Patent Publication Number: US-2019169935-A1

Title: Course holding method and apparatus for rotary mode steerable motor drilling

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     The present application is a continuation-in-part of U.S. patent application Ser. No. 15/430,254 filed on Feb. 10, 2017, which claims priority to U.S. Provisional Patent Application No. 62/295,904 filed Feb. 16, 2016, each of which is incorporated herein by reference as if set out in full. 
     The present application is also related to U.S. patent application Ser. No. 16/049,588 filed on Jul. 30, 2018, U.S. patent application Ser. No. 15/667,704 filed on Aug. 3, 2017, and U.S. patent application Ser. No. 15/808,798 filed on Nov. 9, 2017, each of which is incorporated herein by reference as if set out in full. 
    
    
     BACKGROUND 
     Hydrocarbon retorts for the most part reside beneath a surface layer of dirt and rock (and sometimes water as well). Thus, companies generally erect drilling rigs and drill piping from the surface to a point located below the surface to allow access and retrieval of the hydrocarbons from the retorts. 
     Drilling may comprise vertical wells, non-vertical wells, and combinations thereof. Vertical wells provide a reasonably straight drill path that is generally intended to be perpendicular to the earth&#39;s surface, and the drill bit is operational along the axis of the drill string to which it is attached. Non-vertical wells, also known as directional wells, usually involve directional drilling. Directionally drilling a well requires movement of the drill bit off the axis of the drill string. Generally, a directionally drilled wellbore includes a vertical section until a kickoff point where the wellbore deviates from vertical. 
     To directional drill, most operations use a motor steerable system or rotary steerable tool (sometimes referred to as RST or RSS). Both tools are useful because they allow for directional drilling (moving from vertical to horizontal in some cases), but also provide for a tool that generally travels in a straight path as well. A conventional RSS can generally be classified as a point the bit architecture or a push the bit architecture. A point the bit architecture generally flexes the shaft attached to the bit, to cause the bit to point in a different direction. The GEO-PILOT® rotary steerable system available from Halliburton Company is an exemplary point the bit architecture. A push the bit architecture generally has one or more pads on the outer surface of the rotating drill string housing. The pads press on the wellbore to cause the drill bit to move in the opposite direction causing a directional change in the wellbore. The AutoTrak Curve rotary steerable system, available from Baker Hughes Incorporated, is an exemplary push the bit architecture. Many companies offer steerable motors that incorporate a bent housing within its architecture that must be oriented in the desired position to generate the required directional change. The drill string that connects this assembly and bit to the rig floor must remain essentially stationary during the drilling of these directional change segments. Various RSS tool offerings have no non-rotational requirements or segments that need to be stationary while other RSS designs incorporate certain sections of the tool that must remain stationary or only rotate at a very slow speed. 
       FIG. 1 , for background, shows a conventional steerable motor system  10  that is part of drill string  12  that extends from the surface, at the most proximal end  50 , and terminates in drill bit  14  at distal end  52 . Conventionally, as drill string  12  rotates as shown by arrow R and mud flow through steerable motor  16  adds rotation to bit  14 , the steerable motor system drills in a generally straight line. The drilling path may be vertical or angled (generally between 0 to 90 degrees, but in some instances, up to 180 degrees with respect to vertical) depending on the drill plan. Once drill string  12  has deviated from vertical, a well bore direction is established and is typically measured, like a compass, as a magnetic heading or azimuth (ranging from 0 to 360 degrees). When steerable motor system  10  is being manipulated to directionally drill (by which directional or directionally drilling generally means modifying the angle of inclination and/or azimuth of the hole), where the rate of change is typically measured in degrees over a distance (generally degrees per 100 feet or degrees per 30 meters), rotation of drill string  12  from the surface is normally halted to facilitate directional change. As is well known in the art, one drawback of a conventional steerable system  10 , is that cessation of rotation may cause friction to turn from dynamic to static resulting in an undesirable increase in friction between drill string  12 , including steerable motor  16 , and the wellbore (not shown). 
     In any event, drill string  12  includes a number of segments, not all of which are shown in  FIG. 1 , including drill piping or tubulars  26  to the surface, steerable motor  16  and drill bit  14 . Steerable motor  16  generally comprises rotor catch assembly  18 , power section  20 , transmission  22 , bearing package  24 , and bit drive shaft  46  with bit box  34 . Power section  20  generally comprises stator housing  28  connected to and part of drill string  12 , and rotor  30 . Transmission  22  includes transmission housing  36 , that is part of drill string  12 , and transmission driveline  38  that connects rotor  30  to bit drive shaft  46 . Bearing package  24  includes bearing housing  42 , part of the drill string, and one or more bearing assemblies  44  that may include different combinations of axial, radial, and thrust bearings. Transmission housing  36  generally includes bend  35  to modify drill bit  14  angular rotation axis B relative to drill string  12  rotation axis A, generally a bend is from around 0.5 to 5.0 degrees. (The modification of the angular axis of rotation is more thoroughly described below and is well-documented art.) Because the magnitude of bend  35  can be visually relatively small, the direction of the bend plane is generally marked by a shallow longitudinal groove called scribe line  40 . 
     With mud flow, drilling mud (not shown) travels down internal cavities  32  of drill string  12  and through power section  20  causing rotor  30  to rotate with respect to stator housing  28  and therefore drill string  12 . Rotor  30  drives rotation through transmission driveline  38  and bit drive shaft  46 , to drill bit  14 . Depending on the rotation direction (clockwise or counter clockwise) of rotor  30  relative to drill string  12 , power section  20  can increase, decrease or reverse the relative rotation rate of drill bit  14  with respect to a rotating drill string  12 . During drilling operations with a conventional steerable motor assembly  10 , when it is determined to be desirable to modify the trajectory (angle of inclination and azimuth) of the wellbore, rotation of drill string  12  is terminated while maintaining mud flow through motor power section  20  and therefore continuing rotation of drill bit  14 . By one of many methods that are well known and regularly practiced in the industry (such as MWD tools, LWD tools, drilling gyro tool and wireline orienting tool), the current orientation of drill bit  14  is determined. Drill string  12  is then manually oriented from the surface, generally by fractions of a full rotation, until scribe line  40  (and therefore bit  14 ) is oriented in the desired direction. Thus, the wellbore direction is altered in the direction of the scribe line  40  by the continued rotation of the drill bit  14  via the steerable motor  16  while the drill string  12  is not rotating. As the well continues to be drilled, the orientation of the scribe line  40  is continually monitored and adjusted to create the desired wellbore path. The adjustment of the scribe line  40  conventionally includes manual orientation of the drill string to keep the scribe line  40  oriented in the desired direction. The details of conventional steerable motor system  10  are reasonably well known in the industry and will not be further explained except as necessary to understand the technology of the present application. 
     Drill bit  14  conventionally can be a number of different styles or types of drill bits. Drill bit  14  may be a polycrystalline diamond cutter (PDC) design, a roller cone (RC) design, an impregnated diamond design, a natural diamond cutter (NDC) design, a thermally stable polycrystalline (TSP) design, a carbide blade/pick design, a hammer bit (a.k.a. percussion bits) design, etc. Each of these different rock destruction mechanisms has qualities that make it a desirable choice depending on formation to be drilled and available energy in association with the drilling apparatus. 
     For a variety of disparate reasons, drill bit technology integrated within a drilling apparatus or drilling machine methodology could use much improvement, whether implemented in a vertical drilling system or incorporated into a Steerable Motor or RSS usable with directional drilling. Thus, against the above background, improved drill bits separately or as part of an integrated drilling apparatus or machine coordinated with drill string components, are further described herein. 
     SUMMARY 
     This Summary is provided to introduce a selection of concepts in a simplified form that are further described below in the Detailed Description. This Summary, and the foregoing Background, is not intended to identify all key aspects or essential aspects of the claimed subject matter. Moreover, this Summary is not intended for use as an aid in limiting the scope of the claimed subject matter. 
     In some aspects of the technology, a downhole drilling apparatus or machine is provided. The drilling apparatus or machine comprises a drill bit or cutting structure assembly having a pad that can extend generally perpendicularly to the bit axis by a variable amount from a minimum distance to a maximum distance where the minimum distance is flush or recessed with an axial sidewall of the drill bit or drill string. In the extended position, the pad has a surface that is configured to engage the sidewall of a wellbore. The drilling apparatus may include an actuator to move the pad between the extended position and the retracted position. In certain aspects, the actuator is a push rod or cam follower driven by a cam. The actuator can provide a solid/positive transfer of force or the actuator can provide compliant transfer of force to limit travel, force or both. In other aspects, the actuator is a cam. In still other aspects, the actuator can be magnets configured to attract or repel depending on proximity and magnetic pole orientation. The push rod may include a taper such that the pad is positionable at a plurality of positions between the maximum extension in the extended position and the minimum position in the retracted position. The drill bit or cutting structure assembly comprises a plurality of cutting elements. When extended, the pad is configured to push against the sidewall and move the drill bit and cutting elements in an opposing direction. 
     In certain embodiments, the drill bit may include at least one lateral cutting apparatus located on a side of the drilling apparatus. At least one lateral cutting apparatus would generally engage the sidewall of a wellbore and remove formation at least when the pad is in the extended position. As a result of the added force of the lateral pad or pads, the opposing cutting structure design could have a variable position design or an enhanced fixed cutter design to assist in the directional change capacity. 
     In certain aspects, the drilling apparatus comprises a plurality of pads, wherein each of the plurality of pads is operatively coupled to at least one actuator such that as the plurality of pads are configured to rotate with the drill bit or configured to rotate with the drill string that is generally not rotating while directionally drilling. The actuator may be configured to move each of the plurality of pads from the retracted position to the extended position wherein a maximum extension occurs at a position generally opposite a minimum extension. 
     In certain aspects, the pad begins moving from a retracted position to an maximum extended position and back to a retracted position as the pad rotates about a longitudinal axis of the drilling apparatus. The pad may begin extending and retracting at virtually any angle such as about 30, 45, 90, or 135 degrees and be fully retracted at a corresponding 330, 315, 270, 225 degrees of rotation providing generally symmetric operation. Of course, the pad may begin extension at less than 15 degrees of rotation and finish retracting at greater than 345 degrees of rotation. In certain other embodiments, aspects relating to such things as drilling system design and formation properties may be better optimized using asymmetric operation modes where the pad may be begin extending at say 135 degrees and not be fully retracted until 330 degrees of rotation. In certain embodiments, the pad may always be slightly extended. A further aspect provides for multiple full or partial extensions and retractions of a pad or a plurality of pads during each revolution to improve cutting effectiveness by providing multiple cutter engagements to the well bore. Another embodiment would be to extend a pad or pads off center of the cutter or cutters to modify the cutter contact angle with the well bore. 
     In other embodiments, a downhole drilling apparatus to be attached to a drill string is provided. The apparatus has a drill bit having at least one cutting element axially extending out to the sidewall and a drill bit having a plurality of cutting structures. A cutting pad is operatively coupled to a recess formed in the outer sidewall of the drill bit. A cutting element is coupled to an outwardly facing surface such that at least when in the extended position, the cutting element is configured to engage a sidewall of a wellbore to remove formation. 
     In certain embodiments, and generally applicable with any drilling apparatus or drilling machine methodology using moveable pads to contact the bore hole, the pad extension path can be axially rotated from perpendicular (by around 2 to 45 degrees) to push the drill string forward or better align the contact plane of the pad with the borehole wall to minimize pad pressure or both when extended. In certain aspects, the cam can include a conical profile such that an axially rotated extension pad can be engaged with a cam race that is parallel with the plane of the pad to contact the borehole wall. A further aspect provides a pad path that is cross-axially offset to provide a side force temporarily across an opposing cutter face. 
     In certain embodiments, the technology of the present application provides a drill string that includes a power section to provide rotative force and a transmission that is operatively coupled to the power section. A monolithic or integral drill bit/drive shaft consists of a drill bit portion at a distal end and a drive shaft portion at a proximal end, wherein the transmission is operatively coupled to the proximal end of the monolithic or integral drill bit/drive shaft to transmit rotative force from the power section to the drill bit portion. The drill string may further include a bearing section and possibly a bent housing section. 
     In some aspects of the technology, a downhole apparatus is provided that comprises at least a dual rotating cutting structure having various cutting element types positioned on an inner assembly element and on a separate outer cutting structure where the power source to rotate the two cutting structures can be independently derived. In almost all cases, the resultant rotation rate for each cutting structure would be different. In those cases, where PDC cutters are used to form both the internal and external cutting structures a lower rotation rate of the outer cutting structure can result in a matched or lower surface speed than the internal cutting structure. This can extend the life of the PDC cutter by reducing and better controlling heat generation in the outermost cutters. Additionally, having multiple PDC cutting structures rotating at different rotation rates allows for designing a better mechanical solution to fail (destroy rock) in distinct areas of the formation to be drilled. 
     In certain embodiments, a plurality of rotating cutting structures would be associated with a bent housing above said rotating cutting structures to support the efficient removal of the central area of the wellbore. In this configuration, the directional usefulness of the bent housing would not be available unless it only supported a rotating directional tendency of the assembly. 
     In certain other embodiments, the technology of the present invention provides a drill string that may include various sizes and shapes of mud motors to accommodate reduced power requirements. The drill string may further include a bearing section and transmission section sized accordingly to the reduced loads anticipated versus a standard single bit/motor combination. 
     In some aspects of the technology, a downhole apparatus is provided that employs one or more motor mandrel cam-driven pads to provide a restoration force in opposition to the deviation force of the rotating assembly. In certain embodiments, the pad(s) are deployed generally on the bend side of the downhole apparatus proximal to the drill bit and distal of the bend of the bend housing. The pad(s) may deploy and retract one or more times per motor (mandrel) revolution depending on the mandrel cam configuration. In certain embodiments, the pad(s) are provided with a stroke that pushes them out to a diameter substantially equal to, or slightly greater than, the bit diameter. In embodiments where the downhole apparatus is biased against the hole wall, the pad(s) can push against the hole wall with a greater force or frequency in opposition to the deviation bias direction providing a restorative force to the downhole apparatus. The action of the pad(s) may counter the deviation force, thereby reducing or eliminating the directional tendency. 
     These and other aspects of the present system and method will be apparent after consideration of the Detailed Description and Drawings herein. 
    
    
     
       DRAWINGS 
       Non-limiting and non-exhaustive embodiments of the present invention, including the preferred embodiment, are described with reference to the following figures, wherein like reference numerals refer to like parts throughout the various views unless otherwise specified. 
         FIG. 1  provides a cross-sectional view of a conventional steerable motor system. 
         FIG. 2  provides a cross-sectional view of a drilling assembly having a dynamic lateral pad consistent with the technology of the present application.  FIG. 2  also includes a side view and isometric view of a monolithic or integral drill bit/drive shaft. 
         FIG. 3A  provides a comparison between a conventional motor drill string and an improved motor drill string having a monolithic or integral bit/drive shaft consistent with the technology of the present invention. 
         FIG. 3B  provides a comparison between a conventional motor drill string with a bend and an improved motor drill string having a monolithic or integral drill bit/drive shaft and bend consistent with the technology of the present invention. 
         FIG. 4A  provides a side view of a drill string with an axial cam and integral drill bit/drive shaft consistent with the technology of the present application. 
         FIG. 4B  provides a cross-section view of the drill string provided in  FIG. 4A . 
         FIG. 4C  provides a cross-section view of the drill string provided in  FIG. 4A  without a bend. 
         FIG. 5A  provides a cross-sectional view of a drill string including a dynamic lateral pad and sleeve cam consistent with the technology of the present application. 
         FIG. 5B  provides a series of end views of the drill string provided in  FIG. 5A  showing bit rotation and pad movement at successive 90 degree rotation intervals. 
         FIG. 6  provides a cross-sectional view of a monolithic or integral drill bit/drive shaft having multiple dynamic lateral pads consistent with the technology of the present application. 
         FIG. 7  provides a cross-sectional view of a monolithic or integral drill bit/drive shaft having a dynamic lateral pad and bit shank cam consistent with the technology of the present application. 
         FIG. 8A  provides a cross-sectional view of drill string  800  including a monolithic or integral drill bit/drive shaft, a plurality of Dynamic Lateral Pads (DLPs), a plurality of Dynamic Lateral Cutters and sleeve cam consistent with the technology of the present application. 
         FIG. 8B  provides an end view of the drill string provided in  FIG. 8A  illustrating an odd number of blades, cutters and pads consistent with the technology of the present application. 
         FIG. 9  provides a series of alternative embodiments for dynamic lateral pad and dynamic lateral cutter mechanisms. 
         FIG. 10A  provides a side-by-side partial section view of a Dual Rotating Cutting Structure (DRCS) system, with and without a bend, consistent with the technology of the present application. 
         FIG. 10B  provides an enlarged side view of the dual rotating cutting structure portion of  FIG. 10A . 
         FIG. 10C  provides a cross-sectional view of Dual Rotating Cutting Structure (DRCS) system with a protruding inner drill bit or inner cutting structure as provided in  FIG. 10B , consistent with the technology of the present application. 
         FIG. 11  provides a cross-sectional view of a Dual Rotating Cutting Structure (DRCS) system with a substantially flush inner drill bit or inner cutting structure consistent with the technology of the present application. 
         FIG. 12  provides a cross-sectional view of a Dual Rotating Cutting System (DRCS) with a recessed inner drill bit or inner cutting structure consistent with the technology of the present application. 
         FIG. 13  provides a cross-sectional view of a Dynamic Lateral Pad (DLP) system with a bit box cam, hinged circumferential pad and compliant actuator consistent with the technology of the present application and also including an isometric view and side view with multiple compliant actuator in various positions. 
         FIG. 14  provides a cross-section view of a Dynamic Lateral Pad (DLP) system with magnetic actuators consistent with the technology of the present application with an extended pad. In addition,  FIG. 14  provides an isometric view, and a side view with the pad retracted and a section view of the magnetic actuator. 
         FIG. 15  provides a cross-sectional and isometric view of a Dynamic Lateral Pad (DLP) system with a bit box cam, axially hinged pad and solid actuator consistent with the technology of the present application. 
         FIG. 16A  provides a cross-sectional view of a bit mounted Dynamic Lateral Pad (DLP) with a sleeve cam with an extended pad consistent with the technology of the present application. In addition,  FIG. 16A  provides an isometric view and a section view of a retracted pad. 
         FIG. 16B  provides a cross-sectional view of a bit mounted Dynamic Lateral Pad (DLP) and Dynamic Lateral Cutter (DLC) with sleeve cam and an extended pad with cutters consistent with the technology of the present application. In addition,  FIG. 16B  provides an isometric view and a section view of a retracted pad with cutters. 
         FIG. 17  provides a cross-sectional view of a dynamic bit blade with sleeve cam and an extended blade consistent with the technology of the present application. In addition,  FIG. 17  includes an isometric view and a section view of a retracted blade. 
         FIG. 18  provides a cross-sectional view of an eccentric bearing housing with pockets consistent with the technology of the present application. In addition,  FIG. 18  includes an isometric view, an end view and a section view of the eccentric bearing housing and a covered pocket. 
         FIG. 19A-H  provide views of several exemplary embodiments of drill bit and drill string sections incorporating technology consistent with the disclosure of the present application. 
         FIG. 20  provides a typical tool face angle chart or dial. 
         FIG. 21A  provides a cross-sectional view of an oversized rotary drilled hole at the locations of a rotating bit gauge circumference. 
         FIG. 21B  provides a detailed view of the cross-sectional hole center shown in  FIG. 21A  in neutral drilling mode. 
         FIG. 21C  provides a detailed view of the cross-sectional hole center shown in  FIG. 21A  experiencing a deviation bias. 
         FIG. 22  provides a generalized and exaggerated comparative side view of a neutral drilling borehole and a drop deviation borehole. 
         FIG. 23  provides a generalized and exaggerated comparative side view of a neutral drilling borehole and a left turn deviation borehole. 
         FIG. 24  provides an end view of a neutral drilling borehole. 
         FIG. 25  provides an end view of a deviated dropping and left turning borehole. 
         FIG. 26A  provides an isometric view of a partial section of a basic Dynamic Lateral Pad (DLP) assembly consistent with the technology of the present application. 
         FIG. 26B  provides a cross-sectional view of a Dynamic Lateral Pad (DLP) assembly taken through section A-A of  FIG. 26A . 
         FIG. 27A  provides a cross-sectional view of an oversized rotary drilled hole at the location of a rotated cross-section of a deployed Dynamic Lateral Pad (DLP) during neutral drilling consistent with the technology of the present application. 
         FIG. 27B  provides a cross-sectional view of the oversized rotary drilled hole of  FIG. 27A  with a rotated and retracted Dynamic Lateral Pad (DLP). 
         FIG. 28  provides a cross-sectional view of an oversized rotary drilled hole at the location of a cross-section of a deployed Dynamic Lateral Pad (DLP) experiencing a deviation bias. 
         FIG. 29  provides a generalized top view of a borehole centerline over a brief drilling interval under the influence of a deviation force, restoration force provided by a Dynamic Lateral Pad (DLP), and resultant penetration force consistent with the technology of the present application. 
     
    
    
     DETAILED DESCRIPTION 
     The technology of the present application will now be described more fully below with reference to the accompanying figures, which form a part hereof and show, by way of illustration, specific exemplary embodiments. These embodiments are disclosed in sufficient detail to enable those skilled in the art to practice the technology of the present application. However, embodiments may be implemented in many different forms and should not be construed as being limited to the embodiments set forth herein. The following detailed description is, therefore, not to be taken in a limiting sense. Moreover, reference may be made to the figures using relatively locational or directional terms, such as, for example, top, bottom, left, right, axial up, axial down, radial outward, radial inward, or the like. The terms are used to describe relative movement and locations and should not be considered limiting. 
     The technology of the present application is described, in some embodiments, with specific reference to steerable motor systems. However, the technology described herein may be used for other applications including, for example, vertical drilling as well as directional drilling, and the like. Additionally, certain embodiments of the technology of the present application may be generally described with respect to a dual rotating cutting system having inner and outer bits or cutting structures that may include motor systems incorporating a bent housing that is not used for active directional drilling change requiring slide drilling. One of ordinary skill in the art will now recognize, on reading the disclosure, that more than two cutting structures are possible by providing inner, intermediate, and outer cutting structures for example. Moreover, the technology of the present application will be described with relation to exemplary embodiments. The word “exemplary” is used herein to mean “serving as an example, instance, or illustration.” Any embodiment described herein as “exemplary” is not necessarily to be construed as preferred or advantageous over other embodiments. Additionally, unless specifically identified otherwise, all embodiments described herein should be considered exemplary. 
       FIG. 2  shows a cross-sectional view of Dynamic Lateral Pad (DLP) system  200  consistent with the technology of the present application. DLP system  200  is shown in isolation from the remainder of the drill string for convenience. DLP system  200  includes a unitary, integral, or monolithic drill bit/drive shaft  202  (hereinafter integral or monolithic drill bit/drive shaft). Integral drill bit/drive shaft  202  has distal end  203  that terminates in a plurality of cutters  204 . Cutters  204 , in this case, are shown as PDC cutters, but could be, for example roller cones or the like. Integral drill bit/drive shaft  202  has a first diameter (generally the diameter of bit gauge  210 ) at the distal end of D′. Integral drill bit/drive shaft  202  also has proximal end  206  coupled to the transmission which then is connected to the rotor of the power section (shown below with reference to  FIGS. 3A and 3B ). Integral drill bit/drive shaft  202  has a second diameter at the proximal end of D″. As shown, D′ is generally greater than D″ such that the drill bit portion of integral drill bit/drive shaft  202  extends the diameter of, but also rotates within, the wellbore (not shown); whereas, the drive shaft portion of integral drill bit/drive shaft  202  fits and rotates within drill string housing  208 , therefore drill string housing  208  must generally have a diameter that is equal to or less than D′. 
     Distal end  203  of integral drill bit/drive shaft  202  has an axial surface formed by bit gauge  210  and upper radial surface  212 . Pad hole  214  extends through bit gauge  210  radially inward a distance d 1  and forms a volume. Actuator hole  216  extends from upper radial surface axially downward a distance d 2  and forms a volume that intersects with pad hole  214 . Pad  218  is sized to movably engage pad hole  214 . Pad  218  moves radially in and out as shown by arrow B. Pad  218  may include a stop  219  to inhibit pad  218  from exiting pad hole  214 . Acceptable pad  218  materials include hardened steel or ceramic that would be known to those ordinarily skilled in the art. Actuator  220 , which is shown as a push rod, or cam follower is sized to movably engage actuator hole  216 . By way of reference, the term actuator should be construed as a device, structure, or means to provide a motive force tending to cause the associated pad (or pads) to move radially in at least one direction. Actuator  220 , which is one exemplary means for actuating, rides between pad  218  and the axial cam profile formed in the distal end of non-rotating axial cam sleeve  224 . Axial cam sleeve  224  terminates in a spiral shaped or ramped cam surface  225 . The spiral shape or ramp of cam surface  225  means cam sleeve  224  extends further on one side of integral drill bit/drive shaft  202  than the other and that cam surface  225  has a continuous, potentially constant slope up and down between minimum and maximum axial extension. Actuator  220  moves laterally up and down as shown by arrow C. Axial cam sleeve retainer  222  and axial cam sleeve  224  are operatively coupled and connected to the housing of the drill string. As the integral drill bit/drive shaft rotates relative to generally non-rotating housing  208 , sleeve retainer  222  and axial cam sleeve  224 . Axial cam sleeve  224  acts on actuator  220  to cause the actuator to slide, in this exemplary embodiment, into actuator hole  216 . Sloped surface  226  of actuator  220 , in this exemplary embodiment, drives pad  218  radially out to an extended position. Reactive force from the wellbore wall (not shown) on pad  218  acts to move pad  218  to a flush position as the axial cam rotates back to the start position. A bearing assembly  228 , as is conventional, supports integral drill bit/drive shaft  202  in housing  208 . 
     For convenience and understanding, in certain aspects, reference will be made to the parts and components of a drill string described in  FIG. 1  while describing the technology of the present application. Power section  20  to which an integral drill bit/drive shaft  202  is connected comprises a transmission, mud turbine, positive displacement mud motor or other type of apparatus that creates suitable drilling action downhole. Other such apparatus include an electric motor, reciprocating motor or other type of motor to facilitate driving integral drill bit/drive shaft  202  or, as is conventional today, drill bit  14  connected to bit box  34  that is part of drive shaft  46 . As one of ordinary skill in the art would understand, a drill string having for example a positive displacement motor includes: (1) a power section, which comprises the rotor and stator, (2) drive shaft, optionally (3) a bent housing (generally only included in directional assemblies), (4) a transmission coupling the power section to the drive shaft, and (5) a bit box to connect a conventional bit. Referencing back to  FIG. 1 , conventional drive shaft  46  is contained in a bearing housing  24  having both axial and radial bearings  44 . The distal end of drive shaft  46  typically terminates in bit box  34  containing an API connection  37  (not shown) appropriate for the hole size being drilled. A separate drill bit  14 , having a corresponding thread, is coupled to the distal end of drive shaft  46  through API connection  37  (not shown) on bit box  34 . Connections other than threaded connections are possible such as a weld, interference fit, or other non-threaded attachment. 
     Although introduced as part of DLP system  200 , integral drill bit/drive shaft  202  would increase the effectiveness of most drilling systems, including conventional steerable motor system  10 , rotary steerable systems (not shown) and straight hole motor systems  300  ( FIG. 3A ), without incorporating dynamic lateral pad system  200  described in  FIG. 2 . As compared to conventional designs, providing monolithic or integral drill bit/drive shaft  202 , as shown above, allows reduction of the distance from the most distal bearing set and the distal end of any drilling assembly. In directional assemblies with bend  35 , integral drill bit/drive shaft  202  also allows reduction of the distance from bend  35  to distal end  52  of drill bit  14 . Decreasing the distance from the most distal bearing set to the distal end of the drilling assembly and decreasing the distance from the bend on directional assemblies to the distal end of the bit improves drilling performance. By example, the shortened distance from the distal end of the bit to the bend on any directional assembly, generally means a more aggressive ability to move the drill axis off vertical or to change wellbore direction. The shortened distance from the most distal bearing set to the distal end of the drilling assembly significantly reduces counter-productive flex and possible failure points related to the added length required to form and service the connections. The shortened distance also reduces bending moments in the drive shaft resultant from the flex created by the connection of bit box  34  and drill bit  14 . Decreased bending moments reduce bearing loads and resultant wear in all motors and other systems described above and reduce the potential for erratic bending vectors attributed to misalignment of the conventional API bit box and drill bit connection. Cutters of integral drill bit/drive shaft  202  could be made with any rock destroying cutting structures (i.e.; PDC, Roller Cone, Impregnated, Natural Diamond, etc.) 
       FIG. 3A  shows a side by side comparison of a conventional motor drill string  300  and improved motor drill string  390  using integral drill bit/drive shaft  202  of the present application described above (both drill strings are without a bend). Both drill string  300  and drill string  390  include power section  320 , transmission section  322  and bearing section  324 . Conventional motor drill string  300 , however, incorporates conventional drive shaft  346  with bit box  334 , and separate drill bit  314  having API connection  337  (not shown) to couple to bit box  334 . Conversely, improved motor drill sting  390  has a monolithic or integral drill bit/drive shaft  202 . By replacing conventional drive shaft  346  and drill bit  314  with integral drill bit/drive shaft  202 , distal end  352  of conventional motor drill string  300  is a distance L farther from bearing section  324  than distal end  352 ′ of improved motor drill string  390 . 
       FIG. 3B  shows a side by side comparison of conventional directional drill string  391  and improved directional drill string  392  using integral drill bit/drive shaft  202  of the present application described above (both drill strings include a bend). Similar to the above, both conventional drill string  391  and improved drill string  392  includes power section  320 , transmission section  322  and bearing section  324 . In this example, conventional drill string  391  and improved drill string  392  also includes bent housing  335 . Conventional directional drill string  391 , however, incorporates a conventional drive shaft  346  with bit box  334 , and separate drill bit  314  having API connection  337  (not shown) to couple to bit box  334 . Conversely, improved directional drill string  392  has a monolithic or integral drill bit/drive shaft  202 . As such, distal end  352  of conventional directional drill string  391  is a distance L′ farther from the bend in bent housing  335  than distal end  352 ′ of improved directional drill string  392 . 
     Conventional directional drill string  391  has longitudinal axis A extending above and through power section  320  and, after the bend, longitudinal axis B extending through drive shaft  334  and drill bit  314  of drill string  391 . Improved directional drill string  392  has longitudinal axis C extending above and through power section  320  and, after the bend, longitudinal axis D extending through integral drill bit and drive shaft  202  of improved drill string  392 . Axis A and axis B form angle α and axis C and axis D form angle β, where angle β is capable of being less than angle α yet have the same or greater build rates provided the ratio of angle α to angle β is equal to or less than the ratio of the bit to bend distance (BTB) of conventional directional drilling string  391  and the bit to bend distance (BTB) of improved directional drill string  392 . Build rate is generally computed as the angular change of the wellbore path over a set distance, such as 100 feet or 30 meters. As shown, the cutters are conventional PDC cutters, but most any cutting structures and/or cutting elements are usable. Similar to  FIG. 3A ,  FIG. 3B  provides drill string  391  with conventional drill bit  34  and drill string  392  with integral drill bit and drive shaft  202  without DLP system  200  or DLC system  800  or combination, although DLP system  200  or DLC system  800  or combination could be used with any of the configurations shown in  FIGS. 3A and 3B . 
     As can now be appreciated, shorter lengths and smaller bends provide benefits for the overall drill operation. In certain aspects, the configuration of improved drill strings  390  and  392  provide reduction in stress on critical components most notably the drive shaft and bearing assemblies, reduction in magnitude of cyclical loads, higher build rates at lower bend angles, reduction in drag (resistance to axial movement along the path of the wellbore), increased power, and reduced bending moments as compared to conventional drill strings  300  and  391 . Eliminating the connection also allows for the potential for more efficient and effective use of downhole sensors, power sources for sensors, potential communication devices and additional actuators. These sensors, devices, actuators and power sources can now be placed in closer proximity to the cutting structure area or in other longitudinal space made available because of the shorter length of integral bit/drive shaft  202 . In addition, support wires and tubing can be prearranged during assembly at the shop, eliminating the hindrance of managing support wires and tubing across a rotary connection on the rig floor. 
     With reference back to  FIG. 2 , integral drill bit/drive shaft  202  comprises drill bit portion  401  with drive shaft portion  403  with no field connectors between the two portions. Drill bit portion  401  and drive shaft portion  403  are generally formed as a single unit, such as for example, machined from a single high strength steel forging, machined from a high strength metal bar, as an assembly between a low carbon steel bit core with drill bit matrix or steel bit head welded, shrink fit or chemically bonded to a drive shaft made from high strength steel. Alternatively, a custom or API threaded connection with no provision (axial length) included to make or break the connection at the drilling location. 
       FIG. 4A  provides a side view of DLP drill string  400  in wellbore  452  drilled in formation  450 . Drill string  400  includes power section  406 , bent section  408  (and an associated scribe line (not specifically shown)), bearing housing  410  and DLP system  200  (first presented in  FIG. 2 ). As shown, DLP system  200  includes a cam sleeve retainer  222 , cam sleeve  224  and drill bit portion  401  with a number of blades  412  each including actuator  220 , pad  218 , and cutters or attached integral cutting structures  414 , such as the PDC cutters shown. While shown as conventional blades  412  and cutting structures  414 , the use of the DLP system  200 , and other DLP system or the dynamic lateral cutter (DLC) system described below, may allow for customization of the blades  412  and cutting structures  414  to take advantage of the unique movement of the drill bit portion  401  caused by the DLP systems and DLC systems described herein. 
       FIG. 4B  provides a cross-sectional view of DLP drill string  400  shown in  FIG. 4A  and illustrates the directional drilling action of drill string  490  in operation. In particular, because actuator  220   1  has moved axially downward due to the rotation of drill bit portion  401  relative to stationary axial cam sleeve  224  and ramped cam surface  225 , pad  218   1  extends radially outward from blade  412   1  pressing against wellbore  452 . Pad  218   1  provides force A pressing against wellbore  452 . Force A results in pushing bit portion  401  in a direction opposite as shown by arrow B increasing the side cutting force of bit portion  401  against wellbore  452 . As can be appreciated; pad  218   1 , currently shown as extended radially in  FIG. 4B , rotates 360° with bit  401  about longitudinal axis E. Pad  218   1  is extending the most directly opposite the direction an operator desires to steer the bit, which is the target direction, which target direction is typically associated with the scribe line as described above. Ideally, pad or pads  218  (including pad  218   1 ) are completely retracted and either inset or flush with the blade&#39;s axial wall or bit gauge  210  when the pad is oriented in the target direction, which is generally when aligned with the scribe line as described above. Depending on operating conditions, desired build, and formations associated with the wellbore, the pad  218   1  may not be directly opposite the target direction and scribe line but rather have the maximum extension offset less or more than 180° from the scribe line. 
     While not limiting, the direction in which the operator desires to steer the bit, or target direction, will be designated as 0° with drill string  490  stationary and oriented such that ramped cam surface  225  of axial cam sleeve  224  provides maximum extension of pad  218   1  at 180°, although as described above, operating conditions, desired build, and formations may alter the general case. As appreciated, the 0° target direction also may be aligned with the scribe line in certain embodiments. In other embodiments, the target direction of the bit may not be associated with a scribe line. As blade  412   1  rotates around longitudinal axis E, axial cam sleeve  224  moves actuator  220   1  down forcing outward movement of pad  218   1  from flush or inset to extended. Similarly, from 180° to 360°, the relative rotation of axial cam sleeve  224  allows actuator  220   1  to move up thus allowing pad  218   1  to move inward from maximum extension back to flush or inset. While described over a full rotation, pad  218   1  may extend only at 180° in certain embodiments. In other embodiments, pad  218   1  may be flush from 0° to 45° and from 315° to 360° (the pad is extended from 45° to 315°). In still other embodiments, pad  218   1  may be flush from 0° to 90° and from 270° to 360° (the pad extended from 90° to 270°). The range of motion for pad  218   1  is provided by axial cam sleeve  224  having a ramped cam surface  225 . While described as symmetrical ranges, the ranges may be asymmetrical and rotationally offset as well. In addition, an oscillating cam profile can be provided such that the pad or pads may extend and retract partially or fully and may extend and retract multiple times during each rotation to add constant side force or pulsating side force or both in addition to the conventional forces pushing the cutters. 
     In addition to force A pushing to increase the side cutting force of bit portion  401  as shown by arrow B, force A literally moves bit portion  401 , including a portion of drill string  400  laterally. This movement, coupled with the vibration created by repetitive extension and retraction of actuators  220  and pads  218  can potentially reduce friction between drill string  400 , including the steerable motor (not shown), and wellbore  452  by breaking the static friction that normally occurs with non-rotating steerable motor system  10  ( FIG. 1 ). Additionally, lateral movement of drill bit portion  401  and drill string  400  can potentially break a seal that can form between drill string  400  and formation  450  caused by differential sticking from over pressure of the drilling fluids in a permeable formation  450 . 
       FIG. 4C  provides a cross-sectional view of DLP drill string  491  to help illustrate a unique and highly beneficial supplemental bit motion provided by all the dynamic lateral pad system. Drill string  491  is identical to drill string  400  and drill string  490  ( FIGS. 4A and 4B  respectively) except drill string  491  ( FIG. 4C ) does not include bend  408  shown in  FIGS. 4A and 4B . As previously described, because actuator  2201  moves axially downward due to the rotation of drill bit portion  401  relative to stationary axial cam sleeve  224  and ramped cam surface  225 , pad  218   1  extends radially outward from blade  412   1  pressing against wellbore  452 . Pad  218   1  provides force A pressing against wellbore  452  and pushing bit portion  401  in a direction opposite as shown by arrow B. This increases the side cutting force of bit portion  401  acting against the sidewall of wellbore  452  while simultaneously moving the center of the bit laterally, as shown by arrow C, providing lateral cutting action at the center of wellbore  452 . This lateral cutting action at the center of wellbore  452  reduces conventional drill bit inefficiencies by reducing or eliminating the possibility for pure drill bit portion  401  rotation that only fails rock by compressive failure. Moving the drill bit off its longitudinal axis provides a number of benefits over a conventional drill. One benefit is that conventional drill bits provided limited cutting forces at the geometric center of the drill bit, which is in part due to the lower rotational velocity of the cutting structures near the geometric center of the bit. The DLP system pushes the drill bit off the longitudinal axis and moves the geometric center of the drill bit as the drill operates. This also allows cutting structures with a higher rotational velocity (rpm) to drill the pile of formation that can build up at the center of the bit. While most beneficial with drilling systems without a bend like drill string  491 , drill string  300 , drill string  390  ( FIG. 3A ) and DRCS system  1000  (described below), drilling systems with a bend, like drill string  400 , drill string  391 , drill string  392  ( FIG. 3B ) and conventional drill string  12  ( FIG. 1 ), also benefit. 
     As described above, pad  218  may be provided on a drill string with an integral drill bit/drive shaft or on a conventional steerable motor string having a drill bit coupled to a drive shaft with bit box described above.  FIG. 5A  provides a cross-sectional view of a dynamic lateral pad (DPL) system  500  having a drive shaft  502  with bit box  504  at distal end  503  of drive shaft  502 . Drill bit  506  with API connection  508  is coupled to bit box  504 . Similar to drill bit portion  401  described above, drill bit  506  has a plurality of blades  510 . Blades  510  have an axial outer wall  512  with pad hole  514  to receive pad  516 . Blades  510  form channel  518  with bit box  504  into which radial cam sleeve  520  is operationally fitted. Drill bit  506 , blades  510 , outer wall  512 , pads  514  and drive shaft  502  rotate together relative to the generally non-rotating cam sleeve  520 , cam sleeve retainer  524  and drill string housing  522 . Cam sleeve  520 , in a manner similar to actuator  220  described above, moves pad  516  from a flush to an extended position, which pad  516  is currently shown extended. Cam sleeve  520  is coupled to drill string housing  522  by cam sleeve retainer  524 . As previously presented, pad  516 , presses against formation  550  providing a force shown by arrow A. Force A pushes the bit in a direction opposite as shown by arrow B. Also as previously presented, the cam action can provide symmetric, asymmetric or mixed motion. 
       FIG. 5B  provides multiple end views of DLP string  500  in  FIG. 5A  showing the relative position of pad  516  in a progression of incremental 90 degree rotational steps by drill bit  506 . While not limiting, the target direction in which the operator desires to steer the bit is shown by a double arrow T and will be designated as 0°. View  560  presents pad  516  positioned directly opposite target direction T at 180 degrees relative rotation, at maximum extension and pushing bit  506  in target direction T. As mentioned above, this exemplary embodiment describes the general case where the pad is extended a maximum distance directly opposite the target direction T. In certain embodiments, the maximum extension of the pad may be offset from 180 degrees. Also, for embodiments where the drill string has a bend or scribe line (as described above), the target direction T is generally aligned with the scribe line. As bit  506  rotates in direction R by 90 degrees into view  570 , as shown by arrow R 90 , rotationally stationary axial cam  520  allows extension of pad  516  to decrease as shown by arrow B. As bit  506  rotates an additional 90 degrees into view  580 , for a total of 180 degrees displacement as shown by arrow R 180 , pad  516  is oriented in target direction T but is not visible, as pad  516  has moved to the flush or inset position. Rotation into view  590 , as shown by arrow R 270 , extends pad  516  as shown by arrow C. Continued rotation to 360 degrees brings pad  516  back to the fully extended position shown by arrow A in view  560 . 
       FIG. 6  shows DLP system  600  with multiple pads  608  having radial cam sleeve  602  that is operatively coupled and connected to the housing of drill string  610 . Integral drill bit/drive shaft  604  rotates relative to the generally non-rotating (during steering of the bit) cam sleeve  602 . Radial cam sleeve  602  fits around integral drill bit/drive shaft  604 , above bit portion  601  to acts on pads  608 . Radial cam sleeve  602  has continuous circumferential cam race  603  with variable radial width as shown by the cross-sectional view in  FIG. 6 . Pad  608   1  is shown in an extended position while pad  608   2  is shown to be approximately flush. Radial width Wi of cam race  603  on axial cam sleeve  602  is greater at pad  608   1  than the radial width W 2  of radial cam sleeve  602  at pad  608   2 . The variable radial width of cam sleeve  602  may range from a minimum to a maximum. The minimum radial width would generally be located at the point closest to the direction in which the drill bit is to be pointed, whether a bent or straight drill string configuration; whereas, the maximum radial width would generally be located at a point opposite. As is well known by those familiar in the art, cam race  603  could be formed simply as an off center circle or profiled to better optimize pad  608  movement. Examples of potentially optimized pad  608  movement include steeper slopes for cam race  603  to provide more aggressive or faster movement of pad  608 , non-symmetric pad movement and a plurality of full or partial pad  608  movements, in and out, per rotation. 
       FIG. 7  shows DLP system  700  with shank cam. As can be appreciated, DLP system  700  with shank cam includes integral drill bit/drive shaft  706  having drill bit portion  701 , shank cam portion  702  and drive shaft portion  704 . Shank cam portion  702  includes radial cam race  703  that encircles or partially encircles integral drill bit/drive shaft  706 . Radial cam race  703  has variable radial width about the perimeter of integral drill bit/drive shaft  706  from a minimum radial width W 4  to a maximum radial width W 3 . At maximum radial width W 3 , pad  710  is extended to push against wellbore wall  752  a maximum amount to provide additional side force to actively steer the bit in the desired direction. At minimum radial width W 4 , pad  710  is retracted by contact with well bore  752  to become flush or even slightly inset relative to the outer diameter of pad carrier  715  thus discontinuing the added side force to the drill bit. Pad  710  is physically positioned in slot  714  formed in pad carrier  715  and is operationally coupled to pad carrier  715  and shank cam portion  702  of integral drill bit/drive shaft  706 . Pad carrier  715  allows radial movement of pad  710  and the combination of shank cam portion  702  and well bore  752  provides the radial locomotion. Integral drill bit/drive shaft  706  with shank cam portion  702  rotates relative to the generally non-rotating (during steering of the bit) pad  710  and pad carrier  715  that is fixedly connected to housing  716  and the drill string above (not shown) by retainer  716 . Integral drill bit/drive shaft  706  is rotatably coupled to string housing  712  with bearing assembly  718  as is generally known in the art. As one of ordinary skill in the art would appreciate on reading the application, DLP system  700  could be implemented with a conventional bit coupled to a conventional drive shaft as described throughout the application. 
     An alternate embodiment to retain and retract pad  710  would provide for a “T” shaped or similar slot (not shown) fabricated into shank cam portion  702  with a complementary “T” shaped profile (also not shown) attached to pad  710 . This would allow the cam to both push with cam race portion  703  to extend pad  710  and pull to retract pad  710  with the “T” slot. Additionally, a spring or springs (not shown) could be introduced between pad  710  and cam race portion  703  or pad  710  and pad carrier  715  to maintain continuous contact between pad  710  and wellbore  752 . Conversely, a spring or springs (not shown) could be introduced between pad  710  and cam race portion  703  or pad  710  and pad carrier  715  to retract pad  710  away from wellbore  752  when cam race portion  703  is approaching a minimum position. 
     As described generally above, the DLP systems provide for a pad that is radially movable inward and outward with respect to the central longitudinal axis of the drill string housing. The DLP pad pushes against the wellbore to move the drill bit (or drill bit portion of the drill string) in an opposing direction that would generally be the desired direction to accomplish the drilling objectives whether a directional drill or a straight drill. In certain aspects, the DLP may push against the wellbore to position the drill bit to help mitigate harmful rotational patterns or vibration tendencies also supporting drilling efficiency gains. Combining the DLP systems with a bent housing and integral drill bit/drive shaft would further optimize this technical gain. 
       FIG. 8A  shows a partial section view of DLC system  800  providing a plurality of Dynamic Lateral Pads (DLPs) and a plurality of Dynamic Lateral Cutters (DLCs). The basic DLC system  800  includes dynamic lateral pad with a cutter or series of cutters in certain aspects. As with the above, DLC system  800  is shown with integral drill bit/drive shaft  802  to reduce the overall distance between distal end  804  of drill string  806  and bend element  818 . Integral drill bit/drive shaft  802  is rotatably coupled to drill string  806  by bearing assembly  832 . While shown as with an integral drill bit/drive shaft  802  with drill bit portion  808  and drive shaft portion  810 , DLC system  800  could also use a conventional drill bit and conventional drive shaft as described herein. DLC system  800  further comprises pad  812  having a cutting element or cutting assembly  814 . Pad  812  is generally referred to as cutting pad  812  to distinguish from other pads as will be clear below. Cutting pad  812  is attached, in this exemplary embodiment, to a removable pad carrier and guide or cage  816 . Removable cage  816  is similar to the blades described above, but rather than being machined into the drill bit portion of integral drill bit/drive shaft  802 , cage  816  may be removed and replaced with a compatible alternate cage (not shown) allowing for greater operational flexibility and control regarding the location and number of pads that are radially positioned. Cage  816  may snap fit into a slot on integral drill bit/drive shaft  802  or, in other embodiments, cage  816  may be bolted, threaded, pinned, welded, chemically bonded or otherwise connected to integral drill bit/drive shaft  802 . 
     Similar to embodiments described above, cutting pad  812  moves inward and outwardly based on an actuator, which, in this exemplary embodiment, is cam sleeve  820  having cutting pad cam race  822 . Cam sleeve  820  is coupled to drill string  806  using retainer  824 . Cutting pad cam race  822  may have a variable radial width similar to the widths described above, but not re-summarized here. The wellbore sidewall  852  would be subject to more cutting force the further outward cutting pad  812  extends and with greater numbers of cutter pads  812 . DLC system  800 &#39;s destruction of formation  850  and therefore movement of bit portion  808  would be in the direction of cutter pad  812  extension. 
     Further, DLC system  800  may have bearing pad or pads  826 . The bearing pad is similar to the non-cutting pads described above and is referred to as a bearing pad as it does not including a cutting element. In this exemplary embodiment, the position of bearing pad  826  is controlled by a second actuator, bearing pad cam race  830 , which is also part of cam sleeve  820 . Bearing pad cam race  830  has a variable radial thickness generally 180 degrees out of phase with cutting pad cam race  822  such that bearing pad  826  pushes against the side of wellbore  850  a maximum amount when the opposite cutting pad  812  is exerting the maximum cutting force. As shown, cutting pad cam race  822  and bearing pad cam race  830  are provided on sleeve  820 , but could alternatively be provided in separate sleeves, machined directly into drive shaft portion  810 , or a combination thereof. Similarly, both pads could use an actuator similar to actuator  220  described with respect to  FIG. 2  above. Based upon the above teaching, one ordinarily skilled in the art could easily see that many additional cam races driving many additional bearing pads and cutter pads, with similar or differing cutting structures, operationally in or out of phase or operationally independent of the other actuators could be implemented. 
       FIG. 8B  shows an elevation view of an exemplary DLC system  800  with an odd number of blades  828  and removable cage (not visible) with cutting pad  812  and bearing pad  826  axially aligned with each blade  828 . The exemplary elevation view shows a cutting pad  812   1 , and bearing pads  826   3  and  826   4  in extended positions providing a direct, balanced and generally stable resultant force from the combination of force A 3  and force A 4 . The resultant of force A 3  and force A 4  moves drill bit, and therefore the wellbore to be drilled, in the desired direction by providing added side force to drill bit portion  808  plus cutting force B 1  from cutting pad  812   1  with cutter  814   1  to independently scrape or crush the wellbore sidewall (not specifically shown). Based upon the above teaching, one ordinarily skilled in the art could easily see that this could also extend to DLC systems with a plurality of asymmetrically mounted bearing and cutting pads and to DLC systems with an odd or even number of blades with or without a plurality of cutting pads and/or bearing pads. 
     In the exemplary embodiment of a five (5) bladed DLC system  800  described by the combination of  FIGS. 8A and 8B , first cam race  822  is provided to drive cutter pads  812  and second cam race  830  is provided to drive bearing pads  826 . In this embodiment and with appropriate profiles for cutting pad cam race  822  and bearing pad cam race  830 , as integral drill bit/drive shaft  802  rotates relative to cam sleeve  820 , bearing pad cam race  830  approaches and extends bearing pad  826   3  in advance of bearing pad  826   4  potentially introducing additional rock cutting actions. With cutting pad  812   1  also extended, the earlier extension of bearing pad  826   3  will cause bit portion  808  and cutter pad  812   1  to potentially tip and change the angle of attack of cutter  813   1 . As bit portion  808  continues rotation, bearing pad cam race  830  rotates under, and extends bearing pad  826   4  to bring the angle of attack of cutter  814   1  back to neutral. Similarly, with continued rotation, bearing pad  826   3  retracts before bearing pad  826   4  causing bit portion  808  and cutter pad  812   1  to potentially tip and change the angle of attack of cutter  814   1  in the reverse direction. Depending on the specific profiles of cutting pad cam race  822  and bearing pad cam race  830  similar tipping action could be created by the cutting pads. 
     Referencing  FIG. 8B , simultaneous extension of bearing pad  826   3  and bearing pad  826   4 , or any pair of pads, can be provided by introducing a second bearing pad cam race with identical profiles but out of phase, by ⅕ of a revolution (for a 5 bladed system). This would cause both bearing pads to extend and retract in unison. Based upon the above teaching, one ordinarily skilled in the art could easily see the possibility of additional cam races, additional cutter pads and additional bearing pads, limited only by the space, particularly length required to fit the components. In addition, one ordinarily skilled in the art could easily see that pad profiles can be manipulated to extend, retract, hold and oscillate in an almost limitless number of permutations and combinations while controlling both the amount of lift and timing. Further, the pads could also contain sensors that extend and retract. 
     Rocker arms (not shown) provide another alternative actuator allowing multiple actuators to operate simultaneously off a single reference, like a cam. In addition, a rocker arm actuator, hinged between an input of force and the output, reverses the direction of motion like a teeter-totter; a rocker arm actuator can be used to operate both a cutter pad and bearing pad from a single cam race. In another embodiment, a single cam could be used to drive a hydraulic pump, the output of which could be ported to any number of hydraulic actuators. 
     DLC system  800  ( FIG. 8A ) provides moveable lateral cutting structures opposite one or more moveable lateral pads providing enhanced cutting aggressiveness, primarily with side cutting action, to support the directional change capability in directional wells and in vertical wells where the objective is to stay close to vertical. DLC system  800  in vertical wells, associated or not with an optimized fixed cutting design, would be used to nudge the wellbore back to vertical when the wellbore has drifted off the planned vertical axis. As extension of the pad is controllable based on orientation, location, width of the actuator, profile of the cam race or the like acting on the pad, the extension of a pad can be used to enhance or negate/offset aggressiveness of angular deviation of a drill bit while initially drilling a wellbore or correct unwanted deviations for after the initial drilling of a wellbore section. In certain aspects, as described above, the pad may include a cutting element and, as a pad pushes against the wellbore, a cutter or series of cutters in an opposing pad or cutter assembly may destroy rock in the opposing section of the wellbore. 
     Previously, all pad hole extension paths for DLP systems ( 200 ,  400 ,  500 ) and DLP/DLC system  800  were oriented perpendicular to the axis of rotation and all pad faces were oriented parallel to the axis of rotation. In certain applications, changes to the pad hole extension axis and changes to pad face orientation can improve system overall performance. Using DLP system  500  as exemplary,  FIG. 9  shows enlarged views of a base pad mechanism  900 , consistent with pad hole extension path Pi perpendicular to axis of rotation A and pad face  518   1  orientation parallel to axis of rotation A as presented in each of the exemplary embodiments presented above. Also shown in  FIG. 9  is a second exemplary pad mechanism  920  that adds to base pad mechanism  920 , pad face  518   2  that is closer to parallel with well bore  552 .  FIG. 9  also includes a third exemplary pad mechanism  940  that reorients hole pad extension axis P 3  to provide pad face  518   3  that is closer to parallel with well bore  552 . A fourth exemplary pad mechanism  960  significantly reorients hole pad extension axis P 4  while providing pad face  518   4  close to parallel with well bore  552  with possible modifications to better grip well bore  552  described later. 
     Referring to  FIG. 9 , base pad mechanism  900  includes pad  516   1  that is constrained by pad hole  514   1  to limit motion to the radial direction. Pad hole  514   1  is contained in axial outer wall  512 , part of drill bit  506 . Pad  516   1  translates along pad hole axis P 1  that extends radially, perpendicular to axis of rotation A of drill bit  506 . Pad  516   1  extends and retracts as cam sleeve  520  rotates under pad cam face  519   1  that is parallel to the curvature of pad well bore face  518   1 . As previously discussed, when DLP system  500  includes a bend (not shown), axis of rotation A of drill bit  506  is offset from the drill string axis and therefore well bore  552  by a magnitude close to the magnitude of the bend angle. When loaded during the directional drilling process, the tilt of drill bit rotation axis A typically increases and may more than double the unloaded tilt depending on such things as the well bore geometry, load applied and the geometry of the associated drilling equipment. Assuming the tilt of rotation axis A is doubled relative to the bend angle, results in a misalignment angle ϕ 1  between pad well bore face  518   1  and well bore  552  that is twice the bend angle. Misalignment between pad well bore face  518   1  and well bore  552  can add wear to pad  516   1  and cause rock destruction at the contact point, directly opposite the target direction. The item numbers included but not cited are provided as reference to tie back to DLP system  500  ( FIG. 5A ). 
     Again referencing  FIG. 9 , second pad mechanism  920  is virtually identical to base pad mechanism  900  with the exception that pad well bore face  518   2  of pad  516   2  is profiled to be more generally parallel to well bore  552  under load. Using the previous example of a bend in the assembly and the assumption that, under load, the tilt of rotation axis A is doubled relative to the bend angle; leads to profiling the angle of pad well bore face  518   2  by twice the angle of the bend. 
     Continuing to reference  FIG. 9 , third pad mechanism  940  creates pad well bore face  518   3  of pad  516   3  that is generally parallel to well bore  552  by rotating pad hole axis P 3  from perpendicular as shown by angle θ 3 . Assuming again a bend in the assembly and, when under load, the tilt of rotation axis A is doubled relative to the bend angle; leads to rotating pad hole axis P 3  from perpendicular by twice the angle of the bend. While addressing possible wear to pad  516   3  and unintended rock destruction directly opposite of the target direction, this mechanism reduces force delivered to pad  516   3  by the sine of the angle of pad hole axis P 3  rotation unless the profile of the cam pad face  519   3  is at least partially conical to be parallel to pad well bore face  518   3  and the cam sleeve  520  profile matches the profile of cam pad face  519   3 . 
     Fourth pad mechanism  960  contains all the parts of the three preceding mechanisms but adds a new dimension to pad action. By further rotating pad hole axis P 4  from perpendicular as shown by angle θ 4 , that is greater than the tilt of rotation axis A under load, pad  516   4  can be used to simultaneously push the bit sideways and momentarily push drill bit  506  along the axis of rotation A. To achieve optimal results in some applications, for example in hard competent formations, improvements could be provided in the pad well bore face  518   4  to reduce pad  516   4  slippage relative to formation  550 . There are many ways to decrease the probability that pad  516   4  will slip relative to formation  550  including adding a rubber pad to pad well bore face  518   4 , under or over rotating pad hole axis P 4  in relation to pad well bore face  518   4  to promote a geometry that tends to gouge formation  550  (the reverse objective of second pad mechanism  920  and third pad mechanism  940 ) and introducing hardened steel, carbide, PDC or like teeth to pad well bore face  518   4 . Although, all pads might visually appear as “not sealed” and as having sharp edges, this should not be considered to be in any way limiting. Each alternative such as sealing, or not, and edge details such as sharp, tapered, chamfered, well rounded and half dome bring potential advantages and disadvantages to be considered relative to the specific implementations and drilling objectives. 
       FIG. 13  provides a section view of drill string  1300  with Dynamic Lateral Pad (DLP) inclusive of conventional bit  14  at distal end  1352 . In this exemplary embodiment, drill string  1300  includes the components described by drill string  12  ( FIG. 1 ) as positioned above bearing package  24  with the possible exception of bend  35  that may or may not be included depending on the desired aggressiveness of the drilling objectives. Returning to  FIG. 13 , drill string  1300  also includes bearing housing  1322  connected to the distal end of transmission housing  36  ( FIG. 1 ) and drive shaft  1302  inclusive of bit box  1304  and cam race  1303  connected to the distal end of transmission drive line  38  ( FIG. 1 ). Drill bit  14  is connected to bit box portion  1304  of drive shaft  1302  by API connection  37 . Drill string  1300  further includes pad carrier  1320  with raised section  1326 , slot  1321 , mounting provisions  1329  for pad hinge pin  1318 , and torsion lock pin  1323  to engage axial slot  1325  cut into bearing housing  1322  to prevent rotation of pad carrier  1320  relative to bearing housing  1322 . Pad carrier  1320  is fixedly mounted to bearing housing  1322  with retainer  1324  and torsion lock pin  1323 . Pad assembly  1314  is comprised of pad  1316 , cam follower  1315  and elastic element  1327 . Pad  1316  includes hinge portion  1317 , and mounting provisions  1328  to operationally attach hinge pin  1318 . Pad assembly  1314  is operationally positioned in slot  1321  with a hinged connection to pad carrier  1320  and contacting cam race  1303  with cam follower  1315  of pad assembly  1316 . 
     While similar to DLP system  700  ( FIG. 7 ), drill string  1300  with Dynamic Lateral Pad ( FIG. 13 ) incorporates conventional drill bit  14 , with hinged reciprocating pad assembly  1314  and adds compliance  1327  in pad assembly  1314  drive mechanism. As one of ordinary skill in the art would appreciate on reading this application, DLP system  1300  could also be implemented with integral drill bit/drive shaft as described throughout the application. 
     Drill string  1300  with Dynamic Lateral Pad includes radial cam race  1303  that encircles the outer perimeter of bit box portion  1304  of drive shaft  1302 . During steering of the drill string, drill bit  14  and drive shaft  1302  including cam race  1303  rotate relative to the generally non-rotating (during steering of the drill bit) pad assembly  1314 , pad carrier  1320 , retainer  1324 , housing  1322  and the remaining drill string components (not shown) terminating at the proximal end generally at or near the surface of the earth. The radial thickness of radial cam race  1303  alternates between one or more minimum and maximum thicknesses and the profile of cam race  1303  may include one or more cam race profile features including all of the types presented elsewhere in this application. As previously discussed, at maximum cam race  1303  radial thickness, pad assembly  1314  is fully extended to push against the wellbore wall of formation  1350  to steer the bit in the desired direction. However, in this embodiment an elastic element  1327  such as a rubber pad, Belleville washers or machine springs is located between cam follower  1315  and pad  1316  to provide compliance in the actuator, to limit pad assembly  1314  force and allow pad assembly  1314  to temporarily collapse to prevent potential interference between drill string  1300  with Dynamic Lateral Pad and formation  1350 . 
     View  1391  is a section view of pad assembly  1314  interacting with formation  1350  at three positions. Position  1  illustrates a fully retracted pad assembly  1314  with cam race  1303  at a minimum and presenting pad  1316  to be flush or possibly slightly inset with respect to the outer diameter of raised section  1326  of pad carrier  1320 . In position  1 , force A L  and added resultant force B L  are zero and axis of rotation CL 1  is in a neutral position generally near the center of borehole CL B  and not affected by pad extension. Position  2  illustrates extended pad assembly  1314  with the radial thickness of cam race  1303  approaching or at a maximum. Pad  1316  of pad assembly  1314  is pressing against formation  1350  but elastic element  1327  has not been compressed beyond the pre-load force of elastic element  1327 . In position  2 , force A L  is a function of such things as drill string mechanics, hole angle and bit characteristics but, in position  2  elastic element  1327  was defined to be not compressed beyond the pre-load force, therefore the magnitude of force A L  and added resultant force B L  are limited to the magnitude of the preload on elastic element  1327 . In position  2 , axis of rotation CL 2  is offset from neutral position CL B  in the target direction by the length of pad assembly  1314  extension due to the increased radial thickness of cam race  1303 . Position  3  illustrates extended pad assembly  1314  with cam race  1303  at a maximum thickness with pad assembly  1314  fully collapsed and sharing the lateral load with raised section  1326  of pad carrier  1320 . In position  3 , the magnitude of force A L  is equal to the force required to fully collapse pad assembly  1314  but is largely irrelevant as the drilling actions and conditions, largely irrespective of pad assembly  1314  force A L , are controlling the forces on the bit including added force B L . Additionally, axis of rotation CL 3  has returned to near “neutral” position CL B  just offset by clearance distance D′ that is equal to distance D, the distance between raised section  1326  and wall of formation  1350  at position  1 . 
     View  1390  is an isometric view of the distal end of drill string  1300  with Dynamic Lateral Pad. This view shows pad  1316  with hinge pin  1318  oriented parallel to drill string  1300  axis of rotation CL. Hinge pin  1318  is supported by mounting provisions  1329  as are well known in the art. Hinge pin  1318  mounting provisions  1329  are located as shown in raised section  1326  of pad carrier  1320 . Hinge pin  1318  is also connected using well-known mounting provisions  1328  as part of pad  1316 . In operation, pad  1316  pivots on hinge pin  1318  allowing controlled radial movement of pad assembly  1314  as cam race  1303  rotates under and then away from cam follower  1315 . 
       FIG. 14  provides a section view of drill string  1400  with Dynamic Lateral Pad (DLP) with a magnetic actuator and conventional bit  14  at distal end  1452 . Similar to drill string  1300  described above, drill string  1400  includes the components described by drill string  12  ( FIG. 1 ) positioned above bearing package  24  with the possible exception of bend  35  that may or may not be included depending on the desired aggressiveness of the drilling objectives. Returning to  FIG. 14 , drill string  1400  also includes bearing housing  1322  connected to the distal end of transmission housing  36  ( FIG. 1 ) and drive shaft  1402 , inclusive of bit box  1404  and magnets  1412  and  1414 , connected to the distal end of transmission drive line  38  ( FIG. 1 ). Drill bit  14  is connected to bit box portion  1404  of drive shaft  1402  by API connection  37 . Drill string  1400  further includes pad carrier  1420  with slot  1421 . Operationally positioned in slot  1421  is pad  1416  including magnet  1413  and containing hinge portion  1418  with fixed mounting provision  1419  fixedly connecting pad hinge portion  1418  to pad carrier  1420 . Pad carrier  1420  is fixedly mounted to bearing housing  1322  with retainer  1324  and torsion lock pin  1323  engaging axial slot  1325  cut into bearing housing  1322 . 
     While sharing many components with DLP drill string  1300  ( FIG. 13 ), and providing similar pad extension and retraction as DLP drill string  1300 , drill string  1400  with Dynamic Lateral Pad utilizes fixed mounting provision  1419 , which may be a weld, adhesive, chemical bonding, or the like to fixedly connect cantilevered spring hinge portion  1418  of pad  1416  to pad carrier  1420  and utilizes a magnetic drive mechanism to provide locomotion for reciprocating pad  1416 . The magnetic drive, described below, provides a non-contacting and compliant drive mechanism. As one of ordinary skill in the art would appreciate on reading this disclosure, the DLP system  1400  could also be implemented with integral drill bit/drive shaft as described throughout the application. 
     Drill string  1400  with Dynamic Lateral Pad includes a magnetic actuator to extend pad  1416 . Pad magnet  1413  is fixedly attached to pad  1416  with north magnetic field N P  of pad magnet  1413  orthogonal to and oriented away from axis of rotation CL. Extend magnet  1412  is fixedly attached to bit box portion  1404  of drive shaft  1402  with north magnetic field N E  of extend magnets  1412  orthogonal to but oriented in the direction of axis of rotation CL. As drill bit  14  and drive shaft  1402  including bit box portion  1404  and extend magnet  1412  rotate relative to the generally stationary (while directional drilling) pad carrier  1420 , pad  1416  including pad magnet  1413 , retainer  1324  and bearing housing  1322 ; extend magnet  1412  rotates under pad  1416  and pad magnet  1413 . Because the polarity of pad magnetic field NP is opposed to the polarity of extend magnetic field N E , as proximity and alignment of pad magnet  1413  and extend magnet  1412  increase, pad  1416  is forced outwardly with force A to push against the formation creating an opposing force B in drill bit  14  to steer the bit in the desired direction. As extend magnet  1412  rotates away from pad magnet  1413 , alignment and proximity decrease and the magnetic force decreases. As one of ordinary skill in the art will now recognize on reading the disclosure, additional extend magnets  1412  positioned on the perimeter of the bit box portion, or magnets with a longer arc length could be used to apply force to extend the pad for a longer portion of the revolution. Conversely, a magnet or magnets with a shorter arc length could be used to apply force to extend the pad for a lesser portion of drill bit  14  revolution. Once extend magnet  1412  sufficiently clears pad magnet  1413 , either cantilevered spring hinge portion  1418  or the formation (not shown) or both act to retract pad  1416  to the withdrawn position. Compliance is provided by mechanical fit as, by design, clearance is always provided between extend magnet  1412  and pad magnet  1413 , even if pad  1416  and pad magnet  1413  do not move as extend magnet  1412  rotates under pad  1416  and pad magnet  1413 . Maintaining clearance, regardless of the orientation of extend magnet  1412  and pad magnet  1416  prevents the creation of an interference condition between drill string  1400  with Dynamic Lateral Pad and the formation (not shown). Magnets materials for these embodiments include but are not limited to iron, ferromagnets, rare earth magnets such as samarium-cobalt and neodymium-iron-boron (NIB) and electromagnets. Magnets are attached using one or more means such as a chemical adhesive, mechanical fastener or interference fit 
     In addition to cantilevered spring hinge portion  1418  or the formation (not shown) or a combination of both acting to retract pad  1416  to the withdrawn position, a third method to retract pad  1416  is possible by use of one or more retract magnets  1414  also mounted on the perimeter of bit box portion  1404  of drive shaft  1402  with north magnetic fields NR orthogonal to and oriented away from the direction of axis of rotation CL (the opposite orientation as extend magnet  1412 ). As drill bit  14  and drive shaft  1402  including bit box portion  1404  and retract magnets  1414  rotate relative to the generally stationary (while directional drilling) pad carrier  1420 , pad  1416  with pad magnet  1413 , retainer  1324  and bearing housing  1322 ; retract magnets  1414  rotate under pad  1416  and pad magnet  1413 . Because the polarity of pad magnetic field N P  is congruent with the polarity of retract magnetic field N R , as proximity and alignment of pad magnet  1413  to retract magnets  1414  increase, pad  1416  is attracted inwardly towards the retract magnets. Conversely, as retract magnet  1414  rotates away from pad magnet  1413 , alignment and proximity decrease and the magnetic force decreases. 
       FIG. 14  provides a section view of drill string  1400  with Dynamic Lateral Pad (DLP) with extend magnet  1412  rotationally positioned such that pad magnet  1413  of pad  1416  and extend magnet  1412  are face to face providing magnetic force to extend pad  1416 . View  1491  provides a section view of the actuator section of drill string  1400  with Dynamic Lateral Pad rotated 180 degrees and therefore rotationally positioned such that pad magnet  1413  of pad  1416  faces retract magnet  1414  retracting pad  1416 . View  1492  is a cross-sectional cut through the center of pad magnet  1416  providing an exemplary magnet configuration providing about 45 degrees of extension and 300 degrees of retraction. View  1490  is an isometric view of the distal end of drill string  1400  with Dynamic Lateral Pad further showing carrier slot  1421  and pad hinge portion  1418  with fixed mounting provision  1419  such as, but not limited to a weld or brazed joint fixedly connecting pad hinge portion  1418  and pad carrier  1420 . Alternatively, the pad and the carrier could also be manufactured as a single piece using for example steel tubing, steel bar or a metal casting. 
       FIG. 15  shows a section view of drill string  1500  with DLP and an axial hinged pad. Drill string  1500  is essentially identical to drill string  1300  ( FIG. 13  above) with a few notable exceptions. One exception is drill string  1500  provides a pad  1516  mounted on pad carrier  1520  that is mounted parallel to axis of rotation CL as opposed to the embodiment provided in drill string  1300  where pad  1316  is mounted about the outer circumference of pad carrier  1320 . Between the circumferential pad mounting provided in in drill string  1300  and the axial pad mounting provided in drill string  1500 , one of ordinary skill in the art will now recognize, on reading the disclosure that, the orientation of a hinged reciprocating pad is not constrained to a single orientation. In addition to a circumferential orientation provided in drill string  1300  and axial orientation provided in drill string  1500  above, one of ordinary skill in the art will now recognize that a hinged pad can be implemented at virtually any angle about a physical or virtual cylinder, such as the pad carrier. Examples include a pad such as pad  1516  on drill string  1500  rotated, with carrier slot  1521 , 180 degrees along axis of rotation CL resulting in pad hinge  1518  mounted closer to distal end  1552  of drill string  1500 . Similarly, while never intended to be limiting, pad  1316  of drill string  1300  is shown with hinge pin  1318  leading rotation but hinge pin  1318  and the requisite mounting provisions could be flipped 180 degrees on the horizontal with hinge pin  1318  trailing rotation. Further, the pad could be rotated at virtually any angle off horizontal or off axis of rotation CL and could have a plurality of hinges. Alternative orientations for hinge mounting allow for the potential to improve operational mechanics specific to a given drilling environment. Examples include; more abrupt or less abrupt pad extension and retraction, larger pad area in the generally cylinder volume, longer hinge portions within a given space allowing for more complex extension and retraction mechanism such as providing a fulcrum, adding compliance, and creating an alternative pad extension vector that is more effective at rock removal than just the added side load previously explained. 
     Another exception of drill string  1500  as compared to is drill string  1300  is drill string  1500  includes hinge portion  1518  of pad  1516  fixedly attached to carrier  1520 , in this case weld  1519 , as previously presented as part of drill string  1400 . Another possible exception of drill string  1500  as compared to drill string  1300  is use of a non-descript cam follower  1515  that could be compliant or not. Also, the actuator could be of a type consistent with the magnet system presented as part of drill string  1400 , other actuators presented earlier or following in this application and actuator alternatives that one of ordinary skill in the art will now recognize on reading the disclosure.  FIG. 15  also includes view  1590 , an isometric view of the distal end of drill string  1500  with Dynamic Lateral Pad identifying carrier slot  1521 . 
       FIG. 16A  provides a section view of drill string  1600  with drill bit mounted Dynamic Lateral Pad (DLP). In this exemplary embodiment, drill string  1600  includes the components described by drill string  12  positioned above bearing package  24  with the possible exception of bend  35  ( FIG. 1 ) that may or may not be included depending on the desired aggressiveness of the drilling objectives. Returning to  FIG. 16A , drill string  1600  also includes bearing housing  1322  connected to the distal end of transmission housing  36  ( FIG. 1 ) and drive shaft  1602  inclusive of bit box  1604  connected to the distal end of transmission drive line  38  ( FIG. 1 ). Drill bit  1606  is connected to bit box portion  1604  of drive shaft  1602  by API connection  37 . Drill string  1600  further includes cam sleeve  1620  and torsion lock pin  1323  to engage axial slot  1325  cut into bearing housing  1322  and cam sleeve  1620  that is fixedly mounted to bearing housing  1322  with retainer  1324  and torsion lock pin  1323  to prevent relative rotation between cam sleeve  1620  and bearing housing  1322 . The distal end of cam sleeve  1620  terminates with an external cam profile  1603  on the outer surface of cam sleeve  1620 . In addition to multiple drill bit cutters  1612  shown as PDC type and more thoroughly described above, drill bit  1606  includes hinge pin  1618 , a possible supplemental pad  1616  retraction apparatus (not shown) and pad  1616  with cam follower portion  1617 . Pad  1616  swings on hinge pin  1618  and is operationally coupled to external cam race  1603  of cam sleeve  1620  at cam follower portion  1617 . Although not shown in  FIG. 16A , exemplary supplemental pad retraction apparatus include, but are not limited to, springs, magnets and scavenging hydraulics from mudflow. An example supplemental pad retraction apparatus is shown as spring  1725  in  FIG. 17 . Similar to previous discussions, cam race  1603  varies in radial thickness about the perimeter of cam sleeve  1603  causing pad  1616  to extend and retract by rotating in and out on hinge pin  1618 . Consistent with previous cam race descriptions, it is possible to have multiple undulations and multiple cam races with differing radial thicknesses and slopes. 
     Very similar to DLP string  600 , cam sleeve  1620  of drill string  1600  is fixedly attached to bearing housing  1322  but the cam sleeve and bearing housing could also be made to be integral or as one piece. As in previous embodiments, bearing housing  1322  is fixedly connected to the drill string components above (not shown) and are oriented as required to cause bit  1606  to advance drill string  1600  in the desired direction when drill bit  1612  is rotated and weight is applied. Cam sleeve  1620 , bearing housing  1322  and the drill string above (not shown) are generally not rotating during directional drilling. As previously discussed, to advance drill string, mud (not shown) is pumped from the surface through drill string  1600  to cause rotor  30  ( FIG. 1 ) to rotate drive shaft  1602  and drill bit  1606  relative to cam sleeve  1620  and bearing housing  1322 . As drill bit  1606  rotates, pad  1616  pivots on hinge pin  1618  due to cam follower portion  1617  of pad  1606  reacting to the changing radial thickness of cam race  1603 . As the thickness of cam race  1603  increases, pad  1606  rotates outward towards the formation wall (not shown) in the direction of arrow A. Upon contact to the formation wall (not shown) the outward rotation of pad  1616  pushes bit  1606  in the opposite direction as shown by arrow B. The added force results in additional formation removal in the direction of arrow B. Drill string  1600  in  FIG. 16A  illustrates pad  1616   E  outwardly rotated on pin  1618  in an extended position with cam follower portion  1617  of pad  1606  positioned at cam race  1603   E  oriented to a maximum thickness. Conversely, view  1691  illustrates cam race  1603   R  at a minimum thickness with pad  1616   R  and rotated to the retracted position. In this example, pad  1616  contact with the formation wall (not shown) causes retraction of pad  1616  as the bit rotates away from a maximum thickness of cam race  1603 . View  1690  is an isometric view of the distal end of drill string  1600 . 
       FIG. 16B  shows drill string  1692  as identical to drill string  1600  ( FIG. 16A ) except drill string  1692  includes pad cutters  1614  on pad  1616   c  (shown as  1616   CE  and  1616   CR ). Operationally, drill string  1692  and drill string  1600  are identical as extended pad  1616   CE , upon contact with the formation wall (not shown), the outward rotation of pad  1616  as shown by arrow A pushes bit  1606  in the opposite direction causing added formation removal in the direction of arrow B. However, when pad  1616   C  is in the extended position, cutters  1614  on pad  1616   C  of drill string  1692  also cause added formation removal in the direction of arrow A. Drill string  1692  in  FIG. 16B  illustrates pad  1616   CE  rotated and extended with cam follower portion  1617  of pad  1606  positioned at cam race  1603   E  that is oriented at a maximum thickness. Conversely, view  1694  illustrates cam race  1603   R  at a minimum thickness with pad  1616   CR  rotated to the retracted position. View  1693  is an isometric view of the distal end of drill string  1692 . While drill string  1600  shows bit mounted hinged pad  1616  to be axially mounted, one of ordinary skill in the art will now recognize on reading the disclosure that a bit mounted hinged pad could be formed as a partial helix (pure or a segmented approximation) and hinged at an angle provided the retracted pad does not radially extend beyond a cylinder formed by bit gauge  210  ( FIG. 2 ) and the helix does not wrap than about 45 degrees about the perimeter of the cylinder also formed by bit gauge  210 . 
       FIG. 17  provides a section view of drill string  1700  with a moveable blade in the drill bit. In this exemplary embodiment, drill string  1700  includes the components described by drill string  12  positioned above bearing package  24  with the possible exception of bend  35  ( FIG. 1 ) that may or may not be included depending on the desired aggressiveness of the drilling objectives. Returning to  FIG. 17 , drill string  1700  also includes bearing housing  1322  connected to the distal end of transmission housing  36  ( FIG. 1 ) and drive shaft  1702  inclusive of bit box  1704  connected to the distal end of transmission drive line  38  ( FIG. 1 ). Drill bit  1706  is connected to bit box portion  1704  of drive shaft  1702  by API connection  37 . Drill string  1700  further includes cam sleeve  1720  and torsion lock pin  1323  to engage axial slot  1325  cut into bearing housing  1322  that is fixedly mounted to bearing housing  1322  with retainer  1324  and torsion lock pin  1323 . The distal end of cam sleeve  1720  terminates with an internal cam profile  1703  on the inner surface of cam sleeve  1720 . In addition to multiple fixed blades  1728  with cutters shown as PDC type and more thoroughly described above, drill bit  1706  also includes a moveable bit blade  1716  with cam follower portion  1717 , hinge pin  1718 , and may include a supplemental retraction apparatus  1725 . Moveable blade  1716  pivots on hinge pin  1718  and is operationally coupled to internal cam race  1703  of cam sleeve  1720 . Similar to previous discussions, cam race  1703  varies in thickness about the perimeter of cam sleeve  1720  causing moveable bit blade  1716  to extend and retract by rotating in and out on hinge pin  1718 . Consistent with previous cam race descriptions, it is possible to have multiple undulations and multiple cam races with differing thickness and slopes. While in this exemplary embodiment supplemental pad retraction apparatus  1725  is shown as a single coiled spring, the supplemental pad retraction apparatus could include a plurality of devices including different spring types, magnets, scavenged hydraulics from mud flow or U shaped cam follower, the later to mechanically extend and retract blade  1716 . 
     Similar to drill string  1600  ( FIG. 16A ), cam sleeve  1720  of drill string  1700  is fixedly attached to bearing housing  1322 , or could be manufactured as a single piece, and the drill string components above (not shown) are oriented as required to cause bit  1706  to advance drill string  1700  in the desired direction when drill bit  1706  is rotated and weight is applied. Cam sleeve  1720 , bearing housing  1322  and the remaining drill string components mounted above (not shown) are generally not rotating during directional drilling. As previously discussed, to advance drill string, drilling mud (not shown) is pumped from the surface through drill string  1700  to cause rotor  30  ( FIG. 1 ) to rotate drive shaft  1702  and drill bit  1706  relative to cam sleeve  1720 . As drill bit  1706  rotates, moveable bit blade  1716  pivots on horizontal hinge pin  1718  due to cam follower portion  1717  of moveable bit blade  1706  reacting to the changing thickness of cam race  1703 . As the thickness of cam race  1703  increases moveable bit blade  1716  above hinge pin  1718  rotates inward, away from the formation wall (not shown) in the direction of arrow D IN  compressing coil spring  1725 . With hinge pin  1718  acting as a fulcrum, the lower portion of moveable bit blade  1716  moves outwardly towards the formation (not shown) by the relationship: travel distance out D OUT −travel distance in D IN *L 2 /L 1  where L 1  is the distance from the center line of hinge pin  1718  to the contact point between cam race  1703  and cam follower portion  1717  and L 2  is the distance from the center line of hinge pin  1718  to the cutter of interest. Outward motion D OUT  increases the rate of formation removal in the direction of arrow D OUT  for the portion of bit rotation where moveable bit blade  1716  is extended. As drill bit  1706  continues to rotate, cam race  1703  moves away from maximum radial thickness allowing moveable bit blade  1716  above hinge pin  1718  to rotate outwardly driven by contact with the formation (not shown), spring  1725  or both. By now, one of ordinary skill in the art will now recognize on reading the disclosure that more than one moveable blades  1716  could be implemented in a given drill bit, there could be multiple types of actuators such as those detailed above and moveable bit blade  1716  could be implemented, similar to moveable pad  1616 , at an angle as a pure or segmented helix within the limits detailed for drill string  1600 . In addition, also presented above, an integral bit/drive shaft could replace the conventional bit and drive shaft with all the incumbent advantages described earlier. 
     Drill string  1700  in  FIG. 17  illustrates moveable bit blade  1716   E  rotated to extend cutters  1714  out into the formation (not shown) with cam follower portion  1717  of pad  1706  located at a maximum thickness of cam race  1703   E . View  1790  is an isometric view of the distal end of drill string  1700 . 
       FIG. 18  provides a section view of the distal end of drill string  1800 , an isometric view  1890  of the distal end of drill string  1800 , end view  1891  and cross-section view  1892  cutting through eccentric mud motor bearing housing  1822  at pocket portion  1824  and cover  1848 . In this exemplary embodiment, drill string  1800  includes all the components described by drill string  12  positioned above bearing package  24  with the possible exception of bend  35  ( FIG. 1 ) that may or may not be included depending on the desired aggressiveness of the drilling objectives. Returning to  FIG. 18 , drill string  1800  also includes an eccentric bearing housing  1822  with pocket portions  1824 , axial bearings  1840 , lateral bearings  1842 , electronics  1826 , and cover  1848  fixedly connected to the distal end of transmission housing  36  ( FIG. 1 ). In addition, drill string  1800  includes integral drill bit/drive shaft  1802  with drive shaft portion  1803  and drill bit portion  1801  fixedly connected to the distal end of transmission drive line  38  ( FIG. 1 ) and rotatably coupled with eccentric bearing housing  1822  with bearings  1840  and bearings  1842 . Bearing housing  1822  is machined eccentrically, cast, forged or otherwise formed so that one side provides substantially more wall thickness but does not exceed the well bore diameter (not shown). The additional thickness created by this innovation may run the full axial length of the bearing housing or any portion there-of and extend circumferentially from 10 to 160 degrees. The additional thickness may also be used to house an extendable pad, which could directionally drive the drilling assembly towards a target, as well as sensors or electronics to measure drilling parameters, batteries to power electronics, chemical sources or any combination of the afore mentioned. 
     Use of pockets containing electronics, sensors, chemical sources and batteries in an eccentric housing above the bearing housing is relatively common but this improvement provides for pockets  1824  containing electronics  1826  and other components, in (eccentric) bearing housing  1822 . This is an improvement over the current art as it allows placement of electronics, sensors, batteries, chemical sources, extendable pads and other such components within around 8 to 18 inches, possibly closer, to the terminal cutting structures of drill bit portion  1801  of integral drill bit/drive shaft  1802 . In addition to positioning components closer to the cutting structure, the components are located in a section of drill string  1800  that does not rotate with bit  1801  making for better connectivity as compared to current art that limits placement of sensors and electronics to locations above the motor bearings, above the entire motor or in locations connected to and rotating with the drill bit. With electronics or other components not rotating with the bit, connectivity to other electronics, sensor and power sources is in the drill string is greatly simplified compared to the current art that generally requires sensors and electronics positioned close to and rotating with the drill bit to provide their own power and communications through or around the motor. In situ power requires the assembly to lengthen and electronic communications through or around the motor is generally complex, expensive (cost and power) and often comes with significant communications bandwidth limitations. Utilizing a conventional drill bit and drive shaft in lieu of the integrated drill bit/drive shaft  1802  with an eccentric mud motor bearing housing  1822 , as frequently discussed above, would also be a significant improvement but comes with some length penalty, perhaps doubling the distance to the bit cutting structure as detailed in  FIGS. 3A and 3B . 
     As described herein, the numerous DLP systems and DLC systems provide pads or cutters on the drill bit associated with the drill string. Locating the DLP or DLC on the drill bit in certain embodiments provides the structures as close to the cutting structures on the drill bit as possible, which provides certain advantages, some of which are explained herein. Drilling strings may be provided consistent with the technology described herein with DLP systems and DLC systems mounted removed from the drill bit but placed on the housing of the drill string below the power section  20  (see  FIG. 1 ). For example, in certain embodiments, a DLP system may be provided on the drill bit and a complementary DLP system may be provided on the transmission housing  36  (see  FIG. 1 ). Similarly, a DLP system may be provided on the bearing housing  42  (see  FIG. 1 ) and a DLC system may be provided on the transmission housing  36  (see  FIG. 1 ). Thus, depending on the drilling conditions and rock formation, the DLPs and DLCs described herein may be located on the drill bit, the drill string housing below the power section, or a combination thereof. 
       FIG. 10B  provides a side view  1000  of the distal end of an exemplary Dual Rotating Cutting Structure (DRCS) drilling system.  FIG. 10C  provides cross-sectional view  1092  of the exemplary Dual Rotating Cutting Structure (DRCS) drilling system provided in  FIG. 10B . Dual rotating cutting structure systems may be referred to as the DRCS system or dual rotating cutting structure herein.  FIG. 10A  provides partial section views of two exemplary embodiments of drill strings including a dual rotating cutting structure. One embodiment is a DRCS drill string with no bend (DRCS no bend )  1090  and the second is a DRCS drill string with a bend (DRCS w-bend )  1091 . Both drill strings include power section  1002 , transmission section  1004 , bearing section  1006  with outer cutting structure portion  1030 , and integral drill bit/drive shaft  1028  (reference  FIG. 10C ) with inner cutting structure portion  1020 . While presented with integral drill bit/drive shafts, both drill strings could utilize a conventional bit and drive shaft. DRCS drill string with a bend (DRCS w-bend )  1091  also includes bend  1008 , generally at or near the junction of transmission housing  1014  and bearing housing  1016 . 
     Referencing  FIG. 10A  unless otherwise noted, DRCS drill string with no bend (DRCS no bend )  1090  and DRCS drill string with a bend (DRVS w-bend )  1091  both comprise power section  1002  including motor stator housing  1012  and motor rotor  1010  that rotates inside motor stator housing  1012  when mud flows from the surface. Motor housing  1012  is rigidly coupled to the drill string above (not shown) that extends to the surface. Transmission section  1004  includes transmission housing  1014  and transmission driveline  1018  that rotates inside of transmission housing  1014 . The distal end of motor housing  1012  is rigidly coupled to transmission housing  1014  with transmission driveline  1018  rigidly connected to the distal end of motor rotor  1010 . Bearing section  1006  includes bearing housing  1016  with outer cutting structure portion  1030 , a bearing assembly (not shown), drive shaft cap  1047  (partially shown) and integral drill bit/drive shaft  1020  (reference  FIG. 10C ). Bearing housing  1016  is rigidly connected to the distal end of transmission housing  1014 . Integral drill bit/drive shaft  1020  is rotatably coupled to bearing housing  1016  through the bearing assembly (not shown) and is rigidly connected to the distal end of transmission driveline  1018  through drive shaft cap  1047 . Outer cutting structure portion  1030  of bearing housing  1016  is essentially hollow (reference  FIG. 10C ) to allow integral drill bit/drive shaft  1028 , potentially including inner cutting structure portion  1020 , to rotate within and with respect to the outer cutting structure portion  1030 . As explained above, the drill string located the power section  1002  is rigidly coupled to outer cutting structure portion  1030  of bearing housing  1016  through motor stator housing  1012  and transmission housing  1014 , and it should now be clear outer cutting structure  1030  rotates with the drill string. 
     Again referencing  FIG. 10A  and starting at power section  1002 ; motor rotor  1010  (absent rotor catch  18  shown in  FIG. 1 ) is essentially not connected at proximal end  1048  but the distal end of the rotor is rigidly coupled to transmission driveline  1018 . The distal end of transmission driveline  1018  is rigidly coupled to integral drill bit/drive shaft (reference  FIG. 10C ) that includes inner cutting structure  1020  terminating at distal end  1046  of drill strings  1090  and  1091 . 
     With reference to  FIG. 10B , an expanded side view of dual rotating cutting structure system  1000  used with DRCS drill string with no bend (DRCS no bend )  1090  and DRCS drill string with a bend (DRCS w-bend )  1091  is provided showing inner cutting structure  1020  including blades  1021  containing cutters  1022 , interrupted gauge pad  1024  and junk slots  1026  rotating inside of the outer cutting structure as shown by arrows R I . Also shown in  FIG. 10B , is outer cutting structure  1030  including blades  1031  containing cutters  1032 , interrupted gauge pad  1034 , junk slots  1036  and interrupted follow guide  1038  that rigidly connects to bearing housing  1016  (and the drill string above) rotating with the drill string above as shown by arrow R O    
     As will be explained further below, dual rotating cutting structure system  1000  may be useable as a straight hole drilling assembly or as part of a directional drilling assembly. By way of background, a cutting structure of a drill bit generally creates the wellbore size desired as the wellbore extends into the formation, which may comprise rock and other mineral layers. The DRCS system provides at least two, essentially independent, cutting structures/cutter sets that operate concurrently to create one wellbore. The two cutting structures generally operate at differing rotation rates to most effectively drill the wellbore. Generally, DRCS  1000  system includes an inner cutting structure  1020  and an outer cutting structure  1030 . In certain embodiments, for example, inner cutting structure  1020  will rotate at a higher rate of rotation than outer cutting structure  1030 . In other embodiments, for example by reversing the pitch angle of rotor  1010  and motor housing/stator  1012 , inner cutting structure  1020  will rotate at a lower rotation rate than outer cutting structure  1030 . In a further embodiment inner cutting structure  1020  and outer cutting structure  1030  can rotate in opposite directions for example by again reversing the pitch angle on rotor  1010  and motor housing/stator  1012  and operating mud motor  1002  at a rotation rate greater than the rotation rate of the drill string. In a further embodiment, inner cutting structure  1020  and outer cutting structure  1030  can be made to rotate at essentially the same rotation rate for example by rotationally locking the two cutting structures while bypassing flow around the rotor or not. 
     One unique feature of the technology of the present application with respect to DRCS system  1000  is the inner cutting structure  1020  and the outer cutting structure  1030  may include multiple types of cutters. As described above, cutting structures may take many forms, such as, for example, polycrystalline diamond cutters (PDC), roller cones (RC), impregnated cutters, natural diamond cutters (NDC), thermally stable polycrystalline cutters (TSP), carbide blades/picks, hammer bit (a.k.a. percussion bits), etc. or a combination thereof. DRCS system  1000  may have a conventional drill bit that is, for example, a roller cone, and an outer cutting structure that is a natural diamond cutter. Other combinations are possible as well such as having identical drill cutting structures for the inner and outer cutting structures. The inner or outer cutting structures may mix different rock destroying mechanisms such as an inner cutting structure with PDC and impregnated diamond or an outer cutting structure with natural diamond and roller cones or any combinations of the aforementioned rock destruction mechanisms. 
     Also unique to DRCS system  1000  is the use of a drilling mud motor that has the inner bit/cutting structure integrated monolithically with the mud motor drive shaft. This configuration provides for a shorter drilling assembly that is desirable for many reasons. For example, the farther a drill bit face/cutting structure is located from the supporting radial bearings in or below the mud motor, the greater the moment force. This greater force leads to earlier bearing wear, which leads to reduced drill bit stabilization and accelerated wear or damage to the drill bit/cutting structure. Another benefit of the integrated drill bit/drive shaft is better rigidity of the drill bit/cutting structure and higher torque transmitting capacity than conventional mud motor/drill bit connections that are typically 2⅜″ thru 7⅝″ regular API connections. 
     Another unique feature with DRCS system  1000  is the ability to use a (¼ to 5 degrees) bent housing in DRCS drill string with bend  1091  ( FIG. 10A ) to create an off-axis rotation of both inner  1020  and outer  1030  cutting structures. This off-axis rotation creates a variable pivoting pattern at the cutting structure/rock engagements. In a drilling assembly without a bent housing such as DRCS drill string with no bend  1090  ( FIG. 10A ) and conventional motor drill string  300  ( FIG. 3A ), the low rotational surface speed of inner most cutters  1022  create drilling inefficiencies that limit the performance of the drilling system. Cutter rotational surface speed when under pure rotation (that is no lateral motion) as can happen without a bend, is defined by the relationship: cutter rotation surface speed is equal to the RPM*2πr where RPM is the rotational speed and r is the radius or distance of the subject cutter from the axis of rotation. As r approaches zero, the cutter rotation surface speed approaches 0. Bent housing element  1008  reduces conventional inefficiencies by introducing enhanced multi axis motion at center cutters  1008  (generally PDC) to better fail the rock in the center of the wellbore. The enhanced multi axis motion effectively removes the center cutter inefficiencies allowing for improved drilling efficiency of the entire system. This feature also improves the life of the PDC cutters 
     Another important aspect of DRCS system  1000  is the ability to use some components of conventional steerable system  10  (reference  FIG. 1 ) in combination with the described improvements for DRCS system  1000 . Generally, the motor is selected to generate sufficient torque to rotate and power all of the cutting structures (conventionally the drill bit). For example, for an 8¾″ bit, the likely choice would be a 6″ OD range mud motor. With DRCS system  1000 , the mud motor power is only required to rotate the generally smaller diameter inner bit/cutting structure  1020  as outer cutting structure  1030  is rotated by drill string rotation. In this embodiment, much less power should be required and a smaller OD, shorter length and/or higher speed power section could suffice. As examples, a 6″ OD range mud motor but with a shorter power section or a smaller OD power section. The benefit derived could be a shortened power section or additional space (adjacent, radial or axial) around or just above the power section is now available for placing a variety of measurement sensors and power sources more convenient to the drill bit or cutting structures. This closer proximity can provide better and more accurate data to make decisions related to the drilling efficiency, safety of the drilling operation and cost of the well. Another potential advantage of extracting less power from the drilling fluid is that more hydraulic power is now available to increase bit HSI (horsepower per square inch) for better hole cleaning. Based upon the above teaching, one ordinarily skilled in the art could easily see that DRCS system  1000  in this embodiment cannot create the active directional change made possible by certain features of conventional steerable system  10 . 
       FIG. 10C  shows an exemplary embodiment of dual rotating cutting structure system  1000  where inner cutting structure  1020  extends below the distal end of outer cutter structure  1030 , contacting the formation to be drilled first and supported by axial bearings  1040  and radial bearings  1042 . Outer cutting structure  1030  would then increase the wellbore diameter to the desired size as it removes undrilled formation above inner bit or inner cutting structure  1020 . As shown in  FIG. 10A  and  FIG. 10B , a unique feature of outer cutting structure  1030  is follow-guide  1038  designed to enter hole just drilled by inner bit  1020  and provide radial stabilization for outer cutting structure  1030  to enlarge the uncut portion of the wellbore. This follow-guide  1038  can be made with junk slots  1036 , similar to a PDC drill bit or it can be made as a ring (not shown) that provides 360-degree wellbore contact with orifices and/or nozzles to allow cuttings and return fluid flow. The distal end of follow-guide  1038  may be angled or tapered to assure smooth entry into the pilot hole cut earlier by inner cutting structure  1020  and provides stability for outer cutting structure  1030  reducing the chances of PDC cutter impact damage for outer cutters  1032 . In a tapered embodiment of the follow-guide (not shown), the proximal end of the taper may be extended slightly to a greater diameter than the above-mentioned pilot hole and contain cutting elements. This allows the follow-guide to radially centralize and axially stabilize as outer cutting structure  1030  drills the uncut portion of the hole. Another benefit of follow-guide  1038  is reduced loading on radial bearing  1042  thus extending bit and motor life and effectiveness. As shown in  FIG. 10C , inner cutting structure  1020  can extend below outer cutting structure  1030 , inner cutting structure  1020  can be substantially flush with outer cutting structure  1030  as shown in  FIG. 11 , or inner cutting structure  1020  can be retracted relative to outer cutting structure  1030  as shown in  FIG. 12 . 
       FIG. 19A  is a cross-sectional view of a non-limiting, exemplary embodiment is of a dynamic lateral pad system  1900  with one moveable pad  1902 . The illustration shows a cut away view of an integral drill bit and drive shaft  1904  and a moveable pad  1902  acted upon by a cam following mechanism  1906 , some of which have been described herein before. During slide mode drilling, the moveable pad  1902  will extend and retract based on the cam following mechanism  1906  and the cam race  1908  geometry. When the moveable pad  1902  is in the extended position, the exterior surface engages the sidewall of the wellbore creating a directional bias. When the moveable pad  1902  is in the retracted position, the moveable pad  1902  is generally flush with the housing  1910 , although in certain embodiments it may extrude slightly and/or be recessed. The integral drill bit and drive shaft  1904  rotates relative to the generally non-rotating drill string housing  1910  during steering of the of device. The integral drive shaft and drill bit  1904  has a continuous circumferential cam race  1908  with variable radial depth. On the outer housing of the bottom hole assembly, at least one recess  1912  is formed in the housing  1910  for the moveable pad  1902  to extend and retract. As shown in  FIG. 19B , the moveable pad  1902  as shown in the illustration has two opposing locking tabs  1914  to retain the moveable pad  1902  within the recess  1912 . In certain embodiments, exterior plates  1916  are attached with bolts (not specifically shown) or similar method over top of the tabs to retain the moveable pad  1902  operatively in the recess while allowing the pad to freely extend and retract within a given range of travel. The moveable pad  1902  may be hollow to accommodate an elastic member  1918  ( FIG. 19A ), such as, a coned-disc spring stack as shown, which is commonly referred to as a Belleville spring. The moveable pad  1902 , optionally, has a hole or bore to allow fluid communication between the outer housing and the inner housing primarily to provide flush cooling and to help lubricate the surface between the moveable pad and a cam follower cup  1920 . The coned-disc spring stack serves multiple functions. One exemplary function may be to provide compliance to varying wellbore internal diameters. Another exemplary function may be to provide shock load dampening. Another exemplary function may be to provide a calibrated maximum force on the moveable pad  1902 . Another exemplary function may be to act as a failsafe allowing the moveable pad  1902  to revert to a retracted safe condition in the event of an unexpected interference fit with the borehole thus protecting the mechanism. Any given embodiment may include some, all, none, or other of these functional example. An optional gasket (not specifically shown) can be positioned in a groove of the inner diameter of the recess  1912  to centralize the moveable pad  1902  and mitigate fluid flow between the recess  1912  and the moveable pad  1902 . Underneath the coned-disc spring stack is the cam follower cup  1920  ( FIG. 19A ). The cone follower cup has a mating surface to operatively transfer force from the cam follower to the moveable pad. The cam follower cup  1920  can be a roller ball, tapered roller, cylinder roller, sliding pad or similar cam following system. It should be noted that the cam race  1908  has an extended width to accommodate axial displacement due to potential wear from the ball bearing thrust stack typical in most bottom hole assemblies. It should also be noted that it is possible to have any variety of cam profiles, ramp build and decay rates or timing schemes formed on the cam race. Unique to this configuration is that as the pad is extended, the tabs act to provide a counter force to retract the pads back into the housing as the cam follower force is relieved. It can be appreciated that more than one pad may be used. It can also be appreciated that pads may be arranged in any variety of positions both radially and colinearly to create different biasing, steering and timing options, some of which are exemplified herein. It can also be appreciated that a box pin connection configuration to attach the bit may also be used for this embodiment. 
     With reference now to  FIGS. 19C and 19D , a non-limiting, exemplary embodiment  1930  to the embodiment  1900  is provided. The non-limiting, exemplary embodiment  1930  uses an integral drill bit and drive shaft  1932  and a cam following mechanism  1934  acting upon a moveable pad  1936  allowing it to extend and retract within a recess  1912 . This design demonstrates an alternative moveable pad  1936  assembly. The generally cylindrical moveable pad  1936  assembly uses an integral cantilever shaft  1938 , which is attached to the housing  1940 . The cantilever shaft is secured to the housing using bolts  1942  or similar attachment means. The cantilever shaft  1938  operatively provides a retraction force on the pad to return it back into the recess  1912 . A gasket  1944 , such as an O-ring, is seated in an inner diameter groove of the cylinder to circumferentially support the cantilever arc path of the pad as well as mitigate fluid flow in the recess  1912  channel between the moveable pad  1936  and cylinder. The moveable pad  1936  may include a hole  1937  allowing fluid communication between the outer and the inner housing primarily to provide flush cooling and to help lubricate the surface between a ball  1946  and the cam follower cup  1948 . It can be appreciated that the pad mechanism can be positioned in other orientations, such as 180 degrees on the housing from what is illustrated, such that the attachment of the cantilever shaft can be toward the cutting structure. It can also be appreciated that more than one cam following pad can be mounted on the housing. It can also be appreciated that multiple pads can be placed in different radial positions and with the option of different timing schemes. It can also be appreciated that a box pin connection configuration to attach the bit could also be used for this embodiment. 
       FIGS. 19E and 19F  show a DLP system  1950 , which is similar to the above in certain aspect. In particular, the DLP system  1950  uses an integral drill bit and drive shaft  1952 , and a cam following mechanism  1954  acting upon a plurality of moveable pads  1956 , in this exemplary embodiment, allowing them to extend and retract within corresponding recesses  1912 . The DLP system  1950  provides three moveable pads  1956  collinearly positioned on the housing  1958 . Each of the moveable pads  1956  is partitioned with two outer diameters such that an exterior locking retention plate  1960  on each side will restrict the moveable pads  1956  from over extending. Depending on the space between pads, and other design factors, one exterior locking plate  1960  could be used to lock two pads or more pads. In some embodiments, each moveable pad  1956  would have one or more locking plates  1960 . The locking plate  1960  could also be a ring or other locking structure surrounding each pad. As described in the previous embodiment, each pad may use a fluid communication hole between the outer housing and the inner housing primarily to provide flush cooling and to help lubricate the surface between the ball and the cam follower cup  1954 . This embodiment allows for the advantageous rotation of the pads. Active rotation could be induced using a modified cam race profile creating a bias to spin the cam follower, spring, and pad. Alternatively, pad rotation can be induced via various contoured patterns of grooves or channels on the pad face. Consistent with previous cam race descriptions, it is possible to have multiple undulations as well as differing thickness and slopes. It can also be appreciated that any number of timing patterns between pads as well as ramp build and decay rates for each pad can be configured depending on the drilling application. It can also be appreciated that a box pin connection configuration to attach the bit could also be used for this embodiment. 
       FIGS. 19G  and H provide an exemplary DLP system  1970  a mandrel  1972  with a box pin connection  1974  to attach a drill bit  1976  and a cam following mechanism  1978  acting upon a plurality of cylindrical, movable pads  1980  allowing it to extend and retract within a recess  1912 . In this configuration, two moveable pads  1980  are collinearly positioned in two different radial locations on the housing. As described in the previous embodiment, each individual pad  1980  will extend and retract specific to a prescribed cam profile. As described in the previous embodiment each pad can optionally rotate via a biasing cam profile pattern, contoured grooves and patterns on the pad or similar methods. It should be noted that pads can be positioned in any number of patterns on the housing. Non-limiting and non-inclusive examples are collinear rows of pads, radial patterns of pads, helix patterns, symmetric clusters, asymmetric clusters, and pads in random positions on the housing. It can also be appreciated that any variety of extension and retraction patterns can be configured. Non-limiting and non-inclusive examples are the sequential extension and retraction of a collinear group of pads, two or more pads extended with one or more retracted in a collinear group, sequential timing between pads in different radial positions and at least two pads extending or contracting at the same time in different radial positions. It should be noted that any number of custom pad extension and retraction patterns can be customized based on the drilling application and bottom hole assembly configuration. It will be appreciated that certain pad extension and retraction patterns can induce favorable vibrations to reduce drill string friction with the borehole wall, especially during build and lateral drilling. Certain pad extension and retraction patterns could induce advantageous drill string rocking to facilitate well bore cleaning and cuttings removal. It should be noted that an integral drill bit and drive shaft configuration could also be used in place of a box pin connection to attach the drill bit. 
     Course Holding for Rotary Mode Steerable Motor Drilling 
     Oil and gas well directional drilling is commonly accomplished with a bent housing positive displacement motor assembly. Course corrections using subject assemblies are accomplished by orienting the bend of the assembly and allowing the assembly to drill ahead in “slide mode” without rotation of the drill pipe. When a survey ascertains that the drilling is progressing on the chosen course, the assembly is put into “rotate mode,” in which the assembly drills forward via rotation of the drill pipe. 
     The goal in rotate mode is to continue forward along the achieved and desired path. Drilling forward along the desired path is referred to as “neutral drilling.” In practice, over time the assembly typically experiences a slight departure or drift from the chosen path. The departure may be upwards (referred to as “build”), downwards (referred to as “drop”), or left and/or right (referred to as “turn” or “walk”). The deviation may be a combination of inclination change and orientation change. 
     The deviation from neutral drilling is frequently referred to as the “tendency of the assembly” in rotate mode. When the cumulative departure or drift from the chosen path is too great, a correction must be made in slide mode to bring the assembly back to the chosen path. Each correction slows drilling down and creates increased tortuosity in the wellbore. In a long lateral drilling section, the cumulative tortuosity brought about due to multiple corrections can produce excessive torque and drag, which limits the length of lateral that can be drilled. 
     The specific directional tendency of the assembly in rotate mode is produced by one or more of several different factors, including but not limited to: bit torque, bit profile, bit gauge length, current inclination, string torque, formation dip, formation properties, assembly stabilization, bend angle, weight on bit, rotational speed and inertia, and gravity. 
     A bend housing directional assembly drilling ahead in rotate mode may create an oversize hole due to the bend in the assembly. Higher bend angle assemblies generally create larger oversize hole diameters because the drill string rotation causes the drill bit to orbit at a greater circumference around the hole centerline. 
     A bend housing assembly producing a directional tendency in rotate drilling is exhibiting a preferential bias in the direction of the tendency. In other words, the assembly&#39;s cumulative center of rotation is biased in the direction of the tendency exhibited. Another way of stating this is that the assembly tends to lean or push against the wellbore wall in the direction of the deviation tendency. The greater the rate of deviation, the greater the cumulative bias, which can be termed the deviation force. 
     The deviation force exhibited or experienced by the assembly is not necessarily constant in frequency, direction, or strength. The assembly may move forward for many revolutions of the drill string without exhibiting a deviation force interaction, or it may move forward with a varying direction of deviation force interaction forestalling for a distance a biased departure. Ultimately, the assembly will be more likely to exhibit a greater frequency or strength of deviation force in the direction of the directional tendency. It is the cumulative sum of deviation forces exhibited by the assembly that produces the directional tendency of the assembly. 
     Predicting and trying to control or mitigate the directional tendency in rotate mode with a bend housing assembly has been a long-sought goal. In instances where a higher degree of bend was utilized, this goal has been even more difficult to achieve. 
     Introduced here, therefore, are assemblies that employ one or more motor mandrel cam-driven Dynamic Lateral Pads (DLPs) to provide a restoration force in opposition to the deviation force(s) of the rotating assembly. In certain embodiments, the DLPs are deployed generally on the bend side of the assembly proximal to the drill bit and distal of the bend of the bend housing. The DLPs may deploy and retract one or more times per motor (mandrel) revolution depending on the mandrel cam configuration. The DLPs can be provided with a stroke that pushed them out to a diameter substantially equal to, or slightly greater than, the bit diameter. When the assembly is biased against a hole wall, the deployed DLPs push against the hole wall with a greater force or frequency in opposition to the deviation bias direction to provide a restorative force to the assembly. The action of the DLPs can counter the deviation force, thereby reducing or eliminating the directional tendency. 
     An example is provided as follows: 
     Motor (and Mandrel) Revolutions Per Minute(RPM)=240 (i.e., four revolutions per second)
 
One DLP, One Camming Lobe=240 deployments of DLP per minute 32 DLP deploys once every 0.25 seconds
 
Rotary (Outer Assembly) RPM=60 (i.e., one revolution per second)
 
For each revolution of the assembly, the DLP will deploy four times. In such embodiments, deployment of the DLP may occur in 90 degree increments (e.g., once in each quadrant).
 
     In a revolution of the assembly where a deviation bias of the assembly occurs, the deployment of the DLP in the quadrant of the deviation bias will push against (e.g., tap or strike) the borehole wall providing a restorative force (also referred to as a “counter-deviation force”). Since the assembly in this instance is off center in the direction of the deviation bias, the deployed DLP will fail to touch, or at least less forcefully touch, the borehole wall in the other three quadrants. To some degree, the location of the touch point can be altered by changing the rotational speed of the housing, the rotary speed, or the flow rate (which changes RPM of the mandrel). 
       FIG. 20  provides a typical tool face angle chart or dial  2000 . Dial  2000  includes center point  2001 , inclination/declination dividing line  2002 , and left turn/right turn dividing line  2003 . Dial  2000  reflects the accepted definitions of build, right turn, drop, and left turn, as well as the accepted angular definitions of deviation from neutral drilling. Note, for example, that 225° marks the dial angular value for equal values of drop and turn left. 
       FIG. 21A  provides a cross-sectional view  2100  of an oversized rotary drilled hole  2105  at the locations of a rotating bit gauge circumference  2104 . The cross-sectional view  2100  also shows neutral drilling center point  2101  and generalized orbiting bit diameter center points  2102 . Rotational circumference  2103  shows the rotational orbit of the bit diameter center points  2102  as they rotate around the neutral drilling center point  2101 . Note that the cross-sectional view  2100  (and the features shown) are not necessarily to scale but are intended to illustrate the general concept of oversized drilling with a bend housing assembly (not shown). 
       FIG. 21B  provides a detailed cross-sectional view of the hole area shown in  FIG. 21A  in neutral drilling mode. More specifically,  FIG. 21B  shows the neutral drilling center point  2101  and generalized orbiting bit diameter center points  2102 . Rotational circumference  2103  shows the rotational orbit of the bit diameter center points  2102  as they rotate around the neutral drilling center point  2101 . 
       FIG. 21C  provides an alternative detailed cross-sectional view of the hole area shown in  FIG. 21A  after drilling has advanced some distance. In  FIG. 21C , the neutral drilling center point is shown at  2101 . A deviation force, meanwhile, is shown at  2120 . When the deviation force  2120  is applied, the center point of the rotating bit diameter will shift to the advanced and now deviated location  2111 . The deviation shown is generally indicative of drop and left turn of approximately 225° on the tool face dial. 
       FIG. 22  provides a generalized and exaggerated comparative side view  2200  of a neutral drilling borehole  2206  and a drop deviation borehole  2216 . Neutral drilling borehole  2206  is shown proceeding along neutral drilling centerline  2201 . When a downward deviation force  2220  is applied, however, drilling will result in a deviated borehole  2216  along deviated drilling centerline  2211 . 
       FIG. 23  provides a generalized and exaggerated comparative top view  2300  of a neutral drilling borehole  2306  and a left turn deviation borehole  2316 . Neutral drilling borehole  2306  is shown proceeding along neutral drilling centerline  2301 . When a leftward deviation force  2320  is applied, however, drilling will result in a deviated borehole  2316  along deviated drilling centerline  2311 . 
       FIG. 24  provides an end view  2400  of a neutral drilling borehole. Center point  2401  is shown, as is borehole diameter  2405 . As shown in  FIG. 24 , neutral drilling will result in a roughly consistent borehole that proceeds along a single path. 
       FIG. 25  provides an end view  2500  of a deviated dropping and left turning borehole  2516 . Because the drilling apparatus is under the influence of deviation force  2520 , the borehole  2516  will drop to the left along centerline  2511 . The deviation shown in  FIG. 25  is generally indicative of drop and left turn of approximately 225° on the tool face dial. 
       FIG. 26A  provides an isometric view  2600  of a partial section of a basic Dynamic Lateral Pad (DLP) assembly consistent with the technology of the present application. The DLP assembly may have a lower housing  2607  that includes a DLP blade  2631  and a DLP  2630  (also referred to as a “pad” or “DLP pad”). In  FIG. 26A , the DLP  2630  is shown in the retracted position. Distal of lower housing  2607  is the lower mandrel  2608 . The lower mandrel  2608  may include a connection cavity  2609  for receiving a drill bit (not shown). 
       FIG. 26B  provides a cross-sectional view of a Dynamic Lateral Pad (DLP) assembly taken through section A-A of  FIG. 26A .  FIG. 26B  shows the lower housing  2607  with the DLP blade  2631  and retracted DLP  2630 . The cross-sectional view does not show the mandrel or the activation mechanism of the DLP  2630 . The activation mechanism of the DLP  2630  is further described above (e.g., with respect to  FIGS. 13-15 ). 
       FIG. 27A  provides a cross-sectional view  2700  of an oversized rotary drilled hole  2705  at the location of a rotated cross section of a deployed Dynamic Lateral Pad (DLP)  2740  during neutral drilling consistent with the technology of the present application. For clarity, only the cross section of the deployed DLP  2740  and DLP blade  2731  are shown. Dashed lines  2732  are not structural features but instead are shown for reference. The apex of each pair of dashed lines  2732  converges toward the center of the assembly at each portion of rotation shown. Circle  2703  shows the oversized rotation of orbit of the assembly around the center point  2701  of the borehole. 
       FIG. 27B  provides a cross-sectional view  2700  of the oversized rotary drilled hole  2705  of  FIG. 27A  with a rotated and retracted Dynamic Lateral Pad (DLP)  2730  during a single rotation during neutral drilling. For clarity, only the cross section of the retracted DLP  2730  and DLP blade  2731  are shown. Dashed lines  2732  are not structural features but instead are shown for reference. The apex of each pair of dashed lines  2732  converges toward the center of the assembly at each portion of rotation shown. Circle  2703  shows the oversized rotation of orbit of the assembly around the center point  2701  of the borehole. 
       FIG. 28  provides a cross-sectional view  2800  of an oversized rotary drilled hole  2805  at the location of a rotated cross section of a deployed Dynamic Lateral Pad (DLP)  2840  experiencing a deviation bias. For clarity, only the cross section of the deployed DLP  2840  and DLP blade  2831  are shown. Dashed lines  2832  are not structural features but instead are shown for reference. The apex of each pair of dashed lines  2832  converges toward the center of the assembly at each portion of rotation shown. Circle  2803  shows the oversized rotation of orbit of the assembly around the deviated center point  2801  of the borehole. 
     In some cases, a deviation force  2820  will act on the assembly during drilling. When the DLP  2840  is deployed, engagement of the DLP  2840  with the oversized borehole  2805  will result in a restoration force  2821  that at least partially counters the deviation force  2820 . In this example, the deployed DLP  2940  is shown engaging the wall of the oversized borehole  2805  generally at the location indicated by bracket  2842  in direct response to the deviation force  2820 . This example shows the deviation force  2820  generally towards 225° and the restoration force  2821  in direct opposition to the deviation force  2820 . Depending on the timing of the rotation of the housing (not shown) and the deployment cycle of the DLP  2840 , two individually less forceful engagements could occur, for example at 180° and 270°. In combination these two engagements could provide a combined restoration force comparable to the restoration force  2821  shown in  FIG. 28 . In such embodiments, each individual restoration force may be said to indirectly oppose the deviation force  2820 , while the combined restoration force may be said to directly oppose the deviation force  2820 . Although  FIG. 28  shows the deviation force  2820  generally towards 225° degrees, it should be understood that the deviation force  2820  may by in any tool face direction around the tool face dial and that the restoration force  2821  provided by the deployed DLP  2840  will respond in opposition to the deviation force. 
       FIG. 29  provides a generalized top view  2900  of a borehole illustrating the interaction of weight on bit drilling force  2951 , deviation force  2920 , and restoration force  2921  over a brief period of time as shown along  2953  and brief distance as shown along  2954 . This example shows a plan view of drilling process along a centerline  2911  as the direction of the resultant force  2952  shifts slightly (e.g., between left turn 270° and right turn 90° as marked by azimuth left turn/right turn line  2949 ) under the influence of the deviation force  2920  and restoration force  2921 . This plan view only takes into account azimuth since it is a two-dimensional graphic, but it should be noted that the same factors may apply to inclination or a combination of inclination and azimuth. Looking along timeline  2953  at the interval marked “1st Second,” the drilling path along the centerline  2911  is demonstrating neutral drilling. However, at the end of the “1st Second” interval, a deviation force  2920  commences pushing the centerline  2911  of the drilling path to the left towards the 270° direction on azimuth line  2949 . Midway through the “2nd Second” interval, a restoration force  2921  pulses from the engagement of the DLP with the hole wall (not shown) and begins to push the resultant force  2952  back towards 90° on the reference azimuth line  2949 . Continuing pulses of restoration force  2921  can be seen in the “3rd Second” interval and “4th Second” interval to overcome the deviation force and return the centerline  2911  to its original course, as shown in the “5th Second” interval. A somewhat similar cycle can be seen occurring in the “6th Second” interval and “7th Second” interval. 
     The data presented in  FIG. 29  is based on the previously discussed example parameters of 60 RPM for the housing, 240 RPM for the motor mandrel, a single DLP, and a single activating cam lobe on the mandrel. The data also assumes a 60 foot per hour penetration rate. While these parameters are fairly typical, they are by no means required to implement the technology of the present application. The data may vary as these parameters change. 
     As can be seen in  FIG. 29 , in a short 7 second time span and a short 1.4″ of drilling (as shown by the 0.200″ increments along drilled distance line  2954 ), multiple cycles of deviation force  2920  and restoration force  2921  can occur. The predominant force in any drilling scenario is the weight on bit drilling force  2951 . However, the direction of the drilling force may be modified by a deviation force as was illustrated in  FIGS. 22, 23, and 25 . Deviation is discussed in terms of degrees per 100 feet, such as “4°/100.” As shown in  FIG. 29 , the deviation force  2920  and restoration force  2921  come into play on a much smaller scale. Deviation can begin with an inception of a deviation bias. While the deviation bias does not directly translate the borehole laterally, it can slightly bend or redirect the resultant force  2952  to shift the direction of the borehole as the drill bit drills ahead. 
     In certain embodiments, deployment of DLP(s) occurs with a frequency based on the RPM of the motor and/or the number of cam lobes on the mandrel. DLP deployment may not substantially engage the borehole wall during neutral drilling. When the assembly is biased towards the borehole wall by a deviation bias, the DLP will begin to engage the borehole wall nearly instantaneously in direct response to the deviation bias, thereby providing a restoration force that pushes the assembly back towards the original borehole centerline. The response can be purely geometric and mechanical. Accordingly, unlike extremely expensive and complicated Rotary Steerable Systems that require electronic communication means, feedback loops, and activation commands, the technology described herein may be constantly “active” but only provide restoration force when bias of the assembly brings DLP(s) into contact with the borehole wall. 
     In a scenario where the deviation force overcomes the pulses of restoration force and succeeds in slightly modifying the drilling path, then a new path will be established as “neutral drilling.” The assembly will respond to the new assembly bias to produce restoration force to the most recent path. There is still significant value in the technology even in this scenario. For instance, an unresisted deviation bias that would ultimately produce a 4°/100′ deviation may be mitigated to only 2°/100′. Without the technology described herein, a correction slide run may be required after just 100′ of drilling. However, with the technology described herein, the driller may choose to drill ahead for 200′ or more prior to making a correction. Fewer correction runs translates into much greater lateral drilling length potential, easier completion running, and less production maintenance cost and difficulties. 
     Depending on formation properties, drilling parameters, and experience with the DLP system described herein, an assembly designer may choose to increase or decrease the amount of deployment extension of each DLP. For instance, in softer formations the assembly designer may want a greater extension of the DLP to ensure it generates enough restoration force in response to a deviation bias. Additionally or alternatively, the assembly designer may choose to employ DLP(s) with greater surface area and/or an increased number of DLP(s) to increase the engagement with the borehole wall in response to a deviation bias. 
     In certain embodiments, the directional driller may choose to alter the rotary mode rotate speed, or the flow rate to fine tune the response of the assembly to a deviation bias. If the measurement-while-drilling readings indicate to the directional driller that the DLP system is not fully providing restorative force in response to deviation bias, then changes in rotary speed or flow rate may better position the engagement of the DLP(s) with the borehole wall. 
     The technology of this application may be deployed across the range of available bend housing directional motor configurations including for instance high speed, low torque motors, low speed high torque motors, high bend angle or low bend angle housings, or standard or short bit to bend. 
     Although the technology has been described in language that is specific to certain structures and materials, it is to be understood that the invention defined in the appended claims is not necessarily limited to the specific structures and materials described. Rather, the specific aspects are described as forms of implementing the claimed invention. Because many embodiments of the invention can be practiced without departing from the spirit and scope of the invention, the invention resides in the claims hereinafter appended. Unless otherwise indicated, all numbers or expressions, such as those expressing dimensions, physical characteristics, etc. used in the specification (other than the claims) are understood as modified in all instances by the term “approximately.” At the very least, and not as an attempt to limit the application of the doctrine of equivalents to the claims, each numerical parameter recited in the specification or claims which is modified by the term “approximately” should at least be construed in light of the number of recited significant digits and by applying ordinary rounding techniques. Moreover, all ranges disclosed herein are to be understood to encompass and provide support for claims that recite any and all subranges or any and all individual values subsumed therein. For example, a stated range of 1 to 10 should be considered to include and provide support for claims that recite any and all subranges or individual values that are between and/or inclusive of the minimum value of 1 and the maximum value of 10; that is, all subranges beginning with a minimum value of 1 or more and ending with a maximum value of 10 or less (e.g., 5.5 to 10, 2.34 to 3.56, and so forth) or any values from 1 to 10 (e.g., 3, 5.8, 9.9994, and so forth).