16 extends from the drilling rig into a wellbore 18 that is being drilled through various earth formations 20 to one or more production zones that may contain crude oil, natural gas, distillate and other petroleum products. The drill stem or pipe 16 of the drill string is tubular and defines a central flow passage 22 through which drilling fluid, also called drilling mud, is pumped for the purpose of cooling the drilling mechanism and flushing away drill cuttings and other debris that is loosened from the formation during drilling. When drilling a straight wellbore, the rotary drive mechanism of a drilling rig continually rotates the drill string and drilling fluid is continuously pumped through the drill pipe and weight is applied through the drilling string to the drill bit to drill straight ahead. When the well drilling system is being used to drill a directional wellbore, as drilling fluid is through the drill pipe and with the drill string stationary, a bent housing mud motor is rotationally oriented to the desired direction for wellbore deviation. The well driller will then slide the drill string ahead to correct the course of the wellbore or to change the wellbore direction. After sliding the drill string a desired distance to achieve the well correction or change that is desired, the driller will then begin to rotate the drill string and once again drill straight ahead.

A drilling mechanism 26 is connected with the bit box of the mud motor powered drilling mechanism 24, will be hydraulically powered by the pressurized drilling fluid being pumped through the drill stem to the drill bit or bits 28 of the well drilling mechanism 26. Every mud motor has two sets of threads, internal threads and external threads. With a standard mud motor, the internal and external threads constitute right hand threads because the mud motor is supported at its upper end by the drill string. The left hand reactive torque that occurs during drilling tends to tighten all of the right hand threads of the outer body of the mud motor. All internal threads of the rotor constitute right hand threads because the motor rotor drives the drill bit to the right and thus has the effect of tightening all of the threads beneath it.

The opposite effect occurs during the practice of the present invention. The mud motor for driving the core removal bit of the present invention is not supported at its upper end by the drill string as is typically the case, but rather has its lower end mounted to and supported by the reamer bit body. In essence, the mud motor for driving the core removal bit is supported only at its bottom end by its connection with the reamer bit. When supporting the tubular housing of the mud motor at the bottom, if the core removal bit is being rotated to the right by the mud motor, the core removal bit and all internal threads of the bit drive mechanism must have right hand threads but all external tubular mud motor body threads must be left hand threads because the reactive torque is to the left. If the core removal bit is rotated to the left by its mud motor, the core removal bit and all internal threads must be left hand threads, but all external motor body threads must be right hand threads because the reactive torque of the core removal bit against the formation core being cut away from the top down is to the right.

According to the spirit and scope of the present invention, as shown in FIG. 5, at the lower or distal end of the drill string 16 is mounted a dual bit steerable drilling mechanism 30, which may be rotated by the drill string, when the drill string is rotated by the drilling rig, or may be powered by a drilling fluid energized mud motor that is connected to the drill string. The dual bit steerable well drilling mechanism 30 is employed to achieve rotation of a reamer bit, shown generally at 32, and a core removal bit, shown generally at 34, both being shown at the lower portion of FIG. 5 and being shown in later Figures of the drawings. The dual bit steerable well drilling mechanism 30 comprises a tubular housing, shown generally at 36, which is comprised of a mounting sub 38 which defines an upwardly projecting externally threaded connection 40 that is received by the internally threaded receptacle 42 of a bit box 44. The bit box 44 may be defined by a drilling sub at the lower end of the drill string or by the rotary output shaft of a mud motor that is intended for either straight or directional drilling. The tubular housing 36 further includes an intermediate housing section 46 having an upper threaded connection 48 in assembly with the mounting sub 38 and a lower threaded connection 50 with a reamer bit body 52. The intermediate housing section 46 is typically provided with a plurality of external elongate radially spaced centralizer members 54 that centralize the drilling mechanism within the wellbore and with the spaces between the centralizer members defining flow passages within the wellbore and externally of the tubular housing for the return flow of drilling fluid and drill cuttings after the drilling fluid has been discharged from the drill bit mechanism of the well drilling system.

The reamer bit body 52 is typically composed of a durable metal composition, such as steel, and defines an external surface 54 to which a cutter retention matrix 56 is affixed by bonding, welding or by any other suitable means for attachment. As is evident in FIG. 7 and from the bottom view of FIG. 8, the cutter retention matrix 56 is formed to define a plurality of outwardly radiating curved vanes 58, having leading edge portions 60 that define a multiplicity of cutter receptacles 62 each having a PDC cutter element 64 secured immovably therein. Thus, a plurality of curved arrays of PDC cutter elements 64 are each arranged to present cutting edges that engage and cut away a small portion of the formation interface during each rotational revolution of the reamer bit. Collectively, the curved arrays of PDC cutter elements 64 continuously cut away the major portion of the formation material within which the wellbore is being drilled. Gauge or wear pad members 66, which may be defined by PDC members or by any other hard and wear resistant material, are retained by the cutter retention matrix material 56 and serve to minimize the potential for wear of the cutter retention matrix material as the outer wall of the reamer bit is rotated in contact with the abrasive wall surface of the wellbore.

When drilling with conventional PDC bits the PDC cutter elements tend to crush the central portion of the formation material within the borehole, rather than cut it away, due to the inefficient cutting characteristics of the PDC cutters at the central region of the bit. Even when a PDC bit is provided with a small concentric bit, such as taught by U.S. Pat. No. 8,201,642, for drilling a central portion of a borehole, the small concentric bit would tend to crush, rather than cut away the formation material due to the inefficient formation cutting characteristics of the centrally located formation cutting elements of the small concentric bit. However, as is evident from FIGS. 5 and 7 of the drawings, the reamer body 52 defines a downwardly facing central opening 68 which, since the reamer bit has no central cutter elements, maximizes formation cutting efficiency. The open central portion of the reamer bit presents virtually no resistance to bit penetration as is typically experienced by conventional PDC drill bits having formation cutter elements at the central portions thereof. However, during drilling activity a central core portion of formation material is not cut away, since no cutting elements are present, and enters the central opening 68. A core removal bit 34 is provided to efficiently cut away this central formation core. In the case of the dual bit steerable well drilling mechanism shown in FIGS. 5-8, the tubular housing 36 defines a longitudinal center-line C/L¹ which is concentric with the center of the flow passage 22, concentric with the connecting sub 38 of the housing and concentric with the centers of the intermediate housing section 46 as well as the reamer bit body 52. However, the cylindrical wall surface 76 of the central opening 68 of the reamer bit body 52 is eccentric with respect to the reamer bit body, such that its center-line C/L² is laterally offset with respect to center-line C/L¹ of the reamer bit body 52. It should be borne in mind, however, that the core removal bit can be either eccentrically located or concentrically located with respect to the center-line C/L¹.

As shown in FIGS. 1 and 7, the core removal bit 34 is positioned within the central opening 68 for rotation about the center-line C/L² and has a core cutting face 70 that is recessed within the central opening 68. The core cutting face is provided with a plurality of PDC cutting elements 72 that serve to continuously and completely cut away the remaining formation core that is not cut away by the cutting elements of the reamer bit 32. It should be noted that the reamer bit 32 may be rotated by a rotating drill string or by a drilling fluid energized mud motor. However, the core removal bit is independently rotated by a drilling fluid powered core removal bit mud motor shown generally at 74 which is located within the tubular housing 36 of the well drilling mechanism 30.

For core removal bit mud motor support, as shown in FIG. 7, the reamer bit body member 52 defines a substantially vertical bore 76 having the laterally offset center-line C/L² as its center. The vertical bore 76 defines an internally threaded upper extent 78 within which the upper externally threaded end portion of a bearing support sleeve member 80 is seated. The bearing support sleeve member 80 also serves as an internal wear resisting liner to protect the core removal bit 34 against excessive wear during drilling operations. A plurality of annular seal members 81 are carried within seal grooves of the bearing support sleeve member 80 and establish high pressure sealing with the internal cylindrical surface 75 of the vertical bore 76. An outer bearing member 82 is located within the bearing support sleeve member 80 and an inner bearing member 84 is mounted to a core removal bit drive shaft 86 which is driven by the core removal bit mud motor 74. The bearing support sleeve member 80 carries a plurality of spaced seal members 81, such as O-rings, that establish a sealed barrier between the bearing support member and the internal cylindrical surface 83 of the substantially vertical bore 76 of the reamer bit body 52. The bearing support member 80 defines a mud motor tube mount 88 at its upper end portion which has a downwardly facing shoulder 90 that is seated on an internal upwardly facing surface 92 of the reamer bit body 52. An upstanding externally threaded section 94 of the mud motor tube mount 88 is engaged by an internally threaded section 96 of a tubular mud motor housing 98 of the core removal bit mud motor 74 to provide for stabilizing support of the core removal bit mud motor. The core removal bit mud motor has a bearing pack shown generally at 100 which includes spaced sets of radial bearings 102 and 104 and thrust bearings 106. An annular fluid flow clearance or passage 103 exists through the bearing pack 100, thereby permitting drilling fluid flow through the bearing pack for cleaning and cooling the bearings and materially enhancing the service life of the core removal bit mud motor and its bearing members. The drilling fluid is discharged from the clearance or flow passage of the bearing pack and then flows through the clearance between the core removal bit 34 and the formation core receptacle within which the core removal bit is also positioned for core cutting rotation.

As shown in FIG. 1 and in greater detail in FIG. 6, the tubular housing 98 of the core removal bit mud motor 74 contains a fixed stator member 108 that is composed of a resilient material such as rubber or any of a number of suitable resilient polymer materials. The stator member defines a generally helical internal profile. A rotor member 110 is rotatable within the stator member and has a corresponding generally helical external profile. Pressurized drilling fluid being supplied through the flow passages of the drill string, flow passage 22 of the bit box 24 and the internal fluid passage 112 of the mounting sub 38 enters a high pressure chamber 114 of the steerable well drilling mechanism 30. A portion of the pressurized drilling fluid of the chamber 114 enters a mud motor actuation passage 116 via an opening that is defined by an inlet fitting 118 that forms the upper extent of the core removal bit mud motor 74. A flow control nozzle 119 may be threaded The pressurized drilling fluid within the mud motor actuation passage 116 acts on the geometries of the internal and external helical profiles of the stator and rotor of the core removal bit mud motor and causes hydraulically energized rotation of the rotor member and applies a motor torque to a non-circular shaft drive member 120. A mud motor output shaft 122 receives and is driven by the lower non-circular shaft drive member 120.

During operation of the core removal bit mud motor 74 pressurized drilling fluid is discharged from the rotor and stator interface and enters an annular flow passage 124 that is located about the mud motor output shaft 122 and the inner surface of the tubular housing 98. This flow of drilling fluid serves for cooling and lubrication of the bearing pack 100. The lower end portion of the mud motor output shaft 122 defines a tubular cross-over member 126 that has transverse fluid inlet openings 128 through which pressurized drilling fluid transitions from the annular flow passage 124 to a flow passage 130 within the core removal bit drive shaft 86. The body member 132 of the core removal bit 34 is threaded to the lower end of the core removal bit drive shaft and defines diverging drilling fluid passages 134 that conduct flowing drilling fluid to a plurality of fluid flow control nozzles 136. The fluid flow control nozzles 136 are sized to provide an optimum rate of drilling fluid flow to the cutting interface of the core removal bit 34 for efficient cooling and cleaning of the core removal bit as the drilling operation is being conducted.

For cooling and cleaning of the reamer bit 32 the reamer bit body 52 has a plurality of fluid supply passages, two of which are shown at 138 and 140 in FIG. 7. At the outlet portions of these fluid supply passages fluid flow control nozzles are mounted as shown at 142 and 144. These fluid flow control nozzles are sized according to wellbore parameters, such as formation depth, temperature, pressure, etc. and can be changed or selected to ensure optimum flow of drilling fluid for efficient formation cutting, drill bit cooling and for flushing away drill cuttings. As is evident from the bottom view of FIG. 8 an annular clearance 146 exists between the outer periphery of the core removal bit 34 and the inner surface of the central opening 68. A small volume of pressurized drilling fluid flows within this annular clearance 146 for cleaning and cooling the core removal bit and motor bearings as the core removal bit is independently rotated and oscillated in response to rotation of the reamer bit.

During borehole drilling with the reamer bit 32, the core removal bit 34 of FIGS. 5-7, being eccentrically located with respect to the center of the reamer bit, will have an orbital motion as well as being rotated independently of the rotary motion of the reamer bit. This orbital motion causes the PDC cutter members of the core removal bit to sweep across the central region of the borehole, thereby continuously cutting away the small core that remains as the formation is cut away by the reamer bit. The core removal bit is rotated by the core removal bit mud motor, which requires very little power for its operation, because of its small size in comparison with the size of the reamer bit. The core removal bit is driven at a significantly greater rotary speed which causes its PDC cutter members to move at an optimum speed relative to the formation for efficiently cutting away the core region of the formation, without developing elevated heat. Moreover, the core removal bit is efficiently cooled during its operation by the volume of drilling fluid that is discharged at its cutting face from the fluid control nozzles of the core removal bit and from the clearance between the core removal bit and the central opening of the reamer bit.

Referring now to FIGS. 9-12 a dual bit steerable well drilling mechanism is shown generally at 150 which differs from the dual bit steerable well drilling mechanism 30 of FIGS. 5-8 principally in the concentric arrangement of the core removal bit 34 with respect to the reamer bit 32. In this case, the central opening 68 of the reamer bit is concentric with respect to the center-line of the reamer bit and with virtually all of the tubular components of the tubular housing and core removal bit mud motor. Though the core removal bit is rotated by its mud motor 74 in the same manner as discussed above, it will not have oscillating motion during rotation of the core removal bit. To continuously cut away the central core that remains due to rotary cutting of the borehole by the reamer bit, the core removal bit will simply be rotated by the core removal bit mud motor and will rely totally on the arrangement and cutting capability of the arrays of PDC cutting elements that are affixed thereto.

As shown in FIGS. 13-16 the dual bit steerable well drilling mechanism shown generally at 160 has a bearing pack 162 having a tubular bearing pack support 164 that is mounted to the reamer bit body 52 in substantially the same manner by a tube mount 88 as discussed above in connection with FIG. 7. A rotary hydraulically energized drilling motor, also known as a mud motor, is shown generally at 166 and includes a stator member 168 having a stator body composed of resilient material such as rubber or a suitable polymer material and defining a helical internal profile 170. A rotor member 172 is supported within the stator member 168 and has a rotor body 174 that is also composed of a resilient material. The rotor body 174 defines a generally helical external profile 176 that serves cooperatively with the internal stator profile 170 to develop rotary torque force that causes rotation of the rotor member at a speed and torque force that is determined by the volume, size, length and stator/rotary lobe configuration of the motor and drilling fluid flow from the drill string. The rotor member 172 is of tubular form and defines an internal surface 173 that defines an internal rotor chamber or passage 175. The rotor member defines a bottom opening 177 permitting movement of a flexible rotor driven mud motor output shaft 178. Since it is known that the rotor member of a mud motor has uneven rotation speed during its operation and tends to have a jerking rotary characteristic that is communicated to a drill bit or any other device to which it is connected, it is desirable to minimize this jerking rotary characteristic. The rotor driven shaft 178 is formed of a flexible material such as beryllium copper and has a thin flexible shaft portion that yields and is flexed by the forces the shaft receives from rotor movement of the mud motor. Shaft flexing or yielding in this manner cushions the jerking rotary characteristic of the rotor and thus cushions the formation cutting forces that are communicated to the drill bit. The rotor driven shaft 178 has an enlargement 182 at its upper end portion that is maintained in non-rotatable relation with the rotor member 172 by an engaging spline and groove connection 180. The shaft enlargement 182 of the rotor driven shaft 178 has an upwardly facing shoulder 184 that is secured against a transverse rotor wall 186 by lock-nut members 188 and 190 that are threaded to an externally threaded upper portion 192 of the rotor driven shaft. Thus, upon drilling fluid energized rotation of the rotor member 172 the rotor driven shaft 178 is also rotated. As shown in FIG. 15 a core removal bit operating shaft 200 is located within the tubular bearing support member 164 and is mounted for rotation within the bearings of the bearing pack. At the lower end portion of the rotor driven shaft 178 is defined a connector member 204 that establishes non-rotatable connection with the upper end portion 202 of a core removal bit operating shaft 200.

It is necessary that the motor bearing discharge be at a lower pressure than at the inlet of the motor. This differential pressure condition will cause the drilling fluid or drilling mud to be forced through the bearing pack, achieving cooling and lubrication of the bearing pack. This design causes the mud motor bearing fluid to be discharged into the lower pressure condition of the well bore atmosphere. A major portion of the drilling fluid that enters the internal chamber 114 of the housing 36, which is referred to as a high pressure chamber, and progresses through the interface of the stator member 168 and the rotor member 172 is discharged into an annular drilling fluid supply chamber 194, which is also a high pressure chamber or cavity due to high pressure fluid progression through the contoured interface of the rotor and stator members. The drilling fluid then enters the fluid supply passages 138 and 140 and then flows through the fluid control nozzles 142 and 144 as shown in FIG. 16. After the drilling fluid exits the rotor/stator interface of the mud motor into chamber 194, then a portion of the fluid enters the lower opening in rotor chamber 175 as shown in FIG. 15. The fluid then flows up inside chamber 175 to the opening at the top of the motor bearing pack, then passes down through the fluid passages of the bearing pack and exits into the lower pressure of the wellbore atmosphere. The drilling fluid discharged into the spaces 214 between the curved vanes or blade members 206 of the reamer bit 34 at the cutting interface of the core removal bit with the formation core that remains as the reamer bit penetrates the formation. The PDC cutter elements 208 achieve cutting of the formation in the presence of sufficient drilling fluid for cooling and lubrication of the cutter elements and for flushing away drill cuttings that are transported to the surface via the annulus between the drill string and the surface of the wellbore that has been drilled.

As shown in FIGS. 14 and 15, the flexible mud motor operating shaft 178 defines a drilling fluid flow passage 196 throughout its length. A fluid flow control nozzle 198 is threaded to or otherwise mounted to the upper end of the mud motor operating shaft 178 and serves to control the flow of drilling fluid from the internal housing chamber 114 into the drilling fluid flow passage 196. A core removal bit operating shaft 200 is positioned for rotation within the tubular bearing support member 164 and has its upper end portion 202 mounted to a connector member 204 that is defined by the lower extremity of the mud motor operating shaft 178. The core removal bit operating shaft 200 is supported for rotation within the tubular bearing support member 164 by the various bearing members of the bearing pack 162. As is evident in FIGS. 15 and 16 the core removal bit 34 is threaded to the lower end of the core removal bit operating shaft 200 and is provided with a plurality of curved blade or vane members 206, each having a plurality of PDC core cutting members 208 mounted to the leading edge thereof.

As shown in FIG. 15, the core removal bit operating shaft 200 defines a central fluid flow passage 210 which is in communication with the fluid flow passage 196 of the mud motor operating shaft 178 and serves to conduct drilling fluid to the core removal bit 34 for cooling and cleaning during drilling. The core removal bit defines a plurality of diverging fluid flow passages 212 that communicate with the central fluid flow passage 210 and have fluid discharge openings in the spaces 214 between the blades 206 or vanes of the core removal bit. Fluid discharge control nozzles 216 are threaded into the fluid discharge openings and serve to control the discharge of drilling fluid to the cutting face of the core removal bit 34. Like the fluid flow control nozzles 142 and 144 of the reamer bit 32, the fluid flow control nozzles 216 of the core removal bit may be replaced by fluid flow control nozzles having flow controlling characteristics that are suitable for different well characteristics such as depth, formation pressure, temperature, etc. Thus, the drill bit can easily be tailored to the needs of the drilling operation at any point in time.

FIGS. 19 and 20 illustrate a dual bit steerable well drilling mechanism generally at 220 that differs from the drilling system of FIGS. 13-16 only in that the core removal bit 34 is concentrically arranged within the reamer bit 32 rather than being eccentric as is evident in FIGS. 13-16. It should be noted, regardless whether the core removal bit is eccentrically or concentrically located with respect to the center-line of the reamer bit, that drilling activity develops left hand reactive torque on all of the threaded connections of the mud motor, with exception of the threaded connection of the core removal bit to the core removal bit operating shaft 200. For this reason, the threaded connections of the rotary components of the mud motor will have left hand threads to prevent unthreading of these connections by the left hand reactive torque.

With reference to FIGS. 21 and 22 the dual bit steerable drilling system that is shown in the longitudinal sectional view of the bottom section of the well drilling mechanism employs a core removal bit 34 that is eccentrically located with respect to the center-line C/L¹ of the tubular housing 36. The core removal bit defines a plurality of diverging fluid flow passages 222 that are in communication with the central fluid flow passage 210 of core removal bit operating shaft 200 and have fluid discharge openings 224 that direct discharge streams of drilling fluid downwardly against the formation core that remains as the PDC cutting elements 64 of the reamer bit cut away the formation material during wellbore drilling. The diverging fluid distribution passages of the core removal bit have flow control nozzles 226 that control injection of drilling fluid from the core removal bit into the wellbore according to various well conditions. These flow control nozzles can be replaced with flow control nozzles of different flow controlling capacity as the well conditions change. Like the reamer bit 32, the core removal bit 34 may have any number of radiating curved vanes or blades, for example 3, 6 or 8 blades on which are mounted PDC formation cutter elements. For example in FIG. 25 the core removal bit 34 is shown to have 4 curved cutter supporting blades.

Also, if desired, the inner cylindrical wall surface that defined the downwardly facing central opening 68 may be provided with internal and/or external wear resisting pad members which serve as formation core gauge protection to prevent wear on the internal reamer blades core area of the matrix body, thereby producing a constant core size for PDC reamer bit stabilization during drilling activity. This feature permits the formation core to stabilize drilling rotation of the dual bit mechanism and prevent its otherwise uncontrolled lateral excursion within the formation, which as mentioned above, causes undesired enlargement and/or misdirection of the wellbore being drilled. This feature ensures that the resulting wellbore will have the designed gauge throughout. Gauge protection is also important from the standpoint of cutter element protection. In a dual bit arrangement having a core removal bit, without gauge protection the formation core can become worn to the point that lateral off-direction or gauge enlarging movement of the drill bit will occur in the formation. When the gauge of the wellbore becomes enlarged the drill bit can oscillate back and forth within the wellbore. This back and forth movement can cause the PDC cutter elements of the core removal bit to become sheared away, thus essentially destroying its drilling capability. The presence of the formation core within the downwardly facing central opening 68, assuming the core is not excessively worn, provides for rotational stability of the drill bit and resists lateral movement of the drill bit within the formation.

If a drill bit manufacturer were to make the PDC blades of the reamer bit slightly longer, the result would be a longer core receiving receptacle as shown in FIG. 21, thus causing the formation core to be of greater length. The longer core functions to stabilize the rotation of the bit and to minimize its lateral movement within the formation. A longer and larger diameter formation core will provide better and more efficient stabilization of a drill bit during drilling by restraining lateral movement of the drill bit within the formation, thus ensuring that the resulting wellbore is of the proper gauge. To provide the desired gauge protection, wear resisting members 228 are provided on the inner parts of the PDC cutter supporting blades and serve to minimize abrasive contact of the blades with the formation core. The wear resisting members serve as gauge protectors and prevent the blades from wearing and reducing the diameter of the formation core and also prevent the erosive effect of the formation core from wearing the cutter retention matrix material of the inner parts of the blades. If this is not done, the stabilization effect of the core on the bit will eventually be lost through wear or erosion of the formation core or the matrix material of the drill bit and the drill bit will then tend to move laterally within the formation. The inner stabilization that is provided by the formation core can influence the bit design. Rather than employing the current rounded contour of the outer diameter of a PDC drill bit, so that the drill bit essentially wedges into the borehole for straight drill tracking, the formation core resists lateral movement of the drill bit and causes the drill bit to progress along a straight course during drilling. This feature permits the bit design to be changed to a more straight or flat bottomed design with minimal rounded design portions, thus significantly minimizing the number of PDC cutter elements that are needed for efficient drilling and minimizing the cost of the drill bit.

With increased space in the center of the reamer bit, essentially a reamer bit that has no center, a bit designer can have 4 or more PDC cutter supporting blades extending to the core. Thus 4 or more gauge protected blades are present for stabilizing engagement with the formation core. The downwardly facing central opening can be sufficiently large to allow a 2 inch or larger core to enter the core receiving receptacle of the reamer bit. The size of the formation core that enters the downwardly facing opening of the reamer bit is determined by the size of the reamer bit. Thus, the core can be larger or smaller than 3″. A concentric or eccentric core removal bit having a diameter of about 3 inches can be positioned for cutting engagement with the 2 inch or larger core. If the core removal bit is eccentrically located, the bit will be offset behind central portions the blades of the reamer bit but outside the body of the bit. This feature allows for the drill cuttings of the core removal bit to be transported into the borehole being drilled by the flushing activity of the drilling fluid being discharged from the core removal bit.

FIG. 21 shows the lower portion of a dual bit steerable well drilling system that differs from the drilling system of FIG. 19 in the presence of one or more internal formation cutter supporting vanes or blades 230 that overlap a portion of the central opening 68 and are provided with wear resisting gauge protector members 228. During rotation of the reamer bit 32 about the center-line C/L¹ the centermost cutter elements 232 provide for cutting away the formation material and leaving a central core of formation material within the vertical bore that defines the central opening 68. To ensure that central core is not diminished in width by wear due to its engagement by the internal surface that defines the central opening 68, the gauge protectors 228, being composed of a wear resisting material, such as PDC will protect the central core against unusual wear. The gauge protectors will also minimize abrasive wear of the PDC retaining matrix material and significantly extend the service life of the reamer bit.

The PDC cutters near the center of the reamer bit slightly overlaps the formation core receptacle of the reamer bit and will have cutting engagement with the outer peripheral surface of the core, thereby preventing the formation core from being in contact with any portion the reamer bit. Also because of well bore core removal, little bottom hole assembly weight is required for PDC cutter elements to penetrate into the formation, thereby permitting a straight wellbore to be effortlessly drilled. As additional weight added to any drill bit, this added weight will force the drill collars above the dual bit drilling system to flex and essentially become positioned one side of the well bore, causing the drill bit to be cocked on an angle and thereby drilling off in the direction of the angle. As drilling continues, this angle will continually increase as the wellbore is drilled into the formation. Less heat is generated by friction due to efficient cutting of the formation by the PDC cutting elements, rather than having the inefficient central cutters of a PDC bit typically sliding on top of the formation, thereby extending PDC drill bit service life dramatically.

FIG. 22 shows the lower section of the dual drill bit mechanism, having reamer bit blade members 234 of greater axial length as compared with the axial length shown in FIG. 15. By employing blade members of longer length, the core removal bit 34 is retracted to a greater extent within the reamer body bore 76. The radially inner surface portions of the reamer bit blade members 234 are also provided with internal gauge protector members 228 to minimize wear or erosion of the cuter retaining matrix material of the blade members. The gauge protectors also minimize wear of the formation core and thus maintain the stability and straight drilling capability of the PDC well drilling mechanism.

The longitudinal sectional view of FIG. 23 illustrates a reamer having an eccentrically located core removal bit, wherein the reamer bit is provided with a plurality of blade members 236 that are of greater axial length at the central portions thereof than at the outer portions thereof, and thus defines a downwardly and inwardly tapered generally conical blade geometry. This tapered blade geometry promotes wedging of the reamer bit into the bottom of the wellbore being drilled and promotes straight drill bit tracking in the formation, unless wellbore angle is intentionally caused by controlled application of weight. This longer cutter supporting blade design also promotes the presence of a fairly long bottom inlet opening 238 and permits the remaining formation core to be of significant axial length for efficient lateral support of the reamer bit against lateral movement in the formation while drilling. Additionally, the interior surfaces of the cutter supporting blade members are provided with gauge protectors to minimize wear to the formation core and the cutter retention matrix of the blades. Portions 240 of the cutter supporting blade members 236 overlap portions of the core removal bit 34 in the manner and for the purpose that is described above in connection with FIG. 21. Additionally, the diverging orientation of the PDC cutter elements 239 near the central opening 68 provide the remaining formation core with a fairly large tapered base portion, adding to the structural integrity and stability of the formation core. Since the reamer bit is rotated about its center-line C/L¹ during drilling, the central formation core that is left by the formation cutting activity of the reamer bit will be of considerable length and width and therefore will provide the reamer bit with excellent gauge protecting stability against lateral movement of the reamer bit within the formation being drilled.

According to the longitudinal sectional view of FIG. 24, the PDC cutter support blade members 242 are rotated about the concentric center-line C/L, thus ensuring that the central formation core that remains due to reamer bit drilling will be of greater width or diameter as compared with the eccentric core removal bit configuration of FIG. 23. The length of the formation core will be approximately the same as shown in FIG. 21. The generally vertical bore 67 defining the downwardly facing central opening 68 is at least partially lined by a plurality of gauge protector members 228 that minimize erosion of the central formation core to ensure against lateral movement of the reamer bit during drilling and also minimize wear of the cutter retention matrix material at the inner portions of the PDC cutter retaining blades 242. FIG. 25 is a bottom view showing the eccentric relationship of the downwardly facing opening with respect to the bore 76 for the core removal bit and core removal bit mud motor drive mechanism and further showing overlap of inner portions 230 of the curved PDC cutter retention vanes or blades 236 of the reamer bit.

With reference to FIGS. 26 and 27, the longitudinal sectional view of FIG. 26 shows a dual bit, steerable well drilling mechanism that is similar to the drilling mechanism of FIG. 23, with the exception of the configuration of the cutter retention matrix of the reamer bit 32. The blade forming and cutter retention matrix 56 of the reamer bit 32 defines a central extension 244 of circular configuration, which is concentric with the reamer bit and defines an outer circular surface 246 as is evident in FIG. 27. Wear resistant gauge protector members 248 are mounted to the matrix material and have wear surfaces that are essentially co-extensive with the cylindrical outer surface 246 of the central extension 244. As the reamer bit is rotated within the formation during drilling activity, the gauge protection members 248 minimize erosive wear of the formation wall immediately adjacent the cylindrical surface 246 and also minimize wear of the outer cylindrical surface 246 of the matrix material. This feature minimizes the potential for the reamer bit moving laterally within the formation and causing the wellbore to become off gauge. As is evident in the bottom view of FIG. 27, the downwardly facing outer peripheral portions of the reamer bit define a plurality of curved vanes or blades 250 that have spaces and provide for orientation and support of a multiplicity of PDC cutter elements 252. Likewise, the downwardly facing tapered surface portion 254 of the central extension 244 also defines a plurality of spaced curved vanes or blades 256 that also provide for orientation and support of a multiplicity of PDC cutter elements 258.

As shown in FIG. 26, the bore 76 that defines the downwardly facing central opening 68 of the reamer bit 32 is eccentrically located with respect to the center-line C/L¹ of the tubular housing 36 and the reamer bit body 52 so that its center-line C/L² is laterally offset. This feature causes the radially inner portions of the curved vanes or blades of the PDC cutter support matrix material to overlap the bore 76 as shown at 260 in FIGS. 26 and 27. The core removal bit member 34 is recessed within the bore 76 to provide space 262 for fluid entrainment and flushing of drill cuttings away from the cutting face of the core removal bit 34 by means of the drilling fluid that is discharged from the fluid distribution passages of the core removal bit.

Internal gauge protector elements 264 are mounted to the matrix material 56 within the downwardly facing central opening 68, as shown in FIGS. 26 and 27 and serve to minimize erosive wear of the formation core that is present within the downwardly facing central opening 68 during drilling. The gauge protector elements 264 also minimize erosive wear of the inner peripheral surface that defines the downwardly facing central opening. Thus, the formation core provides for stability of the reamer bit during drilling and ensures against the lateral deflection or drifting that is typically inherent in conventional PDC drill bits.

FIGS. 28 and 29 illustrate the dual bit steerable well drilling system of the present invention and show the core removal bit 34 as being concentric with the reamer bit. As shown in FIG. 28 the generally vertical bore 76 that defines the downwardly facing central opening 68 and the bore 77 within which the core removal bit 34 is maintained for rotation by the internal mud motor 74, both being rotated in concentric relation with the center-line C/L. The core removal bit 34 has its cutting face retracted within the downwardly facing central opening 68 and is located within an enlarged section 266 of the bore 76. The PDC cutter elements that are present on the lower outer periphery of the core removal bit are disposed in overlapping relation with the dimension of the formation core that is present within the downwardly facing central opening during drilling operations. This feature ensures that the formation core is continuously and completely cut away during drilling operations even if the dual drill bits should become shifted laterally.

The text and drawings set forth above disclose a well drilling mechanism having a reamer bit and a core removal bit, both of which rotate clockwise or to the right during wellbore drilling. FIG. 30, however, presents the dual bit well drilling mechanism generally at 270 as having a reamer bit 271 that is rotated to the right, as is typical for virtually all deep well drilling systems for discovery and production of petroleum products and shows a core removal bit 273 that is counter-rotated with respect to the rotational direction of the reamer bit. Since the core removal bit is turned to the left, to compensate for the reaction torque that is developed due to its operation, the threaded connections of the tubular housing structure of the mud motor 162 must be made by right hand threads and the connection of the core removal bit to the bit drive shaft 200 must be made by left hand threads. FIG. 31 is a bottom view showing a duel PDC drill bit generally at 270 which is of the same general form as shown in FIG. 8, with the exception that the blade members 272 that are defined by the cutter retention matrix 56 are of more straight configuration as compared to the curved configuration that is shown in FIG. 8. However, the cutter supporting blade members extend along the curved path about the bottom and side portions of the matrix material as shown in FIG. 31 The blade members 272 therefore define substantially straight cutting edges 274 that define cutter retention receptacles 62 within which the PDC cutter elements 64 are retained.

As is evident in FIGS. 30-32, the reamer bit may be provided with any desired number of cutter retention blade members 272. As shown in the bottom view of FIG. 30, the reamer bit is shown with four cutter retention blade members while in FIG. 31 the reamer bit is shown with three equally spaced cutter retention blade members. Thus, it is clear that the reamer bit may have any desired number of cutter retention blade members that is suitable for the drilling operation that is to be conducted. In each case, the cutter retention matrix material is configured to define a bore or formation core passage 67 that defines a downwardly facing opening 68. The formation core passage 67 is concentric with respect to the center-line C/L¹ of the tubular housing 36 about which the tubular housing 36 is rotated during drilling activity.

The bore or formation core passage 67 is defined in part by one or more core gauge protector members 276 that are fixed to the inner end portions of the cutter supporting blades. The gauge protector members serve to minimize wear of the bore 67 of the reamer bit and minimize erosive wear of the formation core that is present within the downwardly facing opening 68 that is defined by the bore or passage 67. This feature ensures that the formation core within the bore or formation core passage 67 functions as a gauge member to stabilize rotation of the reamer bit and minimize any lateral movement of the reamer bit within the formation during drilling. This feature prevents the wellbore being drilled from becoming off gauge during drilling operations. Of course, the formation core is being continuously cut away from the top down as the reamer bit progresses into the formation. As mentioned above, the tubular housing can be rotated by a rotary drill string or can be rotated by a mud motor drive mechanism that is connected with a drill string that is not rotated continuously for drilling, but may be rotated for drill bit orientation, for activities such as for directional drilling.

As shown in FIGS. 31 and 32 portion of the reamer bit body 52 and the cutter retention matrix material defines a generally cylindrical internal wall 278 forming a wall of a bit chamber bit 279 within which a core removal bit 280 is rotated by the operating shaft 200 of the core removal bit. The outer, generally cylindrical surface 282 of the core removal bit 280 is disposed in spaced relation with the inner cylindrical surface 282, thus defining a clearance 284 through which drilling fluid flows for cooling and cleaning of the core removal bit after having flowed through the various fluid passages and channels of the bearing pack. After passing through the annular clearance about the core removal bit, the drilling fluid is discharged into the low pressure region of the wellbore just below the reamer bit and is then conducted to the surface along with drill cuttings via the annulus between the drill string 16 and the internal surface that is defined by the wall of the wellbore wall. The core removal bit 280, as discussed above is basically composed of a suitable steel material such as 4140 steel which machined and threaded as needed. Tungsten carbide material is then fused to the steel material and is then coated with PDC material to enhance the cutting capability and serviceability of the core removal bit. The core removal bit defines a cutting face 286 that is oriented for cutting engagement with the upper end portion of the formation core and continuously cuts away the upper portion of the formation core at the same rate as the reamer bit penetrates into the formation during wellbore drilling.

The dual drill bits of FIGS. 30 and 31 are cooled and lubricated by drilling fluid flow in the same manner as discussed above. Drilling fluid passages of the right hand rotatable reamer bit 270 have outlets 288 which open to the spaces between the cutter retention blades so that drilling fluid is injected into the wellbore in the immediate vicinity of the PDC cutter members 64. If desired, these outlets may be controlled by flow control nozzle members 142 as discussed above in connection with FIG. 12 and other FIGS. of the drawings. Drilling fluid of the left hand rotatable core removal bit is also channeled through flow passages of the central passage 210 of the bit drive shaft 200 and distributed to the cutting face region of the core removal bit and bit chamber 279 as discussed above in connection with FIG. 15.

It should be noted, concerning FIGS. 30 and 31 that the more central portions of the cutter retention blades are provided with gauge protector members 276. These gauge protectors will be in substantial contact with the outer cylindrical portion of the formation core to protect the transverse dimension of the core from being worn, and thus decreased, by the rotating reamer bit, and also to protect the internal dimension of the reamer bit blades from being worn by its contact with the core. It is desirable to minimize abrasive wear of the core and reamer bit blades for gauge protection to ensure stabilizing rotation of the reamer bit and thus ensure that the wellbore being drilled is maintained on gauge as precisely as possible.

When the reamer bit has a small core removal bit within a small bit compartment that is normally rotated to the right, the cutters of the core removal bit facing to the outside of the reamer bit would be facing the direction that the reamer is tuning, a cutting position, but cutters on the inside, facing the center of the reamer. The purpose of the core removal bit is to cut away the central formation core that the reamer does not cut away. If the small core removal bit is designed to be rotated to the left, with its cutters facing inwardly, toward the center of the reamer, the cutters would be moving in the same direction as the reamer, or to the right, an excellent cutting position. To compensate for the reactive torque that occurs when the cutting face of the core removal bit engages the formation core, the core removal bit is mounted to the drive shaft 200 with left hand threads. However, the core removal bit can be rotated to the right but additional rpm's of the core removal bit are required to overcome the reamer speed effect on the small bit. A bit rotation motor that is capable of providing greater rotational speed of the small core removal bit requires a smaller lobe configuration to increase the speed and requires additional rotor/stator stages to increase the power that is required to turn the small bit. The motor would be longer and would require more pressure to operate effectively. If the small bit to the left or counter-rotated, the cutters of the core bit, facing towards the center of the reamer, will be traveling in the same rotational direction as that of the reamer. It would take less rpm's on the small bit because the combined rpm's of the reamer and small bit would compound. To adjust for the additional rotational speed of the small bit, would require a smaller motor with a larger lobe configuration, which means more power and a slower rpm's.

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.

Claims

1. A dual bit well drilling mechanism for drilling attachment to a tubular well drilling string extending from a drilling rig located at the Earth's surface, comprising:

a well drilling mechanism being connected with the tubular well drilling string and having a connection box;

a tubular drilling housing having a threaded connection with said connection box and defining a fluid flow passage receiving drilling fluid from the tubular well drilling string and defining a housing chamber in communication with said fluid flow passage;

a reamer bit being connected with said tubular housing and having a multiplicity of formation cutter elements mounted thereto, said reamer bit being rotated by said well drilling mechanism and defining a formation core receiving receptacle centrally thereof;

a core removal bit chamber being defined by said reamer bit and having communication with said formation core receiving receptacle;

a core removing bit being supported for rotation within said core removal bit chamber and having core cutting members supported thereby and having a cutting face oriented for engaging and removing a formation core that remains as said formation cutter elements of said reamer bit cut a wellbore into the formation, said core removing bit having a reamer bit body and a cutter retention matrix defining a plurality of spaced blade members each having a multiplicity of formation cutter members; and

a drilling fluid actuated rotary motor being supported by said reamer bit body within said tubular drilling housing and having rotary driving relation with said core removal bit.

2. The dual bit well drilling mechanism of claim 1, comprising:

said core removal bit receptacle having eccentric relation with said formation core receiving receptacle;

said core removal bit having a plurality of PDC cutter supporting blades defining a cutting face; and

said reamer bit having a plurality of downwardly extending PDC cutter supporting blades having inner portions thereof disposed in overlapping relation with said cutting face of said core removal bit.

3. The dual bit well drilling mechanism of claim 1, comprising:

said reamer bit having clockwise rotation within the wellbore being drilled; and

said core removal bit having counter-clockwise rotation within said reamer bit.

4. The dual bit well drilling mechanism of claim 1, comprising:

said drilling fluid actuated rotary motor having a tubular mud motor housing being supported within said tubular drilling housing by said reamer bit;

a stator member being substantially fixed within said tubular mud motor housing and defining a substantially helical inner peripheral surface;

a rotor member being rotatably supported within said stator member and having a substantially helical outer peripheral surface and being rotated by drilling fluid flow between said rotor member and said stator member, said rotor member having a motor output shaft;

a core removal bit drive shaft being in driven relation with said motor output shaft, said core removal bit being located at a retracted position within said reamer bit and having a cutting face exposed to said downwardly facing central opening and being mounted to said core removal bit drive shaft

a bearing pack mechanism being located within said tubular mud motor housing and providing rotary support and stabilization of said core removal bit drive shaft; and

said core removal bit drive shaft and said bearing pack defining flow passages permitting flow of drilling fluid therethrough for lubrication and cooling of said bearing pack mechanism and for lubrication and cooling of said core removal bit and for flushing drill cuttings from said cutting face of said core removal bit.

5. The dual bit well drilling mechanism of claim 4, comprising:

said tubular drilling housing and said drilling fluid actuated rotary motor having numerous threaded connections, said threaded connections of said drilling fluid actuated rotary motor having left hand threads that resist becoming unthreaded by the counteracting reactive torque of core removal bit rotation;

a rotary core removal bit drive shaft being driven by said drilling fluid actuated rotary motor; and

said core removing bit having right hand threaded connection with said rotary core removal bit drive shaft.

6. The dual bit well drilling mechanism of claim 4, comprising:

a central fluid flow passage being defined by said rotary core removal bit drive shaft;

a fluid distribution passage being defined by said core removing core removal bit and having communication with said central flow passage of said rotary core removal bit drive shaft; and

a fluid flow control nozzle being mounted to said core removing core removal bit and controlling the discharge of drilling fluid to said cutting face of said core removing bit.

7. The dual bit well drilling mechanism of claim 1, comprising:

a core of formation material being located within said formation core receiving receptacle of said reamer bit and serving to stabilize said reamer bit during wellbore drilling and providing reamer bit gauge protection minimizing lateral off-gauge movement of said reamer bit within the formation being drilled; and

a plurality of gauge protector members being mounted to said reamer bit within said formation core receiving receptacle and minimizing erosion of the core of formation material and minimizing erosion of said formation core receiving receptacle during drilling activities and stabilizing said reamer bit against lateral off-gauge movement within the formation material.

8. The dual bit well drilling mechanism of claim 1, comprising:

said reamer bit defining lateral internal and external surfaces having erosive contact with the formation material during drilling activity; and

a plurality of gauge protector members being mounted to said lateral internal and external surfaces of said reamer bit and minimizing erosion of said lateral internal and external surfaces and minimizing erosion of the formation material during drilling activities and thus stabilizing said reamer bit during drilling and minimizing gauge enlarging movement of said reamer bit within the formation.

9. The dual bit well drilling mechanism of claim 1, comprising:

a drilling fluid inlet passage being defined by said tubular drilling housing;

a high pressure fluid flow chamber being defined within said tubular drilling housing and externally of said drilling fluid actuated rotary motor; and

a fluid inlet fitting defining an upper portion of said drilling fluid actuated rotary motor and defining a motor actuation passage, said fluid inlet fitting permitting a predetermined flow of drilling fluid from said high pressure fluid flow chamber through said drilling fluid actuated rotary motor for core removal bit rotation, for cooling lubrication and flushing of drill cuttings from said core removing bit.

10. The dual bit well drilling mechanism of claim 1, comprising:

a core removal bit bore being defined by said reamer bit body and being disposed in eccentric relation with said formation core receiving receptacle; and

said core removing bit being positioned for rotation within said core removal bit bore and having said cutting face oriented for substantially continuous cutting engagement with the formation core as said formation cutter elements of said reamer bit body penetrate into the formation being drilled.

11. The dual bit well drilling mechanism of claim 1, comprising:

a core removal bit bore being defined by said reamer bit body and being disposed in concentric relation with said formation core receiving receptacle; and

said core removing bit being positioned for rotation within said core removal bit bore and having said cutting face oriented for substantially continuous cutting engagement with the formation core as said formation cutter elements of said reamer bit body penetrate into the formation being drilled.

12. The dual bit well drilling mechanism of claim 1, comprising:

said reamer bit having a reamer bit body mounted to said tubular drilling housing;

a cutter retention matrix being adhered to said reamer bit body and defining bit outer periphery and a formation core receiving receptacle, said cutter retention matrix defining a plurality of cutter retention blades extending from said bit outer periphery to said formation core receiving receptacle;

a multiplicity of PDC cutter elements being mounted to said cutter retention blades and defining a reamer bit cutter array; and

said core removing bit having driven relation with said rotor member and being positioned within said formation core receiving receptacle for core removing engagement with the formation core.

13. A dual bit well drilling mechanism for drilling attachment to a tubular well drilling string extending from a drilling rig located at the Earth's surface, comprising:

a tubular drilling housing having a threaded connection with said well drilling string and defining a fluid flow passage receiving drilling fluid from the tubular well drilling string and defining a housing chamber in communication with said fluid flow passage;

a stator member being mounted in substantially fixed and sealed relation within said tubular drilling housing and defining a generally helical internal fluid flow reaction profile;

a rotor member being rotatably positioned within said stator member and having a generally helical external fluid flow reaction profile for fluid flow responsive rotation of said rotor member by drilling fluid flow, said rotor member defining a central passage therethrough and defining an open end;

a reamer bit being defined by said tubular drilling housing and having a multiplicity of formation cutter elements mounted thereto, said tubular drilling housing and said reamer bit being rotated by said well drilling mechanism and defining a formation core receiving receptacle centrally thereof;

a core removal bit chamber being defined by said reamer bit body and being exposed to said formation core receiving receptacle; and

a core removing bit being supported for rotation within said core removal bit chamber and having rotary driven relation with said rotor member, a plurality of core removal members supported thereby, said core removing bit having a cutting face oriented for engaging and removing a formation core that remains as said formation cutter elements of said reamer bit body cut a wellbore into the formation.

14. The dual bit well drilling mechanism of claim 13, comprising:

said rotor driven shaft being flexible and absorbing rotary shock forces transmitted there to by said rotor member and minimizing rotary shock forces being transmitted to said core removal bit operating shaft and to said core removal bit.

15. The dual bit well drilling mechanism of claim 13, comprising:

said reamer bit having a reamer bit body mounted to said tubular drilling housing;

a cutter retention matrix being adhered to said reamer bit body and defining bit outer periphery and a formation core receiving receptacle, said cutter retention matrix defining a plurality of cutter retention blades extending from said bit outer periphery to said formation core receiving receptacle;

a multiplicity of PDC cutter elements being mounted to said cutter retention blades and defining a reamer bit cutter array; and

said core removing bit having driven relation with said rotor member and being positioned within said formation core receiving receptacle for core removing engagement with the formation core.

16. The dual bit well drilling mechanism of claim 13, comprising:

a bearing pack being mounted to said reamer bit body

a shaft being rotated by said rotor member and having a portion thereof located within said central passage of said rotor member;

a core removal bit operating shaft extending through said bearing pack and having driven connection with said rotor driven shaft and having driving connection with said core removing bit.

17. The dual bit well drilling mechanism of claim 16, comprising:

said bearing pack defining drilling fluid flow passages permitting flow of drilling fluid therethrough for cooling and lubricating said bearing pack, for cooling of said core removing bit and for flushing away drill cuttings from said core removing bit.

18. A method for drilling wells in consolidated earth formations, comprising:

rotating in formation cutting engagement with an earth formation a drilling mechanism having a tubular drilling housing and a reamer bit connected with said tubular drilling housing, said reamer bit defining a cutting face and defining a downwardly facing core receiving receptacle within which a substantially cylindrical formation core left by said reamer bit is received during drilling;

rotating a core removal bit within said reamer bit with a drilling fluid energized rotary motor having a tubular motor housing supported within said tubular drilling housing by said reamer bit, said core removal bit having a core cutting face exposed to said downwardly facing core receiving receptacle and in cutting engagement with a circular end of the substantially cylindrical formation core and having a retracted position within said reamer bit with its core cutting face offset from said cutting face of said reamer bit, said retracted position determining the length of the substantially cylindrical formation core;

conducting drilling fluid flow through said drilling fluid energized rotary motor, through a bearing pack within said drilling fluid energized rotary motor and through said core removable bit; and

discharging drilling fluid from said core removable bit into said downwardly facing core receiving receptacle at said cutting face of said core removal bit.

19. The method of claims 18, comprising:

engaging a generally cylindrical surface of the formation core within said downwardly facing core receiving receptacle by gauge protection members supported by said reamer bit internally of said downwardly facing core receiving receptacle and minimizing erosive wear of the formation core; and

utilizing the formation core to stabilize rotation and positioning of said reamer bit during drilling and maintaining the guage and orientation of the wellbore being drilled.

20. The method of claim 19, comprising:

controlling the flow of drilling fluid through said drilling fluid energized rotary motor and through flow passages of said bearing pack and core removing bit for cooling, lubrication thereof and for flushing away drill cuttings from said core removing bit.