U.S. patent application number 13/780358 was filed with the patent office on 2014-01-09 for downhole drilling force assembly and method of using same.
This patent application is currently assigned to NOV DOWNHOLE EURASIA LTD.. The applicant listed for this patent is NOV DOWNHOLE EURASIA LTD.. Invention is credited to Alan Martyn Eddison, Ian Heary, Guillaume Plessis, Rory McCrae Tulloch, Rick Young.
Application Number | 20140008127 13/780358 |
Document ID | / |
Family ID | 48521369 |
Filed Date | 2014-01-09 |
United States Patent
Application |
20140008127 |
Kind Code |
A1 |
Plessis; Guillaume ; et
al. |
January 9, 2014 |
DOWNHOLE DRILLING FORCE ASSEMBLY AND METHOD OF USING SAME
Abstract
A drilling assembly, drilling system and method is provided. The
drilling system includes 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 with 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 one mandrel
and the sleeve have a mass offset from the drill string whereby
rotation of the drill string is affected during drilling.
Inventors: |
Plessis; Guillaume;
(Singapore, SG) ; Tulloch; Rory McCrae; (Aberdeen,
GB) ; Heary; Ian; (Dundee, GB) ; Young;
Rick; (Lafayette, LA) ; Eddison; Alan Martyn;
(York, GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
NOV DOWNHOLE EURASIA LTD. |
Stonehouse |
|
GB |
|
|
Assignee: |
NOV DOWNHOLE EURASIA LTD.
Stonehouse
GB
|
Family ID: |
48521369 |
Appl. No.: |
13/780358 |
Filed: |
February 28, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61668769 |
Jul 6, 2012 |
|
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Current U.S.
Class: |
175/55 |
Current CPC
Class: |
E21B 7/06 20130101; E21B
17/1078 20130101; E21B 17/046 20130101 |
Class at
Publication: |
175/55 |
International
Class: |
E21B 7/06 20060101
E21B007/06 |
Claims
1. A drilling assembly of a drilling system comprising a drilling
rig with a drill string deployable therefrom and drivable thereby,
the drill string having 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 comprising: at least one
mandrel operatively connectable to the drill string; at least one
sleeve positionable about the at least one mandrel, the at least
one 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 at
least one sleeve and a socket on an exterior of the at least one
mandrel, the socket interlockingly engageable with the receptacle
whereby the at least one sleeve is orientable about the drill
string; wherein the at least one mandrel and the at least one
sleeve have a mass offset from the drill string whereby rotation of
the drill string is affected during drilling.
2. The drilling assembly of claim 1, wherein the at least one
mandrel comprises a plurality of mandrels threadedly connected
together.
3. The drilling assembly of claim 1, wherein the at least one
sleeve is threadedly connectable to the at least one mandrel.
4. The drilling assembly of claim 1, wherein the at least one
sleeve has threads at an inner surface thereof at an end thereof
mated with threads along the outer surface of the at least one
mandrel.
5. The drilling assembly of claim 1, wherein the at least one
sleeve comprises a modular sleeve having a plurality of sleeve
portions.
6. The drilling assembly of claim 1, wherein the at least one
sleeve has a window therethrough.
7. The drilling assembly of claim 1, wherein the orienter comprises
a polygonal interface.
8. The drilling assembly of claim 1, wherein the orienter comprises
a splined interface comprising a plurality of splines.
9. The drilling assembly of claim 1, further comprising a locking
assembly.
10. The drilling assembly of claim 9, wherein the locking assembly
comprises a pin extendable through the locking sleeve and into the
at least one mandrel.
11. The drilling assembly of claim 9, wherein the locking assembly
comprises a washer positionable between a locking sleeve and the at
least one mandrel.
12. The drilling assembly of claim 9, wherein the locking assembly
comprises a threaded locking sleeve.
13. The drilling assembly of claim 1, wherein the at least one
mandrel comprises a threaded connector connectable to the drill
string.
14. The drilling assembly of claim 1, wherein the at least one
sleeve has an axis offset from an axis of the drill string.
15. The drilling assembly of claim 1, wherein the at least one
sleeve is orientable via the orienter to one of another sleeve, a
reamer, the drill bit, another drilling assembly, and combinations
thereof.
16. A drilling system for drilling a wellbore into a subterranean
formation, the drilling system comprising: a drill string
deployable from a drilling rig and drivable thereby, the drill
string having a bottom hole assembly and a drill bit at a lower end
thereof; at least one drilling assembly, comprising: at least one
mandrel operatively connectable to the drill string; at least one
sleeve positionable about the at least one mandrel, the at least
one 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 at
least one sleeve and a socket on an exterior of the at least one
mandrel, the socket interlockingly engageable with the receptacle
whereby the at least one sleeve is orientable about the drill
string; wherein the at least one mandrel and the at least one
sleeve have a mass offset from the drill string whereby rotation of
the drill string is affected during drilling.
17. The drilling system of claim 16, wherein the at least one
drilling assembly comprises a plurality of drilling assemblies with
at least one spacer therebetween.
18. The drilling system of claim 16, wherein the at least one
drilling assembly comprises at least one drilling assembly and at
least one drilling component.
19. The drilling system of claim 16, wherein the at least one
drilling component comprises a reamer.
20. The drilling system of claim 16, wherein the bottom hole
assembly comprises a driver.
21. The drilling assembly of claim 16, wherein the at least one
drilling assembly comprises a plurality of drilling assemblies
alignable about the drill string.
22. The drilling system of claim 16, wherein the at least one
drilling assembly comprises a plurality of drilling assemblies
oriented via the orienter.
23. The drilling assembly of claim 16, wherein the at least one
drilling assembly is oriented relative to one of another at least
one drilling assembly, a reamer, a drill bit, and combinations
thereof.
24. A method of assembling a downhole drilling tool for drilling a
wellbore into a subterranean formation, the method comprising:
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 comprising: at least
one mandrel operatively connectable to the drill string; at least
one sleeve positionable about the at least one mandrel, the at
least one 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 at least one sleeve and a socket on an exterior of the at least
one mandrel, the socket interlockingly engageable with the
receptacle whereby the at least one sleeve is orientable about the
drill string; wherein the at least one mandrel and the at least one
sleeve have a mass offset from the drill string whereby rotation of
the drill string is affected during drilling; and orienting the at
least one drilling assembly with the orienter.
25. The method of claim 24, further comprising encouraging forward
synchronous whirl with the mass offset during rotation of the drill
string.
26. The method of claim 24, wherein the operatively connecting
comprises: running a first portion of the drill string with the
drill bit thereon into the wellbore; operatively connecting the at
least one mandrel to the first portion of the drill string;
operatively connecting the at least one sleeve about the at least
one mandrel; and operatively connecting a second portion of the
drill string to the at least one mandrel.
27. The method of claim 24, wherein the operatively connecting
comprises: operatively connecting the at least one mandrel to a
downhole portion of the drill string, the at least one mandrel
having a plurality of mandrel splines on an outer surface thereof;
positioning the at least one sleeve about the at least one mandrel,
the at least one sleeve having at least one radial extension on an
outer surface thereof and a plurality of sleeve splines on an inner
surface thereof, the at least one radial extension offset about an
axis of the drill string; orienting the at least one sleeve about
the drill string by engaging the plurality of sleeve splines with
the plurality of mandrel splines; and connecting an uphole end of
the drill string to the at least one mandrel.
28. The method of claim 24, wherein the operatively connecting
comprises operatively connecting a plurality of the at least one
drilling assemblies in alignment along the drill string.
29. A method of drilling a wellbore into a subterranean formation,
the method comprising: providing a drill string having a bottom
hole assembly and a drill bit at a lower end thereof with at least
one drilling assembly comprising: at least one mandrel operatively
connectable to the drill string; at least one sleeve positionable
about the at least one mandrel, the at least one sleeve having an
offset stabilizer on an outer surface thereof, the offset
stabilizer having a mass offset about an axis of the at least one
mandrel and selectively positionable in contact with a wall of the
wellbore; and an orienter comprising a receptacle on an interior of
the at least one sleeve and a socket on an exterior of the at least
one mandrel, the socket interlockingly engageable with the
receptacle; wherein the at least one drilling assembly has a mass
offset from the drill string whereby rotation of the drill string
is affected during drilling; and orienting the at least one
drilling assembly with the orienter; and advancing the at least one
drilling assembly into the subterranean formation.
30. The method of claim 29, further comprising affecting whirl of
the drill string by engaging a wall of the wellbore with the at
least one sleeve during the drilling.
31. The method of claim 29, further comprising rotating the drill
string at a speed sufficient to create a forward synchronous
whirl.
32. The method of claim 29, further comprising offsetting an axis
of the at least one drilling assembly from an axis of the drill
string such that whirl is affected during drilling.
33. A drilling assembly of a drilling system comprising a drilling
rig with a drill string deployable therefrom and drivable thereby,
the drill string having 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 comprising: at least one
mandrel operatively connectable to the drill string; and a
removable sleeve positionable about the at least one mandrel, the
at least one sleeve having an offset stabilizer on an outer surface
thereof, the at least one sleeve being selectively positionable in
contact with a wall of the wellbore; wherein the at least one
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.
34. The drilling assembly of claim 33, wherein the removable sleeve
is reversibly positionable along the at least one mandrel.
35. The drilling assembly of claim 33, further comprising an
orienter for positioning the removable sleeve about the at least
one mandrel.
Description
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 U.S. patent/Application Nos.
US2010/0089647, U.S. Pat. Nos. 4,091,883, 4,064,951, 4,055,226,
4,610,316, and 4,000,549 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
[0005] 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.
[0006] 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.
[0007] 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.
[0008] 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.
[0009] 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.
[0010] 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.
[0011] 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.
[0012] 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.
[0013] 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.
[0014] 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.
[0015] 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
[0016] 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.
[0017] 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.
[0018] FIGS. 2A-2C depict assembly, perspective and partial
cross-sectional views of a two-piece mandrel drilling assembly.
[0019] FIGS. 3A-3C depict assembly, perspective and partial
cross-sectional views of another two-piece mandrel drilling
assembly.
[0020] FIGS. 4A-4B depict partial cross-sectional and side views of
a two piece drilling assembly.
[0021] FIG. 5 depicts a portion of the drilling assembly of FIG. 3A
depicting an orienter.
[0022] FIGS. 6A-6B depict partial cross-sectional views of a
portion of a two piece drilling assembly.
[0023] FIGS. 7A-7B depict partial cross-sectional and side views,
respectively, of a portion of a two piece drilling assembly.
[0024] FIGS. 8A-8B depict side and perspective views, respectively,
of a splined drilling assembly having a one-piece mandrel.
[0025] FIGS. 9A-9B depict side and cross-sectional views,
respectively, of the splined drilling assembly of FIG. 8A.
[0026] FIGS. 10A-10E depict various views of a sleeve of a splined
drilling assembly. FIGS. 10A-10B depict a unitary sleeve. FIGS.
10C-10E depict a two piece sleeve.
[0027] FIGS. 11A-11C depict cross-sectional views of various
locking assemblies for a drilling assembly.
[0028] FIG. 12 depicts a detailed view of a portion of the locking
assembly of FIG. 11B.
[0029] FIG. 13 is a perspective view of a washer.
[0030] FIGS. 14A-14B depict side and partial perspective views,
respectively, of portions of another splined drilling assembly with
the sleeve of FIG. 10C.
[0031] FIGS. 15A-15C depict a front, side and perspective views,
respectively, of a dual drilling assembly.
[0032] FIG. 16 depicts a side view of multiple drilling
assemblies.
[0033] FIG. 17 is a flow chart depicting a method of drilling a
wellbore.
DETAILED DESCRIPTION OF THE INVENTION
[0034] 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.
[0035] 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.
[0036] FIGS. 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.
FIG. 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.
[0037] 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.
[0038] 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.
[0039] 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 111a-c with one or more drill
collars (or spacers) 117 therebetween as shown in the detailed view
of FIG. 1B.
[0040] FIGS. 1B-1D depict horizontal cross-sectional views of the
wellsite 100 of FIG. 1A taken along line 1-1. FIGS. 1B-1D 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.
[0041] FIGS. 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.
[0042] 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.
[0043] 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 FIG. 1A.
[0044] 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.
[0045] 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.
[0046] 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.
[0047] 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.
[0048] 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.
[0049] FIGS. 3A-5 depict another version of a modular, drilling
assembly 211'. This version is the same as the drilling assembly
211 of FIGS. 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'.
[0050] 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'.
[0051] The socket orienter 234 is shown in the detailed view of
FIG. 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.
[0052] 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.
[0053] 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.
[0054] As also shown in FIGS. 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.
[0055] FIGS. 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.
[0056] While FIGS. 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'').
[0057] FIGS. 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.
[0058] Referring to FIGS. 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.
[0059] 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.
[0060] 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.
[0061] As shown in FIGS. 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.
[0062] 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. FIGS. 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.
[0063] 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.
[0064] 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.
[0065] FIGS. 10C-10E 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 (FIGS. 10C-10E), 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.
[0066] As shown in FIGS. 10C-10E, 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 FIGS. 14A and 14B as is described further
herein.
[0067] FIGS. 11A-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 FIG. 11A, 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).
[0068] 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.
[0069] 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.
[0070] 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. FIG. 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.
[0071] The locking assembly 850 as shown in FIGS. 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.
[0072] FIG. 11B 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 FIG. 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. FIG. 13 shows a detailed view of an example
washer 859. The washer 859 may be, for example, a serrated washer
or other lock washer.
[0073] 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 FIG. 11B,
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.
[0074] FIGS. 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 FIG. 10C
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 FIG. 10C.
[0075] FIGS. 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.
[0076] FIG. 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 FIG. 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.
[0077] As also shown in FIG. 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.
[0078] 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.
[0079] 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.
[0080] The drilling assemblies provided herein may be used in a
method for drilling a wellbore into a subterranean formation. FIG.
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.
[0081] 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).
[0082] 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.
[0083] The method(s) may be performed in any order and repeated as
desired.
[0084] 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.
[0085] 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.
[0086] 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.
* * * * *