U.S. patent application number 14/663419 was filed with the patent office on 2015-10-01 for system and methodology for use in borehole applications.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Torbjoern Aksnes, Carlos Javier Delgado, Are Funderud, Edward Richards, Martin Sanderson, Stuart David Dixon Walker.
Application Number | 20150275589 14/663419 |
Document ID | / |
Family ID | 54189582 |
Filed Date | 2015-10-01 |
United States Patent
Application |
20150275589 |
Kind Code |
A1 |
Walker; Stuart David Dixon ;
et al. |
October 1, 2015 |
System and Methodology for Use In Borehole Applications
Abstract
A technique facilitates the dependable, long-lasting use of a
downhole component coupled into a drill string. In some
applications, the downhole component comprises a stabilizer having
a plurality of blades extending outwardly from a body, e.g. sleeve.
Various features of the downhole component enhance the usefulness
and dependability of the downhole component. Examples of such
features comprise uniquely shaped surfaces; materials with a
desired hardness, toughness, and impact strength; and/or wear
protection elements incorporated into the downhole component.
Inventors: |
Walker; Stuart David Dixon;
(Bristol, GB) ; Richards; Edward; (Warwickshire,
GB) ; Funderud; Are; (Trondheim, NO) ;
Sanderson; Martin; (Ruwi, OM) ; Delgado; Carlos
Javier; (Trondheim, NO) ; Aksnes; Torbjoern;
(Stadsbygd, NO) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar land |
TX |
US |
|
|
Family ID: |
54189582 |
Appl. No.: |
14/663419 |
Filed: |
March 19, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61970864 |
Mar 26, 2014 |
|
|
|
62036572 |
Aug 12, 2014 |
|
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|
Current U.S.
Class: |
175/40 ;
166/242.1; 166/330; 166/380; 175/323 |
Current CPC
Class: |
E21B 34/06 20130101;
E21B 41/0085 20130101; E21B 17/1085 20130101; E21B 17/1078
20130101 |
International
Class: |
E21B 17/10 20060101
E21B017/10; E21B 34/06 20060101 E21B034/06; E21B 3/00 20060101
E21B003/00 |
Claims
1. A system for stabilizing a drilling string, comprising: a drill
string having a collar and a stabilizer mounted on the collar, the
stabilizer comprising: a body having an interior surface and an
exterior surface; and a plurality of blades extending outwardly
from the exterior surface of the body, the plurality of blades
being separated by flow channels, the plurality of blades
establishing a leading face and a trailing face, at least one of
the leading face and the trailing face having a shallow slope of
45.degree. or less relative to the exterior surface.
2. The system as recited in claim 1, wherein the body has the
structure of a sleeve, the sleeve being formed of a material
comprising a tungsten carbide matrix, a plurality of wear
protection elements being mounted on the sleeve.
3. The system as recited in claim 1, wherein the trailing face has
the shallow slope and the leading face has a relatively steeper
slope.
4. The system as recited in claim 1, wherein both the trailing face
and the leading face have the shallow slope.
5. The system as recited in claim 1, wherein the shallow slope is
less than 30.degree..
6. The system as recited in claim 1, wherein the interior surface
comprises an internal profile which abuts against a corresponding
shoulder of the collar when the stabilizer is mounted on the
collar.
7. The system as recited in claim 2, wherein the plurality of wear
protection elements comprises polycrystalline diamond compacts.
8. The system as recited in claim 2, wherein the plurality of wear
protection elements comprises thermally stable polycrystalline
components.
9. The system as recited in claim 3, wherein the shallow slope is
no greater than 45.degree. and the relatively steeper slope is no
less than 70.degree..
10. A system, comprising: a downhole component deployed in a drill
string; a sleeve coupled to the downhole component and formed of a
material comprising a tungsten carbide matrix, the sleeve employing
a plurality of wear protection elements.
11. The system as recited in claim 10, wherein the plurality of
wear protection elements comprises polycrystalline diamond compacts
mounted on the sleeve.
12. The system as recited in claim 10, wherein the plurality of
wear protection elements comprises thermally stable polycrystalline
components mounted on the sleeve.
13. The system as recited in claim 10, wherein the downhole
component comprises a stabilizer.
14. The system as recited in claim 10, wherein the downhole
component comprises a measurement-while-drilling tool.
15. The system as recited in claim 10, wherein the downhole
component comprises a logging-while-drilling tool.
16. The system as recited in claim 10, wherein the downhole
component comprises an impeller.
17. The system as recited in claim 10, wherein the downhole
component comprises a rotary valve.
18. A method of drilling a wellbore, comprising: providing a
stabilizer having: a body with an interior surface and an exterior
surface, and a plurality of blades extending outwardly from the
exterior surface of the body; forming the blades to establish a
leading face and a trailing face with at least one of the leading
face and the trailing face having a shallow slope relative to the
exterior surface; and mounting the stabilizer on a drill string
collar of a drill string.
19. The method as recited in claim 18, wherein providing comprises
forming the body with a sleeve constructed of a material comprising
a tungsten carbide matrix, a plurality of wear protection elements
being mounted on the sleeve.
20. The method as recited in claim 19, wherein providing comprises
forming the plurality of wear protection elements as
polycrystalline diamond compacts.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present document is based on and claims priority to U.S.
Provisional Application Ser. No.: 61/970864, filed Mar. 26, 2014,
and U.S. Provisional Application Ser. No.: 62/036572, filed Aug.
12, 2014, which are incorporated herein by reference in their
entirety.
BACKGROUND
[0002] In many hydrocarbon well applications, wellbores are drilled
into a desired hydrocarbon-bearing formation via a variety of
drilling systems. For example, drilling operations may be performed
with drill strings including a variety of bottom hole assemblies
constructed to drill a desired wellbore. In some applications,
rotary steerable drilling systems may be used to control the
trajectory of the wellbore being drilled. This facilitates the
drilling of deviated, e.g. horizontal, wellbores. During drilling,
stabilizers and other drilling components of the bottom hole
assembly may be subjected to substantial abrasion. This abrasion
can be detrimental to the life of the stabilizer or other bottom
hole assembly components. Depending on the application, stabilizers
may be used with steerable drilling systems to provide contact
points with the wellbore wall to facilitate steering. Additionally,
stabilizers known as string stabilizers may be used farther up the
bottom hole assembly of the drill string to support tools, to
reduce shock and vibration, and to reduce stick-slip.
SUMMARY
[0003] In general, a system and methodology are provided to
facilitate the dependable, long-lasting use of a downhole component
coupled into a drill string. In some embodiments, the downhole
component may comprise a stabilizer having a plurality of blades
extending outwardly from a body, e.g. sleeve. Various features of
the downhole component enhance the usefulness and dependability of
the downhole component. Examples of such features comprise uniquely
shaped surfaces; materials with a desired hardness, toughness, and
impact strength; and/or wear protection elements incorporated into
the downhole component.
[0004] However, many modifications are possible without materially
departing from the teachings of this disclosure. Accordingly, such
modifications are intended to be included within the scope of this
disclosure as defined in the claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] Certain embodiments of the disclosure will hereafter be
described with reference to the accompanying drawings, wherein like
reference numerals denote like elements. It should be understood,
however, that the accompanying figures illustrate the various
implementations described herein and are not meant to limit the
scope of various technologies described herein, and:
[0006] FIG. 1 is a side view of an example of a stabilizer, e.g. an
abrasion resistant stabilizer, mounted in a drill string, according
to an embodiment of the disclosure;
[0007] FIG. 2 is a cross-sectional view of an example of a
stabilizer to illustrate mounting of the stabilizer on a collar of
a drill string, according to an embodiment of the disclosure;
[0008] FIG. 3 is a side view of another example of a stabilizer,
according to an embodiment of the disclosure;
[0009] FIG. 4 is a graphical representation illustrating plots of
pull force versus taper angle for varying hole inclinations,
according to an embodiment of the disclosure;
[0010] FIG. 5 is a side view of another example of a stabilizer,
according to an embodiment of the disclosure;
[0011] FIG. 6 is an orthogonal view of an abrasion resistant sleeve
which may be used with a variety of downhole components, including
stabilizers, according to an embodiment of the disclosure;
[0012] FIG. 7 is an illustration of a drill string having a
plurality of downhole components protected with abrasion resistant
sleeves and/or other abrasion resistant features, according to an
embodiment of the disclosure;
[0013] FIG. 8 is an illustration of another example of an abrasion
resistant component in the form of a rotary valve system, according
to an embodiment of the disclosure; and
[0014] FIG. 9 is an illustration of another example of an abrasion
resistant component in the form of an impeller which may be used in
a variety of downhole components, according to an embodiment of the
disclosure.
DETAILED DESCRIPTION
[0015] In the following description, numerous details are set forth
to provide an understanding of some embodiments of the present
disclosure. However, it will be understood by those of ordinary
skill in the art that the system and/or methodology may be
practiced without these details and that numerous variations or
modifications from the described embodiments may be possible.
[0016] With respect to certain embodiments of the present
disclosure, a system and methodology are described for facilitating
a drilling operation which employs a stabilizer or stabilizers on a
drill string. The stabilizer (or stabilizers) comprises an end face
or end faces having shallower slopes instead of steep slopes. Steep
slopes can sometimes cause the bottom hole assembly to get stuck on
a ledge or other obstruction along the wellbore. In some
applications, shallower slopes may be employed on both leading and
trailing faces. In other applications, a shallower slope may be
employed on one of the faces. For example, the shallower slope may
be located on a trailing face of the stabilizer to reduce the risk
of hanging-up the bottom hole assembly on a ledge or other
obstruction while tripping out of the hole. It should be noted the
shallower slopes and/or the relatively shallower slope on the
trailing face may be employed on a variety of parts, components or
entire tools.
[0017] In some applications, the stabilizer may be constructed with
a shallow sloped trailing face and a leading face having a steeper
slope. The steeper leading face moves the crown (contact point) of
the stabilizer forward toward the drill bit. By moving the crown of
the stabilizer toward the drill bit, the dogleg capability of the
drilling system may be substantially increased.
[0018] Referring generally to FIG. 1, an example of a downhole
component 10 in the form of a stabilizer mounted in a drilling
system 12 is illustrated. However, downhole component 10 may
comprise a variety of parts, components or entire tools. In this
embodiment, drilling system 12 comprises a drill string 14 having a
drill string collar 16 and a drill bit 18. The stabilizer 10 is
mounted on drill string collar 16 and comprises a body 20, e.g. a
tubular body, having an interior surface 22 and an exterior surface
24. The interior surface 22 faces inwardly toward the drill string
collar 16 and the exterior surface 24 faces in a radially outward
direction. The stabilizer 10 further comprises a plurality of
blades 26 which extend outwardly from exterior surface 24. The
blades 26 extend along at least a portion of the longitudinal
length of body 20 and are separated circumferentially by flow
channels 28. In some applications, the blades 26 are arranged
helically and thus provide generally helical flow channels 28
therebetween. The flow channels 28 allow flows of fluid to move
longitudinally past the stabilizer 10 along drill string 14.
[0019] The longitudinal ends of blades 26 establish a leading face
30 and a trailing face 32. Generally, the leading face 30 is on the
downhole end toward drill bit 18 and the trailing face 32 is on the
uphole end of blades 26. The leading face 30 is oriented at a
leading end angle 34 with respect to exterior surface 24, and
trailing face 32 is oriented at a trailing end angle 36 with
respect to exterior surface 24. Depending on the application, the
leading face 30 and/or trailing face 32 may have a shallow slope in
the form of a relatively small leading end angle 34 and/or trailing
end angle 36, respectively. In the embodiment illustrated in FIG.
1, the leading face 30 has a relatively steep taper, e.g. a leading
end angle 34 of 70.degree. or greater. In this embodiment, the
trailing face 32 has a shallow taper, e.g. a trailing end angle 36
of 45.degree. or less. In some applications, the shallow taper may
comprise a trailing end angle 36 of 30.degree. or less.
[0020] As illustrated, some embodiments may utilize a substantially
shallower taper on the trailing face 32 relative to a steeper taper
on the leading face 30. Additionally, the leading face 30 and/or
trailing face 32 may be constructed with the leading end angle 34
and the trailing end angle 36, respectively, formed as compound
angles. In other words, one or both of the leading end angle 34
and/or trailing end angle 36 may be formed with a plurality of
differently angled slopes.
[0021] The stabilizer 10 may be mounted on drill string collar 16
of drilling system 12 via a variety of structures and techniques.
An example of such a structure and technique is illustrated in FIG.
2. In this embodiment, the interior surface 22 has an internal
diameter profile 38, e.g. an abutment, located to facilitate
construction of a lengthened stabilizer body 20. The profile 38 is
oriented for engagement with a shoulder 40 of drill string collar
16. Additionally, the stabilizer 10 may be threadably engaged with
and tightened against shoulder 40 via a threaded region 42 on
collar 16 and a corresponding threaded region 44 along the interior
of body 20. In this example, the drill string collar also may
comprise a bit box 46 for engagement with drill bit 18. The overall
arrangement facilitates construction of a longer stabilizer 10 to
accommodate the longer, shallower slopes of the face or faces 30,
32. For example, profile 38 acts against the collar shoulder 40 at
an internal location which allows the stabilizer to be lengthened
by enabling the blades 26 to extend over this internal
location.
[0022] Referring generally to FIG. 3, another embodiment of the
stabilizer 10 is illustrated. In this embodiment, the leading face
30 and the trailing face 32 of blades 26 both have a relatively
shallow slope. In other words, the leading end angle 34 and the
trailing end angle 36 are relatively small. For example, the
shallow slope of the leading face 30 and the trailing face 32 may
have leading end angle 34 and trailing end angle 36, respectively,
of 45.degree. or less. In some applications, the shallow taper may
comprise both a leading end angle 34 and a trailing end angle 36 of
30.degree. or less. In some applications, a shallower taper on the
leading face 30 can limit steerability and dogleg capability. To
increase dogleg capability, the slope taper at the leading face 30
may be steeper and the slope taper at the trailing face 32 may be
relatively shallower.
[0023] As illustrated by the graph of FIG. 4, the face taper angle
has an effect on the force applied to the drill string, e.g. the
pull force, to overcome friction associated with an obstruction,
e.g. a ledge. FIG. 4 illustrates examples of pull force used to
overcome friction for a variety of borehole inclinations and face
taper angles. As illustrated, the pull force used to move
stabilizer 10 past the obstruction decreases as the face taper
angle decreases. FIG. 4 provides a graphical overview of this
relationship for a variety of wellbore types.
[0024] Referring generally to FIG. 5, another embodiment of the
stabilizer 10 is illustrated. In this embodiment, cutting features
48 are added along the slopes, e.g. the shallow slopes, of leading
face 30 and/or trailing face 32. The cutting features 48 may
comprise cutters, such as polycrystalline diamond (PDC) cutters,
formed of hard material and positioned along the sloped faces 30
and/or 32. The cutting features may be oriented to cut away
obstructions, such as ledges resulting from washouts, encountered
along the wellbore. In some applications, the cutting features may
be applied to a non-magnetic stainless steel substrate.
[0025] According to other and/or additional aspects of the present
disclosure, various downhole components 10, e.g. stabilizers, other
components, or entire tools, may be constructed in a manner
providing resistance to abrasion in well related applications and
non-well related applications. For example, the technique may
provide increased abrasion resistance in a downhole component
deployed in a drilling bottom hole assembly. In some applications,
a sleeve is mounted to or constructed as part of the downhole
component. The sleeve is formed of materials having suitable
hardness, toughness and impact strength, such as materials
comprising a tungsten carbide matrix. By way of example, the
tungsten carbide matrix may comprise tungsten carbide particles in
a suitable matrix, e.g. cobalt, and processed according to
appropriate powder metallurgy techniques to form a metal matrix
composite referred to herein as tungsten carbide matrix. In some
applications, the sleeve may be formed primarily of tungsten
carbide matrix.
[0026] In other applications, the sleeve may be formed of a
suitable composite material with portions comprising the tungsten
carbide mixture. By way of example, the portions of hard tungsten
carbide mixture may be bonded to steel or to another material
having suitable toughness and impact strength. However, various
other materials and material combinations may be used to form the
sleeve. The composition of the tungsten carbide matrix also may be
adjusted to accommodate various loading effects, thermal effects,
and/or other effects likely to be experienced by the sleeve in a
given application. The sleeve also may employ a plurality of wear
protection elements. Depending on the application, the wear
protection elements may be used with or incorporated into a variety
of other components. It should be noted the suitable composite
material and the plurality of wear protection elements may be used
in a variety of parts, components or entire tools.
[0027] In some embodiments, the abrasion resistant components
facilitate drilling operations and may be in the form of a
stabilizer (or stabilizers) having an abrasion resistant sleeve.
One or more of the stabilizers may be employed at various positions
along a drill string and in combination with various types of drill
string components, such as bottom hole assembly components. In
addition to their usefulness in stabilizers, the abrasion resistant
sleeves and/or other abrasion resistant features may be used in
combination with directional drilling components,
measurement-while-drilling components, and logging-while-drilling
components. However, the abrasion resistant sleeves and/or other
abrasion resistant features also may be used with a variety of
other components, such as bottom hole assembly components. Examples
include wear bands, kicker plates, filters and screens, telemetry
modulators, impellers, turbine blades, cutter blocks for hole
enlargement tools, stabilizer blocks for variable gauge
stabilizers, and/or other downhole components.
[0028] Depending on the parameters of a given application, the
abrasion resistant sleeves may comprise a suitable material or
materials, e.g. a composite material having portions formed of
tungsten carbide matrix. In some applications, the entire abrasion
resistant sleeve may be made of tungsten carbide matrix. The sleeve
also may be provided with additional wear protection elements, such
as polycrystalline diamond compacts and thermally stable
polycrystalline components. The polycrystalline diamond compacts
and the thermally stable polycrystalline components can be
constructed in a variety of different shapes to provide additional,
high abrasion resistance with respect to the sleeves or other
components. The additional wear protection elements also may be
positioned in optimized patterns or arrangements to help reduce the
erosion and abrasive wear.
[0029] Referring again to FIG. 1, the component 10, e.g. stabilizer
10, may be formed as an abrasion resistant component 10. The
abrasion resistant stabilizer 10 (or other component 10) may
similarly be mounted on drill string collar 16. As with embodiments
described above, the abrasion resistant stabilizer 10 may comprise
the plurality of blades 26 which extend outwardly from exterior
surface 24. Also, the abrasion resistant stabilizer 10 may be used
in combination with drill bit 18 and/or in combination with other
drill string components.
[0030] As illustrated in FIG. 6, the abrasion resistant stabilizer
10 may comprise an abrasion resistant sleeve 50. The abrasion
resistant sleeve 50 may be constructed as the entire abrasion
resistant stabilizer 10, or the abrasion resistant sleeve 50 may be
mounted to or incorporated into the stabilizer 10. In this example,
the abrasion resistant sleeve 50 is formed at least in part from
tungsten carbide matrix and comprises a plurality of additional
wear protection elements 52. By way of example, the additional wear
protection elements 52 may comprise polycrystalline diamond
compacts and/or thermally stable polycrystalline components.
[0031] In this stabilizer example, sleeve 50 may be formed with
stabilizer blades 26 and the wear protection elements 52 may be
mounted on or incorporated into the stabilizer blades 26. By way of
example, the wear protection elements 52 may comprise
polycrystalline diamond compact elements 54 and/or thermally stable
polycrystalline elements 56. The wear protection elements 52 may be
mounted along a lead edge 58 progressing up along each stabilizer
blade 26 and in an arrangement which reduces wear on the lead edge
58. Additionally, the wear protection elements 52 may be arranged
to reduce transversal wear patterns.
[0032] In the embodiment illustrated, the wear protection elements
52 comprise polycrystalline diamond compact elements 54 constructed
as high rake cutters provided along the leading edges 58. In some
applications, the polycrystalline diamond compact elements 54 are
arranged in rows along the leading edge 58. In this example, the
blades 26 also comprise thermally stable polycrystalline elements
56 positioned to provide additional wear protection. It should be
noted, however, the wear protection elements 52 may be formed from
a variety of hardened materials. The wear protection elements 52
also may have various shapes and may be arranged in different
patterns depending on the environment, the application, and/or the
type of abrasion resistant component 10, e.g. stabilizer 10. In
some applications, sleeve 50 may comprise threaded regions 59 (or
other suitable connector mechanisms) at its longitudinal ends to
facilitate attachment to adjacent well string components.
[0033] Referring generally to FIG. 7, other embodiments of abrasion
resistant components 10 are illustrated. In this example, the
abrasion resistant components 10 are assembled into drill string 14
deployed in a wellbore 60. The abrasion resistant components 10
incorporate abrasion resistant sleeves 50 which provide the
components with high abrasion resistance. Again, the abrasion
resistant sleeves 50 may be formed in whole or in part of tungsten
carbide matrix. In some applications, the abrasion resistant
sleeves 50 may be used to protect antennas 62 of, for example,
measurement-while-drilling components and/or logging-while-drilling
components. The abrasion resistant sleeves 50 also may be used in
conjunction with, e.g. as part of, stabilizers to form abrasion
resistant stabilizer components 10 as described above. The abrasion
resistant sleeves 50 in these embodiments may again comprise or be
combined with a variety of the wear protection elements 52 formed
of various hard materials. The wear protection elements 52 may be
attached to sleeve 50 via suitable attachment mechanisms, such as
threaded attachment mechanisms, weldments, independent fasteners,
and/or other suitable attachment mechanisms.
[0034] As illustrated in FIG. 8, the abrasion resistant component
10 also may comprise a variety of rotary valves 64 in which
hardened, wear protection elements 52 are combined with various
components of the valve 64. In some downhole applications, the
rotary valve 64 is combined with a torque impeller 66, and the wear
protection elements 52 may be mounted on or formed with impeller
blades and/or other system components to provide a high resistance
to abrasion from, for example, sand and other particulates.
[0035] As illustrated in FIG. 9, for example, a variety of
impellers 66 may incorporate wear protection elements 52 along
impeller blades 68 and/or at other portions of the impeller 66 to
provide resistance to abrasion. As discussed above, however, the
abrasion resistant sleeves 50 and/or wear protection elements 52
may be used with many types of components to construct abrasion
resistant components 10. The abrasion resistant sleeves 50 and/or
wear protection elements 52 may be combined with wear bands, kicker
plates, filters and screens, telemetry modulators, turbine blades,
cutter blocks for hole enlargement tools, stabilizer blocks for
variable gauge stabilizers, and/or other downhole components.
[0036] Depending on the application, the wear resistant components
10 may have a variety of configurations comprising other and/or
additional components. For example, the wear resistant components
10 may comprise a variety of rotary steerable system components
such as pads, e.g. actuator pads, or kickers. In stabilizer
applications, the shape and structure of the stabilizer body and
stabilizer blades may vary in size and configuration depending on
the parameters of a given application and environment. Similarly, a
variety of materials may be used to construct the wear protection
elements 52. Additionally, the wear protection elements 52 may be
combined with many types of abrasion resistant sleeves 50 and/or
other types of abrasion resistant components in well applications
and non-well applications. In some applications, the sleeve 50 may
utilize features, e.g. tongue and groove features, to facilitate
making-up the connection with adjacent components.
[0037] Although a few embodiments of the disclosure have been
described in detail above, those of ordinary skill in the art will
readily appreciate that many modifications are possible without
materially departing from the teachings of this disclosure.
Accordingly, such modifications are intended to be included within
the scope of this disclosure as defined in the claims.
* * * * *