U.S. patent application number 12/698693 was filed with the patent office on 2011-06-30 for stabilizing system and methods for a drill bit.
Invention is credited to Richard C. Raney.
Application Number | 20110155473 12/698693 |
Document ID | / |
Family ID | 29249404 |
Filed Date | 2011-06-30 |
United States Patent
Application |
20110155473 |
Kind Code |
A1 |
Raney; Richard C. |
June 30, 2011 |
STABILIZING SYSTEM AND METHODS FOR A DRILL BIT
Abstract
A drill bit stabilizing system comprising a body member having
an axis and at least one recess formed in the body member housing
at least one stabilizing member when in a first retracted position.
The stabilizing member is positionable along a diagonal angle with
the axis to a second extended operating position which extends
downward and outward relative to the main body to selectively
engage the surface of a pilot bore hole wall during a drilling
operation so as to stabilize an under gauge drill bit used in
association with the stabilizing system. The body member further
comprises at least one fixed stabilizing surface positioned in an
axially spaced relationship to the at least one moveable
stabilizing member. The body member further comprises a gauge
cutter positioned above the moveable stabilizing member and below
the fixed stabilizing surface to expand the pilot hole to the final
gauge.
Inventors: |
Raney; Richard C.; (Round
Rock, TX) |
Family ID: |
29249404 |
Appl. No.: |
12/698693 |
Filed: |
February 2, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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11733498 |
Apr 10, 2007 |
7661490 |
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12698693 |
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11164755 |
Dec 5, 2005 |
7201237 |
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11733498 |
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10135201 |
Apr 30, 2002 |
6971459 |
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11164755 |
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Current U.S.
Class: |
175/408 |
Current CPC
Class: |
E21B 10/62 20130101;
E21B 17/1014 20130101; E21B 10/60 20130101; E21B 10/43
20130101 |
Class at
Publication: |
175/408 |
International
Class: |
E21B 17/10 20060101
E21B017/10 |
Claims
1-5. (canceled)
6. A drill bit stabilizing system comprising, a body member having
at least one recess formed therein, the recess housing at least one
stabilizing member in moveable relationship to the recess, the at
least one stabilizing member comprising a plunger portion provided
in a spring chamber formed in the body member, the spring chamber
comprising a substantially sealed chamber configured to retain a
substantially fixed volume of an incompressible fluid therein,
wherein the substantially fixed volume of the incompressible fluid
is configured to substantially fill the sealed chamber, and a fluid
displacement system in fluid communication with the spring chamber
to provide pressure equalization upon movement of the plunger
within the spring chamber.
7. The drill bit stabilizing system of claim 6, wherein the fluid
displacement system comprises a displacement cylinder in fluid
communication with the spring chamber, and a moveable sealing
member within the displacement cylinder which is moveable in
response to changes in fluid volume within the spring chamber.
8-12. (canceled)
13. The drill bit stabilizing system of claim 6, wherein the fluid
displacement system comprises a moveable sealing member, wherein
the movable sealing member is configured to act on the
incompressible fluid retained in the spring chamber, and wherein
the movable sealing member is configured to be exposed to a region
external to the body member to equalize pressure between the region
external to the body member and the incompressible fluid retained
in the spring chamber.
14. The drill bit stabilizing system of claim 13, wherein the
moveable sealing member comprises a piston.
15. The drill bit stabilizing system of claim 14, wherein the
piston is configured to be disposed within at least a portion of a
bore adjacent the spring chamber.
16. The drill bit stabilizing system of claim 13, wherein the
moveable sealing member comprises a sealed diaphragm.
17. The drill bit stabilizing system of claim 6, wherein the at
least one stabilizing member is configured to be selectively biased
to an extended position such that at least a portion of the
stabilizing member is configured to engage at least a portion of
walls of a borehole, and wherein at least a portion of the
stabilizing member is moveable to stabilize a drill bit used in
association with the stabilizing system.
18. The drill bit stabilizing system of claim 6, wherein the fluid
displacement system is configured to provide pressure equalization
upon movement of the plunger within the spring chamber such that,
during use, static downhole pressure in an annulus of a bore hole
or fluid pressure within a throat associated with the body member,
does not substantially inhibit movement of the at lest one
stabilizing member.
19. The drill bit stabilizing system of claim 6, comprising a
spring member configured to be positioned inside the spring chamber
during use, wherein the spring member is configured to bias the at
least one stabilizing member toward the extended position.
20. The drill bit stabilizing system of claim 6, further comprising
a plurality of stacked disk Belleville washers configured to be
positioned in the spring chamber during use, wherein the plurality
of stacked disk Belleville washers is configured to bias the at
least one stabilizing member toward the extended position.
21. The drill bit stabilizing system of claim 6, further comprising
a seal bushing disposed about the plunger during use, wherein the
seal bushing is configured to seal at least a portion of the spring
chamber configured to interface with the plunger.
22. The drill bit stabilizing system of claim 6, wherein the
substantially fixed volume of incompressible fluid is substantially
isolated from drilling fluid during use.
23. The drill bit stabilizing system of claim 22, wherein an
interior of the spring chamber comprises a biasing member disposed
therein, wherein the interior of the spring chamber is
substantially isolated such that the biasing member is
substantially isolated from drilling fluid during use.
24. The drill bit stabilizing system of claim 6, wherein the body
member comprises a vent hole extending from the recess, wherein the
stabilizing member is configured to move within the recess during
use, and wherein the vent hole inhibits packing of detritus
material within the pocket.
25. A drill bit stabilizing system, comprising: a body member
configured to be disposed in a bore hole during use; a stabilizing
member coupled to the body member, wherein the stabilizing member
is configured to move between a retracted position and an extended
position during use, and wherein at least a portion of the
stabilizing member is configured to engage walls of the bore hole
in the expanded position; a substantially sealed chamber configured
to retain a substantially fixed volume of incompressible fluid
therein, wherein the substantially fixed volume of the
incompressible fluid is configured to substantially fill the sealed
chamber, and wherein the substantially sealed chamber comprises a
sealing member, wherein at least a portion of the sealing member is
configured to be exposed to at least a portion of a fluid pressure
of an annulus of the bore hole during use, and wherein the sealing
member is configured such that at least a portion the fluid
pressure of the annulus of the bore hole is transferred to the
substantially fixed volume of incompressible fluid during use, and
wherein the substantially sealed chamber is coupled to the
stabilizing member such that at least a portion of a fluid pressure
of the incompressible fluid retained in the substantially sealed
chamber is configured to provide a biasing force configured to
facilitate movement of the stabilizing member.
26. The drill bit stabilizing system of claim 25, wherein the at
least a portion of the sealing member is movable.
27. The drill bit stabilizing system of claim 25, wherein the
stabilizing member comprises a plunger configured to extend into
the substantially sealed chamber, and wherein at least a portion of
a fluid pressure of the incompressible fluid retained in the
substantially sealed chamber is configured to act on at least a
portion of the plunger to provide the biasing force configured to
facilitate movement of the stabilizing member.
28. The drill bit stabilizing system of claim 25, further
comprising a biasing mechanism at least partially disposed within
the substantially sealed chamber, wherein the biasing member is
configured to provide a biasing force configured to bias the
stabilizing member toward the extended position.
29. The drill bit stabilizing system of claim 25, wherein the
substantially fixed volume of incompressible fluid is substantially
isolated from drilling fluid during use.
30. The drill bit stabilizing system of claim 25, wherein the body
member comprises a pocket and a vent hole extending from the
pocket, wherein the stabilizing member is disposed in the pocket
during use, wherein the stabilizing member is configured to move
within the pocket between the retracted position and the extended
position during use, and wherein the vent hole inhibits packing of
detritus material within the pocket.
31. A drill bit stabilization system, comprising: a body member
configured to be disposed in a bore hole during use, wherein an
annulus region located between the body member and walls of the
bore hole is exposed to a down hole pressure; a stabilizing member
coupled to the body member, wherein the stabilizing member is
configured to move between a retracted position and an extended
position during use, wherein at least a portion of the stabilizing
member is configured to engage walls of the bore hole in the
expanded position; a substantially sealed chamber configured to
retain a substantially fixed volume of incompressible fluid
therein, wherein the substantially fixed volume of the
incompressible fluid is configured to substantially fill the sealed
chamber, wherein a first portion of the sealed chamber is
configured to be exposed to at least a portion of the down hole
pressure, during use, such that a fluid pressure of the
substantially fixed volume of incompressible fluid at least
partially equalizes with the downhole pressure during use; and a
biasing mechanism configured to bias the stabilizing member in the
extended position during use, wherein at least a portion of the
biasing mechanism is located within the sealed chamber.
32. The drill bit stabilization system of claim 31, wherein the
substantially fixed volume of the incompressible fluid is
substantially isolated from drilling fluid during use.
33. The drill bit stabilization system of claim 31, wherein the
body member comprises a pocket and a vent hole extending from the
pocket, wherein the stabilizing member is disposed in the pocket
during use, wherein the stabilizing member is configured to move
within the pocket between the retracted position and the extended
position during use, and wherein the vent hole inhibits packing of
detritus material within the pocket.
34. A drill bit stabilizing system, comprising: a body member
configured to be disposed in a bore hole during use, wherein the
body member comprises: a pocket; and a vent hole extending from the
pocket; and a stabilizing member disposed in the pocket during use,
wherein the stabilizing member is configured to move within the
pocket between a retracted position and an extended position during
use, and wherein at least a portion of the stabilizing member is
configured to engage walls of the bore hole in the expanded
position;
35. The drill bit stabilizing system of claim 34, wherein the vent
hole inhibits packing of detritus material within the pocket.
Description
[0001] This application is a divisional of U.S. patent application
Ser. No. 11/164,755 filed Dec. 5, 2005 which is a divisional of
co-pending U.S. patent application Ser. No. 10/135,201, filed Apr.
30, 2002, each of which is hereby incorporated by reference.
TECHNICAL FIELD
[0002] This invention relates generally to drill bit and drill bit
stabilizing systems and methods for use in borehole forming
operations wherein a drill bit is connected to a drill string and
rotated while drilling fluid flows down the drill string to the
drill bit for circulating cuttings up the borehole as the hole is
drilled. More particularly, the invention relates to stabilizing
systems and methods for stabilization of a drill bit so as to
minimize vibration and possible damage to the drill bit or other
structures.
BACKGROUND OF THE INVENTION
[0003] My prior U.S. Pat. Nos. 4,842,083; 4,856,601; and 4,690,229,
which are hereby incorporated by reference, are directed to
drilling systems and methods providing distinct advantages. U.S.
Pat. No. 4,842,083, entitled "Drill Bit Stabilizer", is directed to
a stabilizing system to stabilize the drill bit and drilling string
in a down hole system, and the present invention is directed to
improvements in the system and methods described therein. Although
the prior system and methods provide the desired stabilization of
the drill bit under most circumstances, it has been found to be
desirable to minimize the actuating forces required on the wedge
shaped stabilizing members in order to affect the frictional
blocking action needed for radial stability. Also, it has been
found to be desirable to account for high down hole drilling
pressures, particularly where the stabilizing members are spring
actuated, such that the drilling fluid pressure does not adversely
interfere with the spring action of the stabilizing members.
Blockages of various orifices or recesses in the system can also
cause problems, and the present invention is directed at reducing
or eliminating such possible blockages, particularly around the
stabilizing members. It has also been found that under certain
conditions, the bit may not be properly stabilized by the
stabilizing members, such as at the beginning of a drilling
operation or where no pilot hole is formed in the borehole. In such
situations, it would be desirable to provide stabilization for the
bit face until sufficient hole has been drilled to allow the
stabilizing members to engage the bore hole wall. Thus, it would be
desirable to prevent vibration damage of PDC cutting elements on
the bit which can occur during the start of drilling a bore hole,
or to prevent harmful axis wobble of the assembly may occur during
ongoing drilling operation.
[0004] As will be shown herein, the present invention includes
improved means so as to overcome the deficiencies and problems
mentioned above.
SUMMARY OF THE INVENTION
[0005] It is therefore an object of the present invention to
provide a drill hit stabilizing system and methods which overcome
the above noted problems.
[0006] The structure of the present invention may be generally
similar to that shown in prior U.S. Pat. No. 4,842,083; except that
the various improvements have been provided, both as to the methods
and stabilizing system of the invention. In one aspect, the
invention is directed to a drill bit stabilizing system comprising
a body member having an axis, and at least one recess formed in the
body member for housing at least one stabilizing member when in a
first retracted position. The at least one stabilizing member is
biased to a second extended operating position. The body member
further comprises at least one fixed stabilizing surface positioned
in axially spaced relationship to the at least one moveable
stabilizing member, in another aspect, the invention is directed to
a drill bit stabilizing system comprising a body member and at
least one stabilizing member, being moveable from an extended
operating position to a retracted position within the body member.
The at least one stabilizing member comprises outer contact faces
adapted to engage the wall of a bore hole when in an operating
position, and an inner slide surface adapted to slidingly engage a
corresponding slide surface formed in the body member. The inner
slide surface comprises at least one relief groove to facilitate
the reduction of the surface area of the surface and thereby
provide a predetermined increase in the contact pressure per square
inch between the inner slide surface and corresponding slide
surface associated with the body member. In a further aspect, the
slideable, wedge shaped stabilizing members are entirely spring
actuated and the at least one stabilizing member comprises a
plunger portion provided in a spring chamber formed in the body
member. The spring chamber comprises an amount of incompressible
fluid therein, and a fluid displacement system in fluid
communication with the spring chamber to provide pressure
equalization upon movement of the plunger within the spring
chamber. The invention is also directed to a drill bit for forming
a bore hole wherein the drill bit is attached to a rotary drill
string having an axial passageway through which drilling fluid
flows to the bit face The bit comprises a plurality of wear ridges
and a plurality of cutters in association with the bit face, the
plurality of wear ridges characterized in providing an initial
support surface for the weight applied to the bit during a drilling
operation. There is also provided a method of drilling a bore hole
using a drill bit rotated in conjunction with a drill string. The
method comprises the steps of providing a drill bit having a
plurality of wear ridges on the bit face along with a plurality of
cutting elements. The plurality of wear ridges initially extend
outwardly from the bit face to a greater extent than the plurality
of cutting elements. The drill bit is rotated along with the drill
string to initiate a drilling operation or in an existing fall
gauge hole to form a pilot hole. Upon rotation of the drill bit,
the plurality of wear ridges will allow rotation of the drill bit
and drill string for a period of time before engagement of the
plurality of cutting elements.
[0007] Other objects and advantages of the present invention will
be apparent upon consideration of the following specification, with
reference to the accompanying drawings in which like numerals
correspond to like parts shown in the drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] FIG. 1 is a longitudinal, partially sectioned view of the
preferred embodiment;
[0009] FIG. 2 is a straight-on bottom view of the embodiment;
[0010] FIG. 3 is a cross sectional view taken along line 3-3 of
FIG. 1;
[0011] FIG. 4 is an enlarged partial side view taken along line 4-4
of FIG. 1;
[0012] FIG. 5 is a multi-view illustration of the item shown in
FIG. 4;
[0013] FIG. 6 is a flattened partial side view taken along line 6-6
of FIG. 2;
[0014] FIGS. 7 through 14 are partial sectional views of various
portions of items shown in FIG. 2;
[0015] FIG. 15 is an enlarged partial sectional view of FIG. 1;
[0016] FIG. 16 is a schematic, part sectional view of a drilling
operation with the present invention included therewith.
DETAILED DESCRIPTION
[0017] Referring to the figures of the drawings, the embodiment
comprises an improved stabilizer and drill bit, generally indicated
by the numeral 100. The invention in one aspect is generally
directed to a drill bit stabilizer having a main body of generally
cylindrical configuration and a pin end opposed to a lower drilling
end. The system is attachable to or includes a drill bit for making
a borehole when rotation occurs. A throat is formed longitudinally
through the main body of the stabilizer for passage of drilling
fluid from a drill string, through the body, and through nozzles of
the bit. The drilling fluid exits the bit and returns up the
borehole annulus. A plurality of circumferentially arranged wedge
shaped pockets or recesses are formed about the main body from the
outer surface of the main body inward to slideably receive
corresponding wedge shaped stabilizing members. Means are provided
by which the stabilizing members are spring actuated. The
stabilizing members are each therefore reciprocatingly received in
a slideable manner, as they are spring actuated within each
respective pocket. Each of the stabilizing members has an outer
face which can be retracted into alignment with the outer surface
of the main body, and which can be extended outwardly from the
surface of the main body and into abutment with the wall of a
borehole. Flushing orifices are provided to allow a limited volume
of drilling fluid to flow from the throat through the pockets so as
to prevent jamming of the stabilizing members by detritus
material.
[0018] The before mentioned spring means are incorporated into the
main body in a manner such that each of the stabilizing members is
forced to move in an angular direction downwardly and outwardly of
the main body. The spring means forces the stabilizing members
towards the extended configuration and, as the face of the
stabilizing member, or the borehole wall, is worn, the face of the
member is further extended to maintain abutment with the borehole
wall. Frictional means is provided to lock, or block, the
stabilizing members in any one of a range of extended positions.
The frictional means is the friction between the sliding surfaces
of the wedge shaped stabilizing members and the corresponding
surfaces of the pockets within which the wedges are received.
[0019] More particularly, and with respect to the embodiments shown
in the drawings, the stabilizer comprises a main body 1 made of a
suitable material such as steel. The main body 1 is generally
cylindrical in shape and the upper end thereof is threaded in the
conventional manner or is otherwise provide with a known means for
attachment to the end of a drill pipe or "drill string". The main
body 1 has a central fluid passage or throat 15 extending from the
top end, axially along the central axis towards the lower end. The
lower marginal end of the main body 1 may be an integral part of a
drill bit 110, as shown in FIG. 1, or it may be a separate member
suitably attachable to a drill bit with the throat 15 arranged to
provide a flow of fluid therethrough to the drill bit, as described
in my previous U.S. Pat. No. 4,842,083, of which this invention is
a continuation in part.
[0020] The embodiment 100 includes a plurality of moveable and
radial stabilizing wedges 29 installed in complementary radial
pockets 3 formed into the main body 1 in spaced relationship
respective to the throat 15. The pockets 3, with the respective
wedges 29 installed therein, are symmetrically arranged
circumferentially about the central longitudinal axis of the main
body 1, as shown in FIGS. 1 and 3. The embodiment 100 of FIGS. 1
and 3 includes three such pockets 3 and three corresponding wedges
29; however, any suitable number may be employed.
[0021] The pockets 3 are each shaped and arranged to provide a
mated slide surface 45 which is inclined downward and outward
relative to the central axis of the main body 1. The upper end
surface 45' of each pocket 3 is generally perpendicular to the
inclined slide surface 45, as seen in FIG. 15. Each wedge 29 is
correspondingly shaped and arranged so that the outer surface of
each wedge 29 is flush or aligned with the outer surface of the
main body 1 when the wedges 29 are fully seated into the pockets 3.
Each wedge has an inner slide surface 44 which is mated to and
arranged to slide against the slide surface 45.
[0022] The outer faces of the wedges 29 are provided with suitably
thick wear resistant tungsten carbide surfaces 36 formed onto the
outer faces of the wedges 29 so that the wear resistant surfaces 36
are flush or aligned with the outer faces of the wedges 29, thereby
making the outer faces of the wedges 29 wear resistant. The wedges
29 may alternatively be made entirely of a wear resistant material,
such as ceramic, or may be made wear resistant by other known
expedients, such as applying PDC diamond to the faces.
[0023] Corresponding plungers 32 are attached to the upper end of
each wedge 29 and extend upward and inward parallel to the slide
surface 45 of each pocket 3. To facilitate proper operation, the
coupling between the wedge 29 and corresponding plungers 32 is
preferably non-rigid or has some flexibility to allow some movement
between these members. Such a connection will avoid the formation
of a high stress point at this location. In the embodiment shown,
to attach the wedges 29 to the plungers 32, a bore 8 is formed in
the large end of each wedge, as shown in FIG. 5; with an annular
groove 9 formed therein. As shown in FIG. 15, the lower ends of
plungers 32 are formed to correspond to bores 8 and have grooves
formed thereon to match with grooves 9. As shown in FIG. 5, an
access hole 10 is drilled tangent to groove 9 in each wedge 29 to
allow insertion of metal balls 48, of metal such as stainless
steel, so the matching grooves are filled with metal balls to
thereby attach the wedges 29 to the plungers 32, as seen in FIG.
15. The access holes 10 are tapped to receive plugs to retain the
metal balls in place.
[0024] Complementary bores 46', which do not communicate with the
throat 15, are provided to receive each plunger 32. Each bore 46'
has an enlarged section to form a spring chamber 46 and to
accommodate seal bushing 33. The seal bushings 33 are installed in
fixed relationship within the lower marginal end of spring chambers
46 and reciprocatingly receive the plungers 32 in sealed
relationship therewith by means of the illustrated o-rings 31.
Wipers 43 are also added to prevent debris from banning the o-rings
31 during reciprocating movements of the plungers 32. The seal
bushings 33 are sealed to the spring chambers 46 by o-rings 49 and
are affixed therein by locking rings 35, or by other suitable known
means. Springs 34, such as Belleville washers, and preferably of
the stacked disk type, are received about each plunger 32 between
the seal bushing 33 and the upper end of spring chambers 46. The
springs 34 are thus respectively confined and sealed within the
chambers 46 at a location between the upper end of chamber 46 and
seal bushing 33. To prevent harmful effects from high static
pressures encountered down hole during operation, the spring
chambers 46 must be filled with an incompressible fluid, such as
hydraulic oil, which is sealed therein by plugs 51; and all air or
gas bubbles should be removed.
[0025] In addition, since any reciprocating movement of plungers 32
will produce a displacement of fluid in chambers 46, complementary
bores 46' extend upward to intersect and provide fluid
communication with corresponding radial bores 4, as shown in FIG.
1. A moveable sealing member 5, such as a free traveling piston is
installed in each bore 4 and moveably sealed therein by an O-ring 6
so as to keep fluid within chamber 46, bore 46' and the inner
portion of bore 4. The moveable sealing member 5 could be of a
different character, such as a sealed diaphragm or the like, while
accommodating fluid displacement. Thus, as plunger 32 moves in or
out during operation, corresponding moveable sealing member 5, such
as a piston, freely moves in or out to accommodate the change in
fluid volume within chamber 46, A retaining ring 7 is installed in
bore 4 to keep piston 5 from inadvertently traveling too far
outward in bore 4. Thus, the in or out travel of plunger 32 and
wedge 29 is not hindered nor affected by static down hole pressure
nor by fluid pressure within throat 15.
[0026] A suitable flange 11 is formed on each plunger 32 to provide
contact with springs 34; and to abut against the seal bushings 33
so as to limit the outward travel of each plunger 32 at the
appropriate distance. The springs 34 are arranged to press against
the flanges 11 and thereby bias the plungers 32, and the wedges 29
attached thereto, outward. As will be explained later herein, the
wedges 29 and plungers 32 are to be retracted inward by other force
means, such as by thrust of the wedges 29 against the rim of the
pilot hole formed by the bit 110.
[0027] As seen in FIGS. 1 and 15, flushing orifices 54 are
positioned to provide fluid communication between throat 15 and
each pocket 3 and are sized and arranged to provide an effectual
flow of fluid through each pocket 3 so as to prevent detritus
material from packing or jamming around the wedges 29. As shown in
FIGS. 1 and 15 of embodiment 100, orifice 54 may be in the form of
a disk made of abrasion resistant material, such as tungsten
carbide, having an aperture 40 approximately 0.100 inch to 0.125
inch in diameter. As shown in FIG. 15, aperture 40 is preferably
tapered and flared outward downstream so as to minimize the
velocity of fluid exiting therethrough. Orifice 54 is retained in a
suitably formed port 30 by means of a hollow screw 41 and sealed
therein by an o-ring 42. Each port 30 intersects throat 15 and
provides fluid communication therethrough between throat 15 and
each corresponding orifice 54. Thus, flushing fluid, such as
drilling fluid passing under pressure within throat 15, can pass
outward through each orifice 54, outward through each pocket 3 and
around each wedge 29 so as to remove detritus material or debris
which might otherwise pack around the wedges 29 and jam proper
movement thereof.
[0028] In order to prevent orifices 54 from becoming clogged by
foreign material which might be present in drilling fluid passing
through throat 15, a strainer sleeve 26 is installed in throat 15
adjacent ports 30, as shown in FIGS. 1 and 15. The outer surfaces
of strainer sleeve 26 are formed so that the upper and lower end
portions fit closely within throat 15, but the intermediate portion
is smaller in diameter so that a small but adequate annular space
28 is provide between the sleeve 26 and the wall of throat 15
adjacent to the ports 30. The inner surface of sleeve 26 is
cylindrical. A plurality, preferably up to 200, strainer holes 37
are drilled in sleeve 26 within the region of annular space 28, but
sufficiently above the vicinity of ports 30, as shown in FIG. 15.
The holes 37 are positioned above and away from ports 30 so as to
prevent erosion of the holes 37 due to the swirl of fluid entering
ports 30. Thus, drilling fluid is permitted to pass from throat 15
through holes 37, through annular space 28, through ports 30 and
through orifices 54 into pockets 3. The strainer holes 37 are
approximately 0.050 inch to 0.070 inch in diameter so as to be
smaller than the apertures 40. Thus, foreign material large enough
to clog orifices 54 cannot pass through strainer sleeve 26 when
passing through throat 15. The annular space 28 is, preferably,
made no wider than 0.070 inch so that it too prevents clogging of
orifices 54. Notice that the apertures 40 are sized to provide a
flow rate through each of approximately 10 gpm to 15 gpm at the
usual operating pressures.
[0029] In tests, it has been found that flushing fluid exiting
orifices 54 and passing through pockets 3 can cause erosion damage
to the sealing surface of plungers 32. To prevent such erosion
damage, a clearance notch 50 is formed on the inner, upper end of
each wedge 29, as shown in FIGS. 5 and 15; and ports 30 and
orifices 54 are positioned so that fluid exiting orifices 54
impinges against notches 50 so as to deflect the fluid in a manner
that does not erode the surface of plungers 32.
[0030] In normal operation, the main flow of drilling fluid through
throat 15 is to the nozzles of the bit 110, so that foreign
material or debris cannot clog the strainer holes 37 because the
main flow through throat 15 will wash them away towards the nozzles
of the bit 110. To further enhance this washing action, throat 15,
in the vicinity of sleeve 26, along with sleeve 26, is made small
enough in diameter so that a relatively high fluid velocity is
achieved therethrough during normal operation. For example, when
around 300 gpm of drilling fluid is provided, 11/4 to 11/2 inch
inside diameter of sleeve 26 seems to produce sufficient fluid
velocity for effective washing action. To prevent undue erosion of
sleeve 26, preferably, sleeve 26 should be made of case hardened
steel, or some harder material.
[0031] As shown in FIGS. 1, 2, and 15, the bit 110 is equipped with
a plurality of nozzles 25, similar to the arrangement described in
my prior U.S. Pat. No. 4,856,601, which are arranged to provide
optimum fluid flow restriction and appropriate fluid output
velocity. The nozzles 25 are installed in corresponding nozzle
ports 24 which are formed and arranged to communicate with throat
15. The nozzles 25 are retained in ports 24 by means of threaded
retainers 52 and sealed against leak-by means of o-rings 38.
Nozzles 25 will usually be made of abrasion resistant material such
as tungsten carbide.
[0032] As shown in FIGS. 1, 2 and 3, a plurality of flow slots 27
are formed in the face of bit 110 and along the outside of main
body 1 to permit the return flow of drilling fluid exiting nozzles
25 during operation and to thereby evacuate drilled cuttings from
the bore hole. Also, a plurality of cutting elements 18, usually
the PDC type, are installed, positioned and arranged on bit 110 so
as to cut rock from the bottom of the borehole as bit 110 is
rotated during operation.
[0033] As seen in FIG. 1, the portion of the main body 1
immediately above the wedges 29 is slightly larger in diameter than
the bore hole produced by the drill bit 110 and has installed
therein a plurality of secondary gauge cutting elements 85 which
are similar to the cutting elements 18 on the face of bit 110.
[0034] Notice that the gauge cutters 85 are shown in hidden lines
and are artificially rotated into the positions shown so as to
illustrate their cutting profile. The secondary gauge cutters 85
are positioned and arranged to produce a borehole large enough in
diameter for the entire assembly to pass upward therethrough even
when the wedges 29 are fully extended, as shown in FIG. 1. Thus,
the drill bit 110 and the primary gauge cutters thereof forms a
pilot hole which is intended to be enlarged by the secondary gauge
cutters 85 to the final desired diameter.
[0035] In order to further prevent packing of detritus material
behind or under the wedges 29, vent holes 80 are formed to extend
from the deeper end of each pocket 3 into each corresponding slot
27. As shown, two such vents 80 may be employed for each pocket
3.
[0036] In testing, it has been learned that forces generated by
cutters 18 in the bit face, combined with forces generated by gauge
cutters 85, can tend to cause the axis of the assembly to wobble
relative to the axis of the borehole being drilled. Such axis
wobble can cause damage to the gauge cutters 85 or to the bit face
cutters 18. Therefore, as seen in FIG. 1, upper fixed stabilizing
surfaces 12, such as gauge pads, are formed on body 1 or provided
on a separate body member attached to the stabilizing system. As an
example, the fixed stabilizing surfaces 12 could be formed as part
of the body member 1, or could be provided by means of a suitable
additional body member having fixed stabilizing surfaces thereon,
which is coupled to the main body 1. The fixed stabilizing surfaces
12 are preferably provided in corresponding relationship to each
pocket 3, and in positions axially behind gauge cutters 85 and
radial bores 4, so as to be located at a predetermined axial
distance behind wedges 29. In an example, the fixed stabilizing
surfaces are positioned such that they are spaced from the
corresponding moveable stabilizing members an axial length of not
more than three times, and preferably not more than twice the gauge
diameter of assembly. The fixed stabilizing surfaces 12 may also be
provided with wear resistant surfaces 14, which can be integral to
or can be installed in the surface of each pad 12 to provide wear
resistance. Surfaces 14 may be solid tungsten carbide, or may be
impregnated or coated with diamond to achieve maximum wear
resistance; or, the pads 12 may be made wear resistant by some
other expedient method. The fixed stabilizing surfaces in
conjunction with the moveable stabilizing members provide distinct
advantages in operation to avoid detrimental wobble and vibration
at the drill bit tip.
[0037] The pads 12, with surfaces 14 provided or installed thereon,
are sized and positioned to very nearly coincide with the borehole
diameter cut by gauge cutters 85 so that only minimal clearance
between the surfaces 14 and the borehole wall is allowed. Notice
that the axial distance between wedges 29 and surfaces 14 is
relatively short, and configured to prevent axis wobble of the
assembly during drilling operation. The gauge pads 12 are
effectively integral to the body 1. Of course, pads 12 could be
made as part of a short profile body, commonly called a "sub",
which could be weldable or otherwise attachable to main body 1 so
as to be effectively integral thereto. Nevertheless, as shown in
FIG. 1, pads 12 and main body 1 are a single continuous piece in
the preferred embodiment.
[0038] As seen in FIG. 16, a borehole 60 has a drill string 62 and
a drill collar 64 therein; with the stabilizer 100 attached to the
lower end thereof. A drill bit 110 is integrally attached to the
lower end of the stabilizer 100. A drilling rig 70 manipulates the
drill string 62. The drill string 62, drill collar 64, together
with the stabilizer 100 and drill bit 110 attached, are inserted in
a bore hole 60 and rotated in the conventional manner during a
drilling operation. In operation, drilling fluid flows at 72 into
the drill string 62, through the drill string 62, through the
throat 15 of the present stabilizer 100, out of the drill bit 110,
back up the bore hole annulus outside the drill string 62 and
returned through a blowout preventer 74 in the usual manner. A
shown in FIGS. 1, 2 and 3, flow slots 27 permit passage of the
drilling fluid and, thereby, removal of drilled cuttings from the
borehole.
[0039] In the above mode of operation, the wedges 29 will run in a
pilot hole formed by drill bit 110 and the primary gauge cutters
thereof, while the secondary gauge cutters 85 enlarge the bore hole
to the desired final diameter.
[0040] In a usual operation, drilling fluid flowing through the
present stabilizer 100 is at a relatively elevated pressure within
throat 15, because of the usual pressure drop measured across the
nozzles 25 of the drill bit 110. However, neither the fluid
pressure in throat 15 nor the fluid pressure outside of stabilizer
1.00 will have any effect on the plungers 32. Due only to the
thrust of the springs 34, the plungers 32 will thrust downward. The
wedges 29 will thus be caused to move downward and outward along
the slide surface 45 until the outer face of the wedges 29 abuts
the wall of the pilot hole. The wedges 29 thus are held in contact
with the wall of the pilot hole so long as sufficient spring
tension is maintained. Also, as the outer surface of wedges 29, or
the borehole wall, slowly wear due to friction against the wall of
the pilot hole; the thrust of springs 34 will continually force
plungers 32 and wedges 29 downward and outward to maintain the
outer face of wedges 29 in constant rotating abutment with the
stationary wall of the pilot hole.
[0041] The angle of the slide surfaces 44 and 45, with respect to
the axis of main body 1, is of a selected value so that inward
radial force exerted on the outer face of each wedge 29 produces
sufficient friction between the mated slide surfaces 44 and 45 to
overcome the resultant upward sliding vector force on the wedges
29, so that the wedges 29 cannot be made to retract by radial force
during drilling operation. This is called "radial blocking action"
which prevents radial movement of the central axis of stabilizer
100 and bit 110. The relative angle and arrangement of the slide
surfaces 44 and 45 is such to block any radial inward movement of
the wedges 29 at any extended position thereof when an inward
radial force is exerted on the wedges 29. This is so even if such
inward radial force is of a magnitude that would overcome the
thrust of springs 34 in the absence of the frictional interaction
of the slide surfaces 44 and 45.
[0042] The frictional interaction between surfaces 44 and 45
depends, of course, on the prevailing coefficient of friction. It
has been learned that, due to the relatively large area of surface
44 on each wedge 29, as described in my prior U.S. Pat. No.
4,842,083, the coefficient of friction is sometimes reduced by
conditions of the drilling fluid or other materials present during
operation. Since the coefficient of friction tends to increase with
the amount of contact pressure per square inch, a shallow but
relatively wide relief groove 47, as shown in FIGS. 5 and 15, is
formed longitudinally through the middle of slide surface 44 on
each wedge 29 to reduce the effective area of each surface 44, by
one half or more, and thereby increase the contact pressure per
square inch between slide surfaces 44 and 45; and thus increase the
coefficient of friction and frictional interaction between the
slide surfaces 44 and 45. This reduces the amount of spring thrust
required in order to affect the "blocking action" previously
described; and also reduces the outward force and frictional drag
between the outer surface, of wedges 29 and the wall of the pilot
hole. In addition, the longitudinal groove 47 provides a flow path
for drilling fluid traveling back up the borehole annulus to flow
under and behind each wedge 29 and thereby aid in removing detritus
material from each pocket 3.
[0043] As shown in FIG. 2 and in FIGS. 6 through 14, the face of
bit 110 has wear ridges 39 integrally formed thereon immediately
trailing and corresponding to the pattern of cutting elements 18.
The cutters 18 are deeply installed, and the ridges 39 are so
formed, that the tips of cutters 18 initially do not extend beyond
the surface profile of the ridges 39, before any wear occurs on the
ridges 39. Notice that the ridges 39 of the present invention are
similar to the fluid flow isolating ridge 39 of my prior U.S. Pat.
No. 4,856,601, however, the ridges 39 of the present invention are
much wider and stronger, so as to be able to actually support the
weight applied to the bit 110 during typical drilling operation,
without wearing too fast. For example, the ridges 39 of the present
invention will normally be formed of high grade, hardened steel so
as to be at least one-half inch wide, or more, and so as to be
quite resistant to wear when rotated against the bottom of a bore
hole; and wear resistant materials, such as tungsten carbide, may
be applied to the ridges 39 to further increase wear resistance.
This provides needed stabilization of bit 110 during the start of
drilling a borehole.
[0044] For instance, when starting to drill a bore hole, either at
the surface or at the bottom of a preliminary, full gauge hole
drilled with a conventional drill bit, where no pilot hole exists,
the wedges 29 cannot engage the wall of the full gauge hole and
cannot provide any stabilization, initially. In such an instance,
if the cutters 18 are allowed to fully engage, or cut into the
bottom of the bore hole, the cutting forces will cause chatter or
other vibrations that will damage the cutters 18, especially when
the rock or other material being drilled is relatively hard.
[0045] Hence, in the ridge and cutter arrangement of the present
invention, the strong ridges 39 support the normal weight-on-bit
and prevent the cutters 18 from engaging until the ridges 39 wear
to expose them. As rotation begins with weight-on-bit applied, the
ridges 39 will normally abrade the borehole bottom sufficiently to
form a matching profile pattern thereon. The ridges 39, being held
against the matching profile of the borehole bottom by the
weight-on-bit, will maintain stability of the bit axis. As rotation
continues, the ridges 39 will slowly wear and allow the cutters 18
to begin to engage the borehole bottom, which will proportionately
increase the drilling and penetration. Notice that, as the lower
nose end of each wedge 29 contacts the rim of the pilot hole formed
by the bit 110, the wedges 29 and the respective plungers 32 will
be easily pushed upward and inward as the main body 1 and bit 110
continue to rotate, drill and descend while making hole. As
drilling continues, a pilot hole will be formed by the bit 110,
which will facilitate full engagement and stabilizing action of the
wedges 29 against the wall of the pilot hole.
[0046] The ridges 39 are formed and arranged so that, before the
wedges 29 are fully engaged and activated, the ridges 39 continue
to bear most of the weight-on-bit. After the wedges 29 are fully
engaged and activated, after about two feet of hole is drilled, the
ridges 39 continue to wear, usually for two hours or longer, until
the ridges 39 no longer bear any of the weight-on-bit; and
practically all the weight-on-bit is then borne by the cutters 18.
Thus, the ridges 39 provide temporary stabilization; at least until
the wedges 29 are able to fully engage the pilot hole formed by the
bit 110.
[0047] Since the ridges 39 are made of tough steel, which is harder
than the materials typical casing plugs are made of, a drill bit
and stabilizer assembly made according to the present invention can
be used to effectively drill out casing plugs, without experiencing
damage to the cutters 18. This is a distinct benefit, because
conventional PDC bits often experience damaged cutters when
drilling out casing plugs at the start of drilling oil or gas
wells. Of course, hard materials, such as tungsten carbide, may be
applied to the ridges 39 so as to predetermine their wear rate or
abrasive characteristics.
[0048] It should be made clear that the ridges 39 of the present
invention are arranged and intended so as to wear sufficiently, in
due course, so that, after drilling has progressed sufficiently,
the ridges 39 no longer bear any of the weight-on-bit nor any
longer retard the cutting and penetrating action of the cutters
18.
[0049] During ongoing drilling operation, axis wobble of the
assembly is prevented by virtue of the axial spacing between the
wedges 29 and the gauge surfaces 14 and by the limited, or
non-existent, clearance between the surfaces 14 and the bore hole
wall. Also, in the event that detritus material accumulates in
pockets 3 behind the wedges 29, the detritus material can be forced
out of the pockets 3 through vents 80 and into slots 27 upon upward
movement of wedges 29.
[0050] Also, even under extremely high down hole static pressure,
the hydraulic force on plungers 32 will be equalized by the action
of pistons 5 freely moving in bores.
[0051] Now, it can be seen from the foregoing that the present
invention provides improved means for radial stabilization of a
drill bit; such that whirl, chatter and other forms of radial
vibration are prevented under a wide range of drilling conditions;
and such that the drilling, penetrating and endurance capabilities
of a PDC drill bit is maximized.
* * * * *