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BACKGROUND 
     Some wells may need to be drilled using a complex trajectory to reach multiple target areas or to perform other operations. Therefore, operators must be able to precisely “steer” the drilling direction. To do this, operators can remotely operate a directional drilling device near the drill bit to control the drilling direction. Various types of directional drilling devices are known in the art. One such device uses a variable stabilizer, such as disclosed in U.S. Pat. No. 4,821,817, to control the drilling trajectory. The variable stabilizer has stabilizer blades that center the drill string within the borehole. Drilling mud pumped downhole is used to control the variable stabilizer by retracting the blades. When selected blades are retracted, the device permits the drilling angle of the drill bit to be changed. 
     Another directional drilling device is commonly referred to as a bent housing mud motor. This device uses a mud motor disposed on a housing that has an axis displaced from the axis of the drill string. In use, circulated drilling fluid hydraulically operates the mud motor, which has a shaft connected to a rotary drill bit. By rotating the drill bit with the motor and simultaneously rotating the motor and bit with the drill string, the device produces an advancing borehole trajectory that is parallel to the axis of the drill string. However, by rotating the drill bit with the motor but not rotating the drill string, the device can produce a borehole trajectory deviated from the axis of the non-rotating drill string. By alternating these two methodologies, operators can control the path of the borehole. 
     Another directional drilling device is a rotary steerable system that can change the orientation of the drill bit to alter the drilling trajectory but does not require rotation of the drill string to be stopped. One type of rotary steerable system is disclosed in U.S. Pat. No. 6,116,354, which is incorporated herein by reference. Although effective, rotary steerable systems during certain operations can suffer from vibrations and oscillations that can be extremely damaging and hard to control. These uncontrolled vibrations can especially occur when the rotary steerable system is run below a high torque mud motor with a reasonably high speed (i.e., a total bit RPM of about 110). Generally the higher the RPM, the higher the likelihood of CCW whirl. 
     In particular, a bottom hole assembly having a rotary steerable system essentially acts as a series of rotating cylindrical spring mass systems with variable support points (typically stabilizers or extended blades). The natural frequencies of these spring mass systems can create a variety of damaging vibrations during operation. Ideally, the bottom hole assembly experiences concentric rotation so that drill bit has sliding contact with the borehole wall. Although the assembly may initially be in sliding contact, the assembly eventually tries to ride up the wall in a horizontal borehole, but gravity and bending strain tend to throw the assembly back downslope. 
     The riding and dropping of the assembly in the borehole can intensify and becomes more violent with increasing impact loads propelling the assembly back and forth across the borehole. Eventually, the multiple impacts can develop into counterclockwise (CCW) bit whirl in which the drill bit is in continuous rolling contact with the borehole wall. At this stage, the frequency of the whirl action jumps dramatically, and the bottom hole assembly oscillates in a counterclockwise direction opposite to the rotation of the drill string. In general, the resulting motion can be defined by a Hypocycloid sub form of general Hypotrochoids. (This is true for a point on the outer surface of the BHA because the center describes a circle of diameter equal to the borehole clearance). The whirl action from the drill bit can travel up the drill string and can affect multiple points on the assembly. 
     As expected, counterclockwise bit whirl can unevenly wear the drill bit&#39;s cutters and can create fatigue in the various components of the bottom hole assembly and drill string. For this reason, operators need a way to reduce or minimize the development of counterclockwise bit whirl in a bottom hole assembly having a rotary steerable system or any other rotary drilling assembly. 
     SUMMARY 
     A bottom hole assembly for directional drilling avoids damaging vibrations that conventional assemblies may experience during operation. The assembly has a drill bit, a first collar that rotates with the drill bit, a rotary steerable tool that can control the trajectory of the drill bit, and a second collar that rotates with the drill string used to deploy the assembly. 
     The rotary steerable tool can use point-the-bit or push-the-bit technology. For example, the rotary steerable tool can have a center shaft that drives the drill bit and can have a non-rotating sleeve disposed about the center shaft and configured to remain rotationally stationary relative to the shaft. Hydraulically actuated pistons on a mandrel disposed in the sleeve can deflect the center shaft relative to the sleeve to direct the drill bit, and a stabilizer disposed on the first collar can act as a fulcrum point for the tool. During operation, both the drill string and the bit are rotated, and a mud motor on the assembly can impart rotation to the drill bit. 
     In one arrangement, the first collar coupled between the drill bit and the rotary steerable tool defines a bend that deflects the drill bit from an axis of the first collar. The bend can be predefined in the collar or can be adjustable. During operation, this bend causes a portion of the bottom hole assembly to engage the borehole wall. In this way, the bend can inhibit counterclockwise (CCW) bit whirl from developing at the drill bit by promoting clockwise whirl in a portion of the bottom hole assembly, generating friction against the borehole wall, and dampening vibrations generated at the assembly. By inhibiting or even preventing CCW bit whirl at the bottom hole assembly, other damaging vibrations such as CCW whirl in the drill string can also be prevented from forming up the borehole. In other arrangements, only the second collar between the tool and the drill string can define a bend, or both the first and second collars can define bends. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  illustrates a bottom hole assembly having a rotary steerable tool according to the present disclosure. 
         FIG. 2A  illustrates the bottom hole assembly with the rotary steerable tool in a first orientation. 
         FIG. 2B  illustrates an internal cross-section of the rotary steerable tool in  FIG. 2A . 
         FIG. 3A  illustrates the bottom hole assembly with the rotary steerable tool in a second orientation. 
         FIG. 3B  illustrates an internal cross-section of the rotary steerable tool in  FIG. 3A . 
         FIG. 4A  illustrates an isolated view of the lower end of the bottom hole assembly showing the bend in the lower collar. 
         FIG. 4B  illustrates an isolated view of the lower end of the bottom hole assembly showing an adjustable bend in the lower collar. 
         FIG. 4C  illustrates the deflection of the drill bit&#39;s rotational path produced by the bend in the lower collar. 
         FIG. 5A  illustrates a bottom hole assembly having a bend in the collar disposed above the rotary steerable tool. 
         FIG. 5B  illustrates a bottom hole assembly having bends in the collars both above and below the rotary steerable tool. 
     
    
    
     DETAILED DESCRIPTION 
     A directional drilling system  10  in  FIG. 1  has a bottom hole assembly  50  deployed on a drill string  22  in a borehole  40 . Although shown vertical, this borehole  40  can have any trajectory. The assembly  50  has an upper collar  52 , a rotary steerable tool  60 , a lower collar  66 , and a drill bit  58 . In general, the upper collar  52  can house a control electronics insert having batteries, directional sensors (e.g., magnetometers, accelerometers, gamma ray sensors, inclinometers, etc.), a processing unit, memory, and downhole telemetry components. The bottom hole assembly  50  can also have a mud motor  56  positioned in this upper collar  52  or elsewhere so that the mud motor  56  can provide torque to the drill bit  58  via a shaft (not shown) passing through the rotary steerable tool  60 . 
     During operation, a rotary drilling rig  20  at the surface rotates the drill string  22  connected to the bottom hole assembly  50 , and a mud system  30  circulates drilling fluid or “mud” through the drill string  22  to the bottom hole assembly  50 . The mud operates the mud pump  56 , providing torque to the drill bit  58 . As the drill string  22  rotates, the drill bit  58  and lower collar  66  also rotate. Eventually, the mud exits through the drill bit  58  and returns to the surface via the annulus. 
     During drilling, the rotary steerable tool  60  can be operated to direct the drill bit  58  in a desired direction using point-the-bit technology discussed later so that the bottom hole assembly  50  can change the drilling path. As noted previously, however, the bottom hole assembly  50  with the rotary steerable tool  60  can suffer from undesirable vibrations in some circumstances, and the resulting motion from the vibrations can be extremely damaging and hard to control, especially when the rotary steerable tool  60  is run below a high torque mud motor  56  with a reasonably high speed (i.e., a total drill bit RPM of about  110 ). It is believed that damaging vibrations that begin as counterclockwise (CCW) bit whirl starting at the bottom hole assembly  50  and that can travel up the assembly  50  and drill string  22 . The frequencies involved in CCW bit whirl can be at least an order of magnitude higher than the drill string&#39;s RPM and can be a function of the borehole&#39;s diameter, the drill bit&#39;s diameter, and dimensions of other components of the bottom hole assembly  50  that act as the driving surfaces for whirl. 
     Regardless of the frequencies involved, the whirl once CCW bit whirl develops can migrate up the drill string  22  where it changes frequencies as the casing/drill string traction diameters change. This migrating whirl can eventually lead to CCW whirl in the drill string  22 . The frequency of this whirl is believed to be established by the relative diameter of tool joints and the casing&#39;s internal diameter and is believed to be driven by the bottom hole assembly&#39;s CCW bit whirl, which can occur at a different frequency. 
     To alleviate the problems associated with CCW whirl, the rotary steerable tool  60  has a bend  67  in its rotating lower collar  66  near the drill bit  58 . As the collar  66  and bit  58  rotate, the bend  67  in the collar  66  can prevent CCW bit whirl from developing and evolving into other uncontrolled motions, such as whirl in the drill string  22  uphole. The bend  67  can prevent this evolution by clamping portions of the bottom hole assembly  50  in the borehole  40 , creating friction between the assembly  50  and the borehole wall, creating clockwise (CW) whirl in the assembly  50 , or producing a combination of these actions. 
     During operation, for example, the rotating bend  67  produces frictional damping as the bent collar  66  is forced straight in the borehole  40 . This friction inhibits the drill bit  58  from moving into rolling contact with the borehole wall, which could lead to CCW bit whirl. In addition, the bend  67  preloads the assembly  50  against the borehole wall and dampens harmful vibrations that may develop during operation and attempt to travel uphole. When this bend  67  is forced straight in the borehole  40 , for example, the bend  67  clamps portions of the bottom hole assembly  50  and adjacent drill string  22  against the borehole  40 . This clamping prevents resonant frequencies from developing and makes it harder for bit whirl to develop and travel uphole, because the traction of the drill bit  58  around the borehole wall cannot be maintained for an entire 360 degrees. 
     Finally, by engaging the borehole wall, the bend  67  also tends to create clockwise (CW) whirl that inhibits the extremely damaging hypocycloidal CCW bit whirl from developing. As expected, CCW whirl of the bit  58  cannot coexist with CW whirl in the assembly  50  generated by the collar  66 . In this way, any CW whirl created by the collar  66  occurring at the collar&#39;s rotational frequency forces the drill bit  58  out of continuous rolling contact with the borehole wall and breaks up any CCW bit whirl that may develop. 
     As shown in more detail in  FIGS. 2A-2B , the bottom hole assembly  50  coupled to the drill string  22  has a drill string stabilizer  52 A, the upper collar  54 , the rotary steerable tool  60 , the lower collar  66 , a near-bit stabilizer  52 B, and the drill bit  58 . The drill string stabilizer  52 A provides a contact point to control deflection of the tool  60 , and the near-bit stabilizer  52 B provides a fulcrum point for deflecting the rotary-steerable tool  60  so that the axis of the drill bit  58  can be oriented to change the drilling trajectory as discussed below. 
     A suitable system for the rotary steerable tool  60  is the Revolution® Rotary Steerable System available from Weatherford. As shown, the rotary steerable tool  60  has an upper end  62  coupled to the upper collar  54 . A center shaft ( 72 ;  FIG. 2B ) extending from components at the upper end  62  passes through the non-rotating sleeve  64  and couples to the lower collar  66 , to which the near-bit stabilizer  52 B and drill bit  58  couple. Both the non-rotating sleeve  64  and the rotating pivot stabilizer  52 B are close to the gage of the borehole  40  to maximize the directional performance of the tool  60 . The rotating shaft  72  running through the sleeve  64  transmits torque and weight through the tool  60  to the drill bit  58 . However, the non-rotating sleeve  64  is intended to engage the borehole  40  using a number of blades and anti-rotational devices to keep it from rotating. 
     As shown in the cross-section of  FIG. 2B , a mandrel  70  positions within the non-rotating sleeve  64  and has the shaft  72  passing through it. The shaft  72  has a hollow bore for drilling mud to pass through the shaft  72  to the drill bit ( 58 ). A plurality of pistons  76  surround the mandrel  70  and engage the inside wall of the sleeve  64 . Several banks of these pistons  76  run along the length of the mandrel  70  and shaft  72 . These pistons  76  can be operated by high pressure hydraulic fluid HF pumped by a hydraulic system (not shown) driven by the relative rotation between the shaft  72  and the non-rotating sleeve  64 . 
     As shown in  FIGS. 2A-2B , the rotary steerable tool  60  operates in a neutral position to drill a straight section of borehole  40 . In this neutral position, the tool&#39;s shaft  72  is concentric with the non-rotating sleeve  64  (See  FIG. 2B ). To control the drilling direction, however, the rotary steerable tool  60  can be deflected as shown in  FIGS. 3A-3B . In particular, onboard navigation and control electronics (not shown) monitor the orientation of the tool  60  and its components. When changes in borehole direction are desired, the control electronics activate a solenoid valve (not shown) to pump hydraulic fluid to selected pistons  76  when a commutating valve  74  on the shaft  72  turns relative to the pistons  76 . The hydraulic fluid HF pumped to selected pistons  76  causes them to extend outward from the mandrel  70  and to move the mandrel  70  internally relative to the non-rotating sleeve  64 . In turn, the moved mandrel  70  deflects the shaft  72  in a direction opposite to the desired trajectory, and the near-bit stabilizer  52 B acts as a fulcrum for the shaft  72  to point the drill bit  58  in the desired direction. 
     As shown in  FIGS. 2A and 3A , the bend  67  in the lower collar  66  essentially loads portions of the bottom hole assembly  50  against the borehole wall, clamping portions of the assembly  50  to the borehole  40 , and promoting rotational friction and CW whirl to prevent or reduce the occurrence of CCW whirl and other vibrations as discussed herein. Details of the bend  67  in the lower collar  66  are illustrated in  FIG. 4A . The bend  67  can be predefined in an integral collar  66  as shown in  FIG. 4A  or can be produced between joints of modular components of the collar  66  connected together. Alternatively, an adjustable bend  67 ′ as shown in  FIG. 4B  can be used. This adjustable bend  67 ′ can operate in a way similar to jointed bends found in bent housing mud motors, such as used on Weatherford&#39;s PrescisionDrill™ motor. The adjustable bend  67 ′ can be set at a desired angle between 0 to 3-degrees and can use an internal universal joint. 
     In one arrangement, the bend  67  may be disposed a length (L) of a several feet or less from the drill bit  58 , although the actual distance may vary given a particular implementation, size of the assembly  50 , etc. In general, the bend  67  may define an angle (θ) of from 0 to 3-degrees, although the angle may depend on variables of the particular implementation. In addition, the bend  67  may deflect the drill bit  58  by a deflection (D) of about 3/16 inch off axis or more. For example, the deflection (D) of the drill bit  58  may be about ¼-inch from axis of the tool  60 , although again the deflection (D) depends on the particular implementation. [Para  33 ] Given the deflection (D) by the bend  67 , the drill bit  58  when rotated sweeps a circular path that drills a borehole slightly larger than the diameter of the drill bit  58 . As shown in  FIG. 4C , for example, the rotational path of the drill bit  58  deflected by the bend ( 67 ) will produce a borehole  80  that has a diameter approximately 2×D (e.g., ½-inch) larger than the borehole  82  that would be produced with a non-deflected drill bit. Operators can take the amount of deflection (D) produced by the bend  67  into account when selecting the size of drill bit  58 , stabilizers  52 A-B, desired gage of the borehole, etc. 
     The bend  67  may even tend to dampen string vibration even in over gage holes. For example, the bottom hole assembly  50  having a ¼-inch off axis bend  67  may be effective even in a ⅜-inch over gage borehole. The bend  67  may also dramatically reduce the tendency of the assembly  50  to engage in stick slip oscillation, which are pumped rotational oscillations caused by forcing functions at the drill bit  58 . Although the actual amount of deflection required to be effective depends on the stiffness of the bottom hole assembly  50 , the deflection load is preferably sufficient to assure that at least a portion of the bottom hole assembly  50  engages and stays in contact with the borehole wall. 
     As discussed above, the lower collar  66  near the near-bit stabilizer  52 B can define the bend  67 . In an alternative shown in  FIG. 5A , the bottom hole assembly  50  can have a bend  57  in the upper collar  54  disposed above the rotary steerable tool  60 . As shown, this bend  57  can be positioned between the drill string stabilizer  52 A and the rotary steerable tool&#39;s sleeve  64 . For example, the bend  57  can be applied in the collar  54  or mud motor  56  immediately above the rotary steerable tool  60 , although other locations are possible. In one arrangement, the bend  57  can be located a distance of greater than 5-ft. from the bit  58  and can define an angle of about 1 to 1.5 degrees. In this way, the bend  57  can cause the upper section of the rotary steerable tool  60 , the mud motor  56 , and the assembly&#39;s collar  52  immediately above the rotary steerable tool  60  to be loaded against a borehole even in 1-inch over gage boreholes. 
     In another alternative shown in  FIG. 5B , the bottom hole assembly  50  can have a bend  57  in the upper collar  54  above the rotary steerable tool  60  and can have a bend  67  in the lower collar  66 . The upper bend  57  will rotate with the drill string&#39;s rotation, while the lower bend  67  will rotate with the drill bit&#39;s rotation. This offset in the rotation and contact of these bends  57  and  67  may have benefits in particular implementations. 
     In this specification, terms such as “upper”, “lower” and “bottom” may be used for convenience to denote parts which have such an orientation in the drill string when the drill string extends vertically in a borehole. However, it will be understood that these parts may have a different orientation when the bottom hole assembly is in a section of borehole that deviates from the vertical and may even be horizontal. 
     Although discussed as being used with the rotary steerable tool  60  that uses point-the-bit technology (namely a center shaft deflected by a mandrel with pistons in a non-rotating sleeve), the teachings of the present disclosure are also applicable to rotary steerable tools that use push-the-bit technology. A push-the-bit rotary steerable tool can use external pads extendable from a non-rotating sleeve to engage the borehole wall to direct the drill bit. Thus, this form of tool can have a center shaft driving the drill bit and can have a sleeve disposed about the center shaft that is configured to remain rotationally stationary relative to the shaft. At least one pad disposed on the sleeve is extendable therefrom to engage the borehole wall to change the trajectory of the drill bit. 
     The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof.

Summary:
A bottom hole assembly avoids damaging vibrations that can develop during directional drilling with a rotary steerable system. The assembly has a drill bit, a first collar that rotates with the bit, a rotary steerable tool that controls the bit&#39;s trajectory, and a second collar that rotates with the drill string. The first collar between the bit and the tool defines a bend that deflects the bit from the first collar&#39;s axis. During operation, this bend causes portion of the assembly to engage the borehole wall to inhibit counterclockwise (CCW) bit whirl by promoting clockwise whirl in the assembly, generating friction against the borehole wall, and dampening vibrations. By inhibiting CCW bit whirl, other damaging vibrations such as CCW whirl in the drill string can also be prevented up the borehole. Alternatively, only the second collar between the tool and the drill string may define the bend, or both collars can define bends.