AND METHOD OF USING SAME

BACKGROUND

[0001] This present disclosure relates generally to techniques for performing wellsite operations. More specifically, the present disclosure relates to techniques, such as drilling assemblies configured to address stresses, such as bending fatigue, while drilling a wellbore into a subterranean formation.

[0002] Oilfield operations may be performed to locate and gather valuable downhole fluids. Oil rigs are positioned at wellsites, and downhole equipment, such as a drilling tool, is deployed into the ground by a drill string to reach subsurface reservoirs. At the surface, an oil rig is provided to deploy stands of pipe into the wellbore to form the drill string. Various surface equipment, such as a top drive, a Kelly and a rotating table, may be used to apply torque to the stands of pipe and threadedly connect the stands of pipe together. A drill bit is mounted on the lower end of the drill string, and advanced into the earth from the surface to form a wellbore.

[0003] The drill string may be provided with various downhole components, such as a bottom hole assembly (BHA), measurement while drilling, logging while drilling, telemetry and other downhole tools, to perform various downhole operations, such as providing power to the drill bit to drill the wellbore and performing downhole measurements. During drilling or other downhole operations, the drill string and downhole components may encounter various downhole forces, such as downhole pressures (internal and/or external), torque on bit (TOB), weight on bit (WOB), etc. WOB refers to weight that is applied to the bit, for example, from the BHA and/or surface equipment. During drilling operations, portions of the drill string may be subject to tension, and portions of the BHA may be subject to compression.

[0004] Various downhole devices, such as stabilizers, have been provided along the drill string. Examples of downhole devices (or components) are provided in US Patent/ Application Nos. US2010/0089647, 4091883, 4064951, 4055226, 4610316, and 4000549 and GB Patent No. GB2355036. Despite advancements in downhole drilling, there remains a need for techniques to address downhole stresses (e.g., rotating, bending, etc.) and/or to facilitate drilling. SUMMARY

In at least one aspect, the disclosure relates to a drilling assembly of a drilling system having a drilling rig with a drill string deployable therefrom and drivable thereby. The drill string has a bottom hole assembly with a drill bit at a lower end thereof advanceable into a subterranean formation to form a wellbore. The drilling assembly includes at least one mandrel operatively connectable to the drill string, at least one sleeve positionable about the mandrel (the sleeve having an offset stabilizer on an outer surface thereof selectively positionable in contact with a wall of the wellbore), and an orienter comprising a receptacle on an interior of the sleeve and a socket on an exterior of the mandrel. The socket is interlockingly engageable with the receptacle whereby the sleeve is orientable about the drill string. The mandrel and the sleeve have a mass offset from the drill string whereby rotation of the drill string is affected during drilling.

The mandrel may include a plurality of mandrels threadedly connected together. The sleeve may be threadedly connectable to the mandrel. The sleeve may have threads at an inner surface thereof and at an end thereof mated with threads along an outer surface of the mandrel. The sleeve includes a modular sleeve having a plurality of sleeve portions. The sleeve may have a window therethrough. The orienter includes a polygonal interface. The orienter includes a splined interface comprising a plurality of splines.

The drilling assembly may also include a locking assembly. The locking assembly may include a pin extendable through a locking sleeve and into the mandrel. The locking assembly includes a washer positionable between a locking sleeve and the mandrel. The locking assembly may include a threaded locking sleeve. The mandrel includes a threaded connector connectable to the drill string. The sleeve may have an axis offset from an axis of the drill string. The sleeve may be orientable via the orienter to another sleeve, a reamer, a drill bit, and/or another drilling assembly.

In another aspect, the disclosure relates to a drilling system for drilling a wellbore into a subterranean formation. The drilling system includes a drill string deployable from a drilling rig and drivable thereby and at least one drilling assembly. The drill string has a bottom hole assembly and a drill bit at a lower end thereof. The drilling assembly includes at least one mandrel operatively connectable to the drill string, at least one sleeve positionable about the mandrel (the sleeve having an offset stabilizer on an outer surface thereof selectively positionable in contact with a wall of the wellbore), and an orienter comprising a receptacle on an interior of the sleeve and a socket on an exterior of the mandrel. The socket is interlockingly engageable with the receptacle whereby the sleeve is orientable about the drill string. The mandrel and the sleeve have a mass offset from the drill string whereby rotation of the drill string is affected during drilling.

The drilling assembly may include a plurality of drilling assemblies with at least one spacer therebetween. The drilling assembly may include at least one drilling assembly and at least one drilling component. The drilling component may include a reamer. The bottom hole assembly may include a driver. The drilling assembly may include a plurality of drilling assemblies alignable about the drill string. The drilling assembly may include a plurality of drilling assemblies oriented via the orienter. The drilling assembly may be oriented relative to another drilling assembly, a reamer, and/or a drill bit.

In yet another aspect, the disclosure relates to a method of assembling a downhole drilling tool for drilling a wellbore into a subterranean formation. The method involves operatively connecting at least one drilling assembly to a drill string having a bottom hole assembly and a drill bit at a lower end thereof. The at least one drilling assembly includes at least one mandrel operatively connectable to the drill string, at least one sleeve positionable about the at least one mandrel (the sleeve has an offset stabilizer on an outer surface thereof selectively positionable in contact with a wall of the wellbore), and an orienter comprising a receptacle on an interior of the sleeve and a socket on an exterior of the mandrel. The socket is interlockingly engageable with the receptacle whereby the sleeve is orientable about the drill string. The mandrel and the sleeve have a mass offset from the drill string whereby rotation of the drill string is affected during drilling. The method also involves orienting the at least one drilling assembly with the orienter.

The method may also involve encouraging forward synchronous whirl with the mass offset during rotation of the drill string. The operatively connecting may involve running a first portion of the drill string with the drill bit thereon into the wellbore, operatively connecting the mandrel to the first portion of the drill string, operatively connecting the sleeve about the mandrel, and operatively connecting a second portion of the drill string to the mandrel. The operatively connecting may also involve operatively connecting the mandrel to a downhole portion of the drill string (the mandrel having a plurality of mandrel splines on an outer surface thereof), positioning the sleeve about the mandrel (the sleeve having at least one radial extension on an outer surface thereof and a plurality of sleeve splines on an inner surface thereof, with the radial extension offset about an axis of the drill string), and orienting the sleeve about the drill string by engaging the plurality of sleeve splines with the plurality of mandrel splines. The method further involves connecting an uphole end of the drill string to the mandrel. The operatively connecting may also involve operatively connecting a plurality of the drilling assemblies in alignment along the drill string.

In yet another aspect, the disclosure relates to a method of drilling a wellbore into a subterranean formation. The method involves providing a drill string having a bottom hole assembly and a drill bit at a lower end thereof with at least one drilling assembly. The drilling assembly includes at least one mandrel operatively connectable to the drill string, at least one sleeve positionable about the mandrel (the sleeve having an offset stabilizer on an outer surface thereof, the offset stabilizer having a mass offset about an axis of the mandrel and selectively positionable in contact with a wall of the wellbore), and an orienter comprising a receptacle on an interior of the sleeve and a socket on an exterior of the mandrel. The socket is interlockingly engageable with the receptacle. The drilling assembly has a mass offset from the drill string whereby rotation of the drill string is affected during drilling. The method also involves orienting the drilling assembly with the orienter, and advancing the drilling assembly into the subterranean formation.

The method may also involve affecting whirl of the drill string by engaging a wall of the wellbore with the sleeve during the drilling, rotating the drill string at a speed sufficient to create a forward synchronous whirl, and/or offsetting an axis of the drilling assembly from an axis of the drill string such that whirl is affected during drilling.

Finally, in another aspect, the disclosure relates to a drilling assembly of a drilling system comprising a drilling rig with a drill string deployable therefrom and drivable thereby. The drill string has a bottom hole assembly with a drill bit at a lower end thereof advanceable into a subterranean formation to form a wellbore. The drilling assembly includes at least one mandrel operatively connectable to the drill string, and a removable sleeve positionable about the mandrel. The sleeve has an offset stabilizer on an outer surface thereof and is selectively positionable in contact with a wall of the wellbore. The mandrel and the removable sleeve have a mass offset from a mass of the drill string whereby forward synchronous whirl of the drill string is encouraged during drilling.

The removable sleeve may be reversibly positionable along the mandrel. The drilling assembly also includes an orienter for positioning the removable sleeve about the mandrel.

BRIEF DESCRIPTION OF THE DRAWINGS

[0005] So that the above recited features and advantages of the present disclosure can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof that are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate example embodiments and are, therefore, not to be considered limiting of its scope. The figures are not necessarily to scale and certain features, and certain views of the figures may be shown exaggerated in scale or in schematic in the interest of clarity and conciseness.

[0006] FIGS. 1A-1D depict schematic views, partially in cross-section, of a wellsite having a surface system and a downhole system for drilling a wellbore.

[0007] FIGS. 2A-2C depict assembly, perspective and partial cross-sectional views of a two- piece mandrel drilling assembly.

[0008] FIGS. 3A-3C depict assembly, perspective and partial cross-sectional views of another two-piece mandrel drilling assembly.

[0009] FIGS. 4A-4B depict partial cross-sectional and side views of a two piece drilling assembly.

[0010] FIG. 5 depicts a portion of the drilling assembly of Figure 3A depicting an orienter.

[0011] FIGS. 6A-6B depict partial cross-sectional views of a portion of a two piece drilling assembly.

[0012] FIGS. 7A-7B depict partial cross-sectional and side views, respectively, of a portion of a two piece drilling assembly.

[0013] FIGS. 8A-8B depict side and perspective views, respectively, of a splined drilling assembly having a one-piece mandrel.

[0014] FIGS. 9A-9B depict side and cross-sectional views, respectively, of the splined drilling assembly of Fig. 8A. [0015] FIGS. 10A-10E depict various views of a sleeve of a splined drilling assembly. FIGS.

10A-10B depict a unitary sleeve. FIGS. lOC-lOE depict a two piece sleeve.

[0016] FIGS. 1 lA-11C depict cross-sectional views of various locking assemblies for a drilling assembly.

[0017] FIG. 12 depicts a detailed view of a portion of the locking assembly of Figure 1 IB.

[0018] FIG. 13 is a perspective view of a washer.

[0019] FIGS. 14A-14B depict side and partial perspective views, respectively, of portions of another splined drilling assembly with the sleeve of FIG. IOC.

[0020] FIGS. 15A-15C depict a front, side and perspective views, respectively, of a dual drilling assembly.

[0021] FIG. 16 depicts a side view of multiple drilling assemblies.

[0022] FIG. 17 is a flow chart depicting a method of drilling a wellbore.

DETAILED DESCRIPTION OF THE INVENTION

[0023] The description that follows includes exemplary apparatuses, methods, techniques, and/or instruction sequences that embody techniques of the present subject matter. However, it is understood that the described embodiments may be practiced without these specific details.

[0024] The present disclosure relates to various drilling assemblies connectable to a drill string to facilitate drilling. The drilling assembly includes an offset (or protrusion), such as an offset sleeve or a dogleg mandrel, extending therefrom. The sleeve may be, for example, modular for replacement (e.g., due to wear), orientable for positioning about the drill string and contacting the wellbore wall, alignable with the bit, alignable with another offset drilling assembly and/or offset for weight distribution. The drilling assembly may be configured to affect bit whirl, offset, drill string whirl, and/or other drilling forces, such as torque, weight on bit, etc., that may be applied to drilling operations. The drilling assembly may be provided with an offset stabilizer shaped to provide contact with the wellbore wall and define a mass offset from the remainder of the drill string such that, during drilling, forward synchronous whirl of the BHA is encouraged to reduce effects of rotating bending fatigue, and to reduce large changes in stresses from tension to compression stresses.

[0025] Figures 1A-1D depict an example environment in which a drilling assembly may be used. While a land-based drilling rig with a specific configuration is depicted, the drilling assembly herein may be usable with a variety of land or offshore applications. A drilling system 100 includes a rig 101 positionable at a wellsite 102 for performing various wellbore operations, such as drilling. Figure 1A depicts a vertical cross- sectional view of the wellsite 102. The drilling system 100 also includes a downhole drilling tool including a drill string 103 with a bottom hole assembly (BHA) 108 and a drill bit 104 at an end thereof deployed from the rig 101. The drill string 103 may include drill pipe, drill collars, or other tubing used in drilling operations. The drill string may include combinations of standard drill pipe 115a, heavy weight drill pipe 115b and/or drill collars 117. The drill bit 104 is advanced into a subterranean formation 105 to form a wellbore 106. Various rig equipment 107, such as a Kelly, rotary table, top drive, elevator, etc., may be provided at the rig 101 to support and/or drive the drill string 103.

[0026] The bottomhole assembly (BHA) 108 is at a lower end of the drill string 103 and contains various equipment for performing downhole operations. Such equipment may include, for example, measurement while drilling, logging while drilling, telemetry, processors and/or other downhole tools. A driver, such as a downhole motor, 109 is also provided uphole of the bit 104 for rotationally driving the bit 104. In some applications and some configurations, the bit 104 may be, for example, a bi-center bit.

[0027] A mud pit 110 may be provided at the surface for passing mud through the drill string 103, the BHA 108 and out the bit 104 as indicated by the arrows. A surface controller 112 is also provided at the surface to operate the drilling system. As shown, the BHA 108 includes a downhole controller 112 for communication between the BHA 108 and the surface controller 112. One or more controllers 112 may be provided.

[0028] A drilling assembly 111 may also be coupled to the drill string 103. The drilling assembly 111 is positioned between an uphole portion 114 and a downhole portion 116 of the drill string 103. The drilling assembly 111 may be positioned, for example, adjacent or as part of the BHA 108. The drilling assembly 111 may include multiple drilling assemblies 11 la-c with one or more drill collars (or spacers) 117 therebetween as shown in the detailed view of Figure IB.

[0029] Figures IB-ID depict horizontal cross-sectional views of the wellsite 100 of Figure 1A taken along line 1-1. Figures IB- ID depict backward whirl, chaotic whirl and forward whirl of the drill string 103, respectively, that may occur during drilling. The drilling assembly 111 may be configured to manipulate whirl of the drill string 103 to affect rotation and stresses that apply thereto.

[0030] Figures 2A-2C depict a modular, drilling assembly 211. The modular configuration of the drilling assembly 211 may be assembled at the wellsite or pre-assembled for delivery.

Various sized components may be provided for various applications, for example, various diameter drilling assemblies may be provided for various hole sizes. Interchangeable components may be provided to allow replacement of parts as needed for repair, maintenance, wear, conformity to specific applications, etc. While a modular configuration is depicted, various portions of the drilling assembly 211 may be integral.

[0031] The drilling assembly 211 as shown includes a mandrel 216 and a sleeve 218. The sleeve 218 is depicted as a sleeve with an offset stabilizer in a tubular configuration positionable about the tubular mandrel 216. Example offset stabilizers are provided in US Patent Application No. 2010/0089647, the entire contents of which are hereby incorporated by reference herein.

[0032] The mandrel 216 includes an uphole portion 220 and a downhole portion 222. One or more portions of the mandrel 216 may be provided, and the mandrel 216 may be provided with standardized sizing for use at the wellbore. The uphole portion 220 has a box end 223 for connecting to the uphole portion 114 and the downhole portion 222 has a pin end 224 for connecting to the downhole portion 116 as shown in Figure 1A.

[0033] The uphole portion 220 is threadedly connectable to the sleeve 218. The upper portion 220 and the sleeve 218 are then threadedly connectable to the downhole portion 222. The drilling assembly 211 may be sealingly connected to prevent fluid from passing between an inside and outside thereof. The outer surface 225 of the uphole portion 220 and the outer surface 225 of the downhole portion 222 receivingly engage the sleeve 218. Shoulders 217, 219 are provided on the uphole portion 220 and the downhole portion 222, respectively, to support the sleeve therebetween when the uphole portion 220 and the downhole portion 222 are connected therein. Corresponding lips (not shown) may also be provided along an inner surface of the sleeve 218.

[0034] Connection means may be provided about the sleeve 218, the uphole portion 220 and the downhole portion 222 for securing the drilling assembly 211 together. As shown, the uphole portion 220 has a pin end 215a threadedly receivable by a box end 215b of downhole portion 222. The mandrel 216 and/or the sleeve 218 may be provided with various surfaces, threads or other portions for securing the components together. The downhole portion 222 may be rotationally advanced along the uphole threaded connection 230 between the uphole portion 220 and the sleeve 218. The downhole portion 222 and sleeve 218 may then be rotationally advanced onto downhole portion 222 along downhole threaded connection 227 until the shoulder 219 abuttingly engages a downhole end of the sleeve 218 thereby securing the sleeve 218 between the shoulders 217, 219.

[0035] The sleeve 218 has an offset stabilizer 226 with a slot (or trough) 237 therebetween. The sleeve 218 is positioned about the upper and lower portions 220, 222 of the mandrel 216, and defines dual lobes 229 along the offset stabilizer 226. A window 231 is positioned in the sleeve 218 to provide visual access into the drilling assembly 211. The window 231 extends through the sleeve 218 and to the mandrel 216. The window 231 may be used, for example, to see the position of portions of the uphole portion 220 and the downhole portion 222 of the mandrel 216 during makeup.

[0036] The sleeve 218 has an offset configuration, with the offset stabilizer (or protrusion or blade) 226 extending radially from one side thereof. The offset configuration may be sized and shaped to pass through portions of the wellbore, for example, where casing has a reduced diameter. The offset stabilizer 226 may optionally be provided with hardening, coating or other wear resistance 221 about an outer surface thereof.

[0037] The offset configuration also places a bulk of the mass of the sleeve 218 on one side of the drilling assembly 211. This offset can be positioned to affect rotation of the drill string during drilling and/or by offsetting the BHA with respect to the center of the wellbore. The offset stabilizer 226 defines a contact surface 228 for engaging a wall of the wellbore during drilling to affect rotation of the drill string during drilling. Such offset and contact with the wellbore wall can be used, for example, to provide forward synchronous whirl conditions. The offset stabilizer 226 may be offset to one side of the sleeve 218 such that the drill-string moves off center in the hole, rather than concentric as per conventional stabilizers. The mass of the offset drill string is rotated at a rate that may be used to generate forward synchronous whirl.

Figures 3A-5 depict another version of a modular, drilling assembly 211 '. This version is the same as the drilling assembly 211 of Figures 3A-3B, except that the mandrel 216' and sleeve 218' have been modified to provide a different connection 235' therebetween, and a modified uphole portion 220' and downhole portion 222' are provided with a different connection 233' therebetween. Also, a socket orienter 234 has been provided to position the sleeve 218' in a specific orientation about the mandrel 216'.

[0038] The mandrel 216' and/or the sleeve 218' may be provided with various surfaces, threads or other portions for securing the components together. The sleeve 218' may be sealingly connected to the mandrel 216' to prevent fluid from passing between an inside and outside thereof. Connection means may be provided along the uphole portion 220' and the downhole portion 222' for securing the sleeve 218' thereabout. As shown, the uphole portion of the mandrel 220' has a pin thread 215a' on the lower end which screws into a box thread 215b' of the downhole portion 222' in mandrel 216' .

[0039] The socket orienter 234 is shown in the detailed view of Figure 5. The socket orienter 234 provides a fixed radial position of the sleeve 218' about the mandrel 216'. Because the mandrel 216' is connected to the drill string 103 and the drill bit 104 of the drilling system 100 (see Fig. 1), the socket orienter 234 also fixes the radial position of the sleeve 218' relative to the drill string 103 and/or another drilling assembly. For example, an offset sleeve of a drilling assembly may be aligned to a sleeve of another drilling assembly or to a fixed one piece offset stabilizer located below the drilling assembly. The offset stabilizer 226 may be at a known position relative to the remainder of the drill string, thereby allowing for the offset stabilizer to be positioned for contact with the wellbore wall and/or for offsetting the weight of the drill string 103.

[0040] The socket orienter 234 provides a polygonal connection between the sleeve 218' and the downhole portion 222' of the mandrel 216'. A receptacle 238 of the sleeve 218' is provided with a polygonal shaped inner alignment surface to receive a corresponding polygonal socket 239 on an end of the downhole portion 222' having a polygonal shaped outer alignment surface. The polygonal shape is shown as a hexagonal shape, similar to a socket and wrench, but could be any shape to prevent rotation therebetween. The sleeve 218' is positionable on the downhole portion 222' to define the polygonal connection to fix orientation therebetween. The socket orienter 239 interlockingly engages receptacle 238 to secure the sleeve 218' in a desired position.

[0041] In cases, for example, where a bi-centered bit is used, the position of the sleeve 218' may be placed relative to the bit 104 (Fig. 1) to place the offset stabilizer in a desired position relative thereto. When used, for example, with a bi-center or other bit, the sleeve 218' may be positioned to place the offset stabilizer in alignment relative to the drill bit. Bi-centered bit applications may involve configurations where the motor 109 is not used.

[0042] As also shown in Figures 6A through 6B, an alternate threaded connection 230' is provided for securing the sleeve 218' to the mandrel 216' . The threaded connection 230' includes an uphole threaded connection 232' and an intermediate threaded connection 227'. The uphole portion 220' is threadedly connected to sleeve 216' by intermediate threaded connection 227'. The uphole portion 220' is also threadedly connected to the downhole portion 222' . The uphole threaded connection 232' provides a safety should the intermediate connection 227' fail. Upon such failure, the uphole and downhole portions 220', 222' will separate and the uphole portion 220' will slide up the sleeve 218' until the threads on a downhole end of the uphole portion 220' catch the threads 232' of the sleeve 218' . The sleeve 218' may then be retrieved.

[0043] Figures 7A and 7B depict an alternate threaded connection 230' ' for connecting mandrel 316" and sleeve 218". This threaded connection 230" includes a threaded ring 741 disposed about upper portion 220' ' of mandrel 216" . The ring 741 is threadedly connected to sleeve 218" . A shoulder 217" on the uphole portion 220" may abuttingly engage a lip 235" on ring 741. The uphole portion 220" may be threadedly connected to a downhole portion 222" of mandrel 216" as previously described. In this configuration, the uphole portion 220" is free to slide within the sleeve 216" with the ring 741 thereabout during makeup. During makeup, the ring 741 and the sleeve 216" are disposed about upper mandrel 220", the sleeve is slid onto the downhole portion 222", and the uphole and downhole portions are threaded together.

[0044] While Figures 2A-7B depicted specific configurations, other configurations may also be provided to connect an offset sleeve (e.g., 218, 218', 218") with a two piece mandrel (e.g., 216, 216', 216").

[0045] Figures 8A-9B depict various views of a modular, drilling assembly 811. This drilling assembly 811 includes a mandrel 816 and sleeve 818. The mandrel 816 includes an uphole portion 820, an intermediate portion 823 and a downhole portion 822 in a unitary (one piece) configuration. The sleeve 818 has an offset stabilizer 826 positionable about the mandrel 816.

[0046] Referring to Figures 8A-10B, the mandrel 816 and/or the sleeve 818 may be provided with various surfaces, threads or other portions for securing the components together. The sleeve 818 may be sealingly connected to the mandrel 816 to prevent fluid from passing through the gap between the mandrel 816 and the sleeve 818. Connection means, such as threads, may be provided along the uphole portion 820, the intermediate portion 823 and the downhole portion 822 for securing the sleeve 818 thereabout. The mandrel 816 may be provided with a pin end 825 and a box end 824 on opposite ends thereof for threaded connection with portions of the drill string 103.

[0047] The mandrel 816 has been provided with a stepped outer surface 825 for receiving the sleeve 818. A shoulder 837 extends from an outer surface of the downhole portion of the mandrel 816 for abutting engagement with the sleeve 818. A locking assembly 850 including a spacer 852 and a locking sleeve 854 positionable against the sleeve 818 is also provided for securing the sleeve 818 in position. The locking sleeve 854 is threadedly connected to mandrel 816 via a threaded connection 833 thereby securing the sleeve 818 in position.

[0048] Wear may occur about the mandrel 816 and sleeve 818 due to, for example, cuttings accumulation. The shoulder 837 is provided with wear resistance 821 to prevent wear about the sleeve 818 and the mandrel 816. Wear resistance may be provided about other portions of the drilling assembly as desired.

[0049] As shown in Figures 9A and 9B, the drilling assembly 811 is also provided with a splined orienter 834 to position the sleeve 818 in a specific orientation about the mandrel 816. The splined orienter 834 provides a fixed radial position of the sleeve 818 about the mandrel 816. Because the mandrel 816 is connected to the drill string 103 and the drill bit 104 of the drilling system 100 (see Fig. 1), the splined orienter 834 also fixes the radial position of the sleeve 818 relative to another component of the downhole assembly, such as another offset stabilizer of another drilling assembly. When sleeve 818 is positioned about mandrel 816, the offset stabilizer 826 may be at a known position relative to the remainder of the drill string, thereby allowing for the offset stabilizer to be positioned for contact with the wellbore wall and/or to align with another component (e.g., another offset stabilizer) along the drill string 103.

[0050] The splined orienter 834 is depicted as a splined connection 834 between the sleeve 818 and the intermediate portion 823 of the mandrel 816. The mandrel 816 is provided with mandrel splines (or fingers) 840 on an outer mandrel surface of the intermediate portion 823. The splines 840 engage the sleeve 818. The sleeve 818 may be positioned adjacent mandrel 816 (e.g., at shoulder 837) to locate the sleeve 818 axially along the mandrel 816. Figures 10A-10B depict the sleeve 818 in greater detail. The sleeve 818 is provided with a plurality of sleeve splines 842 on an inner surface thereof for receivingly engaging the mandrel 816 and a stabilizer 826 on an outer surface thereof. The sleeve splines 842 are interlockingly engageable with the mandrel splines 840 to secure the sleeve 818 in a desired position about mandrel 816.

[0051] The sleeve splines 842 may be provided on each end thereof such that the sleeve 818 is reversible (e.g., when worn on one side). The sleeve 818 may also have multiple sets of sleeve splines 842 spaced apart along an inner surface thereof. Relief grooves 849 may be provided at an inner end of the sleeve splines 842. Where the offset stabilizer experiences wear on local contact areas when run, forward synchronous whirl is generated during drilling operations, and wear may apply to one side. The sleeve 818 may be reversed to provide additional usage on the non-worn side of the sleeve 818.

[0052] A desired number of mandrel splines 840, sleeve splines 842 and spacing therebetween may be provided as desired. Additional mandrel splines 840 and/or sleeve splines 842 may be provided to increase the precision of alignment about the mandrel 816. The sleeve 818 is positionable on the intermediate portion 823 with the splined orienter 834 to fix orientation therebetween. The number of mandrel splines 840 corresponds to the number of sleeve splines 842, the number of which can be varied for increased or decreased orientational alignment. The mandrel splines 840 may be configured to enable the sleeve 818 to be incrementally orientable in a radial manner around an axis of the drill string. The mandrel splines 840 may be positioned, for example, at about twenty degree spacings, but finer or coarser splines may also be used. Where a second drilling assembly is provided (see, e.g., Fig. 1), the sleeve 818 may be aligned relative to the second drilling assembly. The mandrel splines 840 may be of any length, for example, 6 inches (15.24 cm) to about 7 inches (17.78 cm) long.

[0053] Figures lOC-lOE depict another sleeve 818' in a two piece configuration. Sleeve 818' is similar to sleeve 818, except that the sleeve 818' includes two portions 844, rather than a single body. One or more portions may be provided. Optionally, when a sleeve 818' is used (Figures lOC-lOE), the portions 844 of the sleeve 818' may be secured by threaded connectors 848 and pins 846, the connectors 848 may be tightened about the mandrel such that the portions 844 do not fully abut as they may be clamped tightly onto the spline on the mandrel 816 which may be used to stop the portions 844 from rotating around under drag torque coming from external contact with the wellbore wall.

[0054] As shown in Figures lOC-lOE, the sleeve portions 844 may have pins 846 for interlocking connection therebetween. The pins may be, for example, high tensile dowel pins located in holes in adjacent sleeve portions 844. Socket head cap screws or other connectors 848 may be provided for connecting the sleeve portions 844 together. Washers (e.g. tab lock washers or serrated washers (e.g., nord lock washers)) or adhesive may also be provided to secure the sleeve portions 844 in position. Sleeve 818' is depicted about the drilling assembly 1411 of Figures 14A and 14B as is described further herein.

[0055] Figures 1 lA-11C are cross-sectional views of drilling assembly 811. As shown in these figures, the sleeve 818 is positioned about the mandrel 816 and against shoulder 837 and secured in position by the locking assembly 850. As shown in Figure 11 A, the locking assembly 850 includes a lock spacer 852, a locking sleeve 854, a locking plug 856, and a dowel pin 858. The lock spacer 852 and the locking sleeve 854 are positionable about the mandrel 816 and adjacent the sleeve 818. The lock spacer may be abutted against the sleeve 818 and the locking sleeve 854 is threadedly connected to the mandrel 816. The locking assembly 850 provides a secondary locking mechanism to back-up the make-up torque on the sleeve 818 to ensure the sleeve 818 does not back-off more than a small amount (e.g., about 1/8 inch (2.10 cm) to about 1/4 inch (0.63 cm)). For example, if the threaded sleeve backed off and make up torque was lost due to vibration downhole, the sleeve 818 remains fully located on the splines 840 (Fig. 9A).

[0056] The mandrel 816 has an external parallel thread at the uphole end onto which the locking sleeve 854 screws which abuts the sleeve 818 and is torqued up to lock the sleeve 818 against the lower shoulder 837. The torque generates enough axial force to lock the sleeve 818 radially and also axially from moving about the mandrel 816. The splines 840 may be configured to take the full make-up torque and any drag torque the sleeve 818 may encounter during operation. The splines 840 and/or locking sleeve 854 may be configured individually or in combination to accept the drag torque. The splines 840 and locking sleeve 854 may be used to retain the sleeve 818 by the axial force from moving both radially and axially on the mandrel 816 and so the splines 840 will back up the locking sleeve 854 as a secondary torque drive device from the mandrel 816 to the sleeve 818.

[0057] The locking assembly 850 also provides a secondary locking system for securing the sleeve 818 in place. The sleeve 818 is locked by the splines 840 along the mandrel 816 (Figs. 8A-9B). The sleeve 818 may be installed from the uphole end of the mandrel 816 so that the sleeve 818 rests against the shoulder 837 on the mandrel 816. If the lock assembly 850 were to fail or come loose, the splines 840 may still be used to drive the sleeve 818 against the shoulder 837 to prevent the sleeve 818 from slipping downwards over the mandrel 816, and the sleeve 818 would remain recoverable out of the hole with the mandrel 816.

[0058] The locking sleeve 854 may be locked into position with another lock, such as locking plug 856 and pin 858 (e.g., a dowel pin) extending through the locking sleeve 854 and into the mandrel 816. Figure 12 shows a detailed view of the dowel pin 858. By way of example, three steel dowel pins may be held/located in a turned groove 857 on the outer surface of the mandrel 816 and prevented from falling out of their location holes with the 856 plugs. The plugs 856 may be, for example, national pipe thread (NPT) tapered thread plugs which may be provided with a threaded profile on the taper to prevent backing off. During makeup of the sleeve, a torque of, for example, about 43,843 ft lbs (59,443.13 Nm) may be applied to secure the lock assembly in position. The shear pins and plugs may be inserted into ports 890 and a torque of, for example, about 50 ft lbs (67.79 Nm) may be applied to retain the plugs in position. One or more dowel pins 858 may be positioned in one or more ports 890 about the drilling assembly.

[0059] The locking assembly 850 as shown in Figures 11A-12 includes a locking sleeve 854 threadedly connected to the mandrel 816 and abutting the sleeve 818 against shoulder 837 and the pin 858 and plug 856 therethrough, to retain the sleeve 818 about the mandrel 816 and to prevent the sleeve 818 from disengaging or becoming unthreaded. Additional locking sleeves, pins, plugs and other security features may be provided about the drilling assembly.

[0060] Figure 1 IB shows another locking assembly 850' that may be the same as the locking assembly 850, except that no spacer is provided, and the locking sleeve 854 is abutted directly against the sleeve 818 and threadedly connected to the mandrel 816. The locking assembly 850" of Figure 11C may be the same as the locking assembly 850, except that lock washer 859 (e.g., a serrated washer) may be provided between the sleeve 818, spacer 852, locking sleeve 854 and/or mandrel 816. Figure 13 shows a detailed view of an example washer 859. The washer 859 may be, for example, a serrated washer or other lock washer.

[0061] Other optional features include grease ports, lifting tappings, eye bolts and other devices to facilitate handling the sleeve 818 on the drill-floor. For example, a data recorder puck port 851 may be positioned in the sleeve 818 as shown in Figure 1 IB, but could also be positioned in the mandrel 816 (or another ring inserted between the sleeve 818 and the locking sleeve 850). Additional spacers may be used, for example, in smaller holes to take up the sleeve 818 length needed in larger holes. The spacer 852 may also contain the data recorder puck. In such cases, the spacer 852 may have a cross-sectional shape similar to that of the sleeve 818 to give a thick wall into which to locate the puck. The spacer 852 may be similar to the sleeve 818 and be aligned using a locking assembly (e.g., 850) about its ends. The puck may be located in various locations about the drilling assembly, such as in the sleeve 818 or a separate spacer 852 alongside the sleeve.

Figures 14A-14B depict yet another drilling assembly 1411. This version is the same as the drilling assembly 811, except that this version is provided with the modular sleeve 818' of Figure IOC having multiple portions 844 positioned between dual shoulders 1437 along the mandrel 1416. The sleeve 818' is positionable about mandrel 1416 with a small gap between the shoulders 1437 and connectable thereabout with, for example, the pins (e.g., dowel pins) and connectors (e.g., threaded screws) as previously described with respect to Figure IOC.

[0062] Figures 15A-15C depict a multi drilling assembly 1511 usable with a drilling system (e.g., 100 of Fig. 1). As shown in these figures the multi drilling assembly 1511 may have multiple drilling assemblies separated by spacers (or drill collars) 1517. The drilling assembly 1511 may be the same or different drilling assemblies. As shown, a conventional drilling assembly 1588 is at a downhole end and the drilling assembly 811 is at an uphole end of the multi drilling assembly 1511. In a given example, a one piece drilling assembly, such as the drilling assembly 811, may be connected along the drill string downhole from another drilling assembly, such as drilling assembly 1588. If a single drilling assembly is used, it may not be aligned to any other reference.

[0063] Figure 16 depicts a multi drilling assembly 1611 usable with a drilling system (e.g., 100 of Fig. 1). As shown in these figures the multi drilling assembly 1611 may have multiple drilling assemblies 811 separated by spacers (or drill collars) 1517. The drilling assembly 1611 includes one or more of the same or different drilling assemblies 811, with drill collars 1616. As also shown in Figure 16, one or more drilling assemblies may be operatively connected to a drill string component, such as the hole opener 1689. An example of a hole opener is depicted in US Patent Application No. 2010/0089647, previously incorporated by reference herein.

[0064] As also shown in Figure 16, the drilling assembly 1611 may have a dogleg

configuration. The dogleg configuration provides a nonlinear shape extending between uphole and downhole ends of the drilling assembly 1611. The dogleg configuration positions a portion of the drilling assembly 1611 along an offset axis X offset a distance D from and parallel to an axis Y of the under reamer 1689. As shown, the drilling assembly 1611 has a bent end 1686 connectable to reamer 1689 and an offset body 1688 extending therefrom. This dogleg configuration provides for a weight of the offset portion of the drilling assembly 1611 to the remainder of the drill string (e.g., the under reamer 1689 and other drill string components). The offset mass defined by the offset drilling assembly 1611 may be used to manipulate rotation and affect whirl or other movement as desired.

[0065] The drilling assemblies 811, 1588 may optionally be aligned. In some cases, the drilling assemblies may be misaligned, if desired. While only two drilling assemblies are shown with a given length of one or more spacers therebetween, any number of drilling assemblies and/or spacers may be used. The drilling assemblies may be spaced, for example, up to about 100 feet apart with a given alignment of each drilling assembly as desired. Where a 20 degree offset may be provided between the splines (or other orienter) of each of the drilling assemblies, for example, up to about a 10 degree offset may exist therebetween. During make up, a chalk line may be provided along the tools to facilitate orientation therebetween.

[0066] A drilling assembly may be aligned with at least one other drilling assembly to create forward synchronous whirl. The drilling assemblies may be configured and aligned to minimize rotating bending fatigue along the length of the drill string. The drilling assemblies may be offset to some degree and rotated with the correct speed to create forward synchronous whirl and/or to reduce the magnitude at bending stress level variations in areas of the offset drill string, for example, at threaded connections at ends of the drilling assemblies. By using two or more aligned drilling assemblies, a larger length BHA can be run under optimal running conditions for forward synchronous whirl.

[0067] The drilling assemblies provided herein may be used in a method for drilling a wellbore into a subterranean formation. Figure 17 depicts a method 1700 of drilling a wellbore into a subterranean formation. The method involves 1770 operatively connecting at least one drilling assembly to a drill string having a bottom hole assembly and a drill bit at a lower end thereof, the drilling assembly having at least one mandrel operatively connectable to the drill string, a sleeve positionable about the mandrel, and an orienter. The drilling assembly has a mass offset from the drillstring. The method also involves assembling the drilling assembly by 1772 running a first portion of the drill string with the drill bit thereon into the wellbore, 1774 operatively connecting the mandrel to the first portion of the drill string, 1776 positioning the sleeve about the mandrel(s), and 1778 operatively connecting a second portion of the drill string to the mandrel.

[0068] The method also involves 1780 orienting the offset stabilizer about the drill string. The orienting may involve, for example, orienting the offset stabilizer to a second offset stabilizer and/or drilling assembly connected to the BHA between the drill bit and the offset stabilizer. The uphole one of the offset stabilizers (and/or drilling assemblies) may be orientable, with a downhole one of the offset stabilizers assemblies connected thereto (that may or may not be orientable).

[0069] Where a locking assembly is provided, the method(s) may also involve operatively connecting a locking sleeve to the mandrel adjacent the sleeve, and positioning a pin

therethrough and a plug therein. The method(s) may also involve positioning a locking spacer about the mandrel. The drilling assembly may be pre-assembled or assembled at the wellsite. When more than one drilling assembly is used, the drilling assemblies may be assembled as the BHA is run into the hole to align the offset stabilizers of the drilling assemblies.

[0070] The method(s) may be performed in any order and repeated as desired.

[0071] It will be appreciated by those skilled in the art that the techniques disclosed herein can be implemented for automated/autonomous applications via software configured with algorithms to perform the desired functions. These aspects can be implemented by programming one or more suitable general-purpose computers having appropriate hardware. The programming may be accomplished through the use of one or more program storage devices readable by the processor(s) and encoding one or more programs of instructions executable by the computer for performing the operations described herein. The program storage device may take the form of, e.g., one or more floppy disks; a CD ROM or other optical disk; a read-only memory chip (ROM); and other forms of the kind well known in the art or subsequently developed. The program of instructions may be "object code," i.e., in binary form that is executable more-or-less directly by the computer; in "source code" that requires compilation or interpretation before execution; or in some intermediate form such as partially compiled code. The precise forms of the program storage device and of the encoding of instructions are immaterial here. Aspects of the invention may also be configured to perform the described functions (via appropriate hardware/software) solely on site and/or remotely controlled via an extended communication (e.g., wireless, internet, satellite, etc.) network. [0072] While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible. For example, one or more drilling assemblies may be provided with one or more features of the various drilling assemblies herein and connected about the drilling system.

[0073] Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.