U.S. patent application number 11/073051 was filed with the patent office on 2006-09-07 for modular kerfing drill bit.
Invention is credited to Johnny Castle, Roy Estes, Marvin Gearhart.
Application Number | 20060196699 11/073051 |
Document ID | / |
Family ID | 36943045 |
Filed Date | 2006-09-07 |
United States Patent
Application |
20060196699 |
Kind Code |
A1 |
Estes; Roy ; et al. |
September 7, 2006 |
Modular kerfing drill bit
Abstract
A modular kerfing rock drilling bit (10) is presented. Drill bit
(10) comprises a bit body (12) having a connection (14) for
attachment to a drill string member. A base portion (16) below the
connection (14) has an outer portion (18) and a bottom (20). Slots
(22) are formed in the base portion (16). A cutter assembly (100)
comprises a leg (110) insertable into the slot (22) of the bit body
(16). A journal (126) extends angularly downward and inward from
the leg (110) for bearing support of a cone (180) rotatably mounted
on the journal (126). A plurality of cutters (182) extend outward
from the surface of the cone (180). A kerfing segment (140) extends
downward from the leg (110) beyond the cone (180). A plurality of
kerf cutters (142) are attached to the bottom of the kerfing
segment (140).
Inventors: |
Estes; Roy; (Weatherford,
TX) ; Gearhart; Marvin; (Fort Worth, TX) ;
Castle; Johnny; (Weatherford, TX) |
Correspondence
Address: |
STORM LLP
BANK OF AMERICA PLAZA
901 MAIN STREET, SUITE 7100
DALLAS
TX
75202
US
|
Family ID: |
36943045 |
Appl. No.: |
11/073051 |
Filed: |
March 4, 2005 |
Current U.S.
Class: |
175/374 ;
175/398; 175/415 |
Current CPC
Class: |
E21B 10/04 20130101 |
Class at
Publication: |
175/374 ;
175/398; 175/415 |
International
Class: |
E21B 10/00 20060101
E21B010/00 |
Claims
1. A modular kerfing drill bit, comprising: a bit body comprising;
a connection for attachment to a drill string member; a base
portion below the connection means, having an outside surface, and
a bottom surface; and, at least one slot formed in the base
portion; a cutter assembly comprising; a leg insertable into the
slot of the bit body; a journal extending angularly downward and
inward from the leg; a cone rotatably mounted on the journal; a
plurality of cutters extending outward from the surface of the
cone; a kerfing segment extending downward from the leg; and, a
plurality of kerf cutters attached to the bottom of the kerfing
segment.
2. The modular kerfing drill bit of claim 1, further comprising: a
kerfing assembly comprising; a leg insertable into the slot of the
bit body; a kerfing segment extending downward from the leg; and, a
plurality of kerf cutters attached to the bottom of the kerfing
segment.
3. The modular kerfing drill bit of claim 1, further comprising:
wherein each kerf cutter on a kerfing segment is located at a
unique radial position.
4. The modular kerfing drill bit of claim 1, further comprising:
wherein a kerfing segment contains kerf cutters located at radial
positions substantially equal to the radial positions of the kerf
cutters on another kerfing segment of another leg.
5. The modular kerfing drill bit of claim 1, the leg further
comprising: a lead face and an opposite trailing face; a back face
and an opposite center face; a transition face angularly disposed
between the center face and the kerfing segment; and, wherein the
journal extends outward substantially perpendicular to the
transition face.
6. The modular kerfing drill bit of claim 5, the leg further
comprising: a contiguous mesh of flow channels and flow slots
extending from the leg center face, to between the kerf cutter, and
to the leg back face.
7. The modular kerfing drill bit of claim 6, the contiguous mesh of
flow channels and flow slots further comprising: alternating
vertically and horizontally oriented of flow channels and flow
slots.
8. A cutter assembly comprising; a leg insertable into the slot of
the bit body; a journal extending angularly downward and inward
from the leg; a cone rotatably mounted on the journal; a plurality
of cutters extending outward from the surface of the cone; a
kerfing segment extending downward from the leg; and, a plurality
of cutters attached to the bottom of the kerfing segment.
9. A kerfing assembly comprising; a leg insertable into the slot of
the bit body; a kerfing segment extending downward from the leg;
and, a plurality of cutters attached to the bottom of the kerfing
segment.
10. A modular kerfing drill bit, comprising: a bit body comprising;
a connection for attachment to a drill string member; a base
portion below the connection means, having an outside surface, and
a bottom surface; and, a plurality of slots formed in the base
portion; a cutter assembly comprising; a leg insertable into the
slot of the bit body; a journal extending angularly downward and
inward from the leg; a cone rotatably mounted on the journal; a
plurality of cutters extending outward from the surface of the
cone; a kerfing segment extending downward from the leg; and, a
plurality of cutters attached to the bottom of the kerfing segment;
and, a kerfing assembly comprising; a leg insertable into the slot
of the bit body; a kerfing segment extending downward from the leg;
and, a plurality of kerf cutters attached to the bottom of the
kerfing segment.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] None.
BACKGROUND OF THE INVENTION
[0002] 1. Technical Field
[0003] The present invention relates generally to drilling bits
used for drilling earth formations. More specifically, the present
invention relates to a novel modular design for the improved
construction of kerfing type rock bits, comprised of a combination
of fixed cutters and roller cone cutters.
[0004] 2. Description of Related Art
[0005] In the exploration of oil, gas, and geothermal energy,
drilling operations are used to create boreholes, or wells, in the
earth. These operations normally employ rotary and percussion
drilling techniques. In rotary drilling, the borehole is created by
rotating a tubular drill string with a drill bit secured to its
lower end. As the drill bit deepens the hole, tubular segments are
added to the top of the drill string. While drilling, a drilling
fluid is continually pumped into the drilling string from surface
pumping equipment. The drilling fluid is transported through the
center of the hollow drill string and into the drill bit. The
drilling fluid exits the drill bit at an increased velocity through
one or more nozzles in the drill bit. The drilling fluid then
returns to the surface by traveling up the annular space between
the borehole and the outside of the drill string. The drilling
fluid carries rock cuttings out of the borehole and also serves to
cool and lubricate the drill bit.
[0006] One type of rotary rock drill is a drag bit. Early designs
for drag bits included hard facing applied to steel cutting edges.
Modern designs for drag bits have extremely hard cutting elements,
such as natural or synthetic diamonds, mounted to a bit body. As
the drag bit is rotated, the hard cutting elements scrape against
the bottom and sides of the borehole to cut away rock.
[0007] Another type of rotary rock drill is the roller cone bit.
These drill bits have rotatable cones mounted on bearings on the
body of the drill bit, which rotate as the drill bit is rotated.
Cutting elements, or teeth, protrude from the cones. The angles of
the cones and bearing pins on which they are mounted are aligned so
that the cones essentially roll on the bottom of the hole with
controlled slippage. One type of roller cone cutter is an integral
body of hardened steel with teeth formed on its periphery. Another
type has a steel body with a plurality of tungsten carbide or
similar inserts of high hardness that protrude from the surface of
the body somewhat like teeth. As the roller cone cutters roll on
the bottom of the hole being drilled, the teeth or carbide inserts
apply a high compressive load to the rock and fracture it. The
cutting action of roller cone cutters is typically by a combination
of crushing, chipping and scraping. The cuttings from a roller cone
cutter are typically a mixture of moderately large chips and fine
particles.
[0008] When drilling rock with a roller cone cutter, the fracture
effect of loading on the teeth of the rock bed is limited due to
the rock matrix surrounding the borehole. Failure of rock is
prevented in a large degree by the restraint to movement offered by
the surrounding rock. Thus, it appears in usual drilling operations
that small cracks are created in the rock, which return to the
surface of the bottom of the wellbore creating chips instead of
propagating deep into the rock itself. Thus, the bit tooth of the
usual rock bit presses on the rock surface tending to create small
cracks which propagate downward, but by virtue of the resistance to
fracture offered by the surrounding rock matrix, a crack follows
the path of least resistance and emerges at the surface on the
bottom of the wellbore, thus creating the small chips.
[0009] U.S. Pat. No. 3,055,443 to Edwards disclosed a combination
drag bit and roller cone cutter which removes the lateral restraint
on a core to be drilled. The drag bit component cuts a single
annular kerf forming a core which is received within a hollow body
member and drilled by multicone rolling cutters arranged within the
hollow body member. Windows are provided in the bit body adjacent
to the multicone cutters to provide an egress for chips formed by
the destruction of the core. This bit design causes rapid failure
of the drag cutters, however, since virtually all the drilling
fluid escapes through the windows and results in insufficient fluid
flow to cool the drag bit component.
[0010] U.S. Pat. No. 4,892,159 to Holster describes a kerf-cutting
bit wherein resistance of the rock to fracture is removed or
reduced by employing a drill bit which destroys the rock rapidly
and efficiently. The drill bit of Holster cuts multiple annular
kerfs which result in more rapid drilling rates than those achieved
by cutting a singular annular kerf.
[0011] U.S. Pat. No. 5,145,017 to Holster, et al, describes a
combination kerf-cutting bit and roller cone bit in which an
annular kerf ring is cut in advance of rolling cutter. An inner
kerf cutting structure is located internal to the annular kerf
ring. Rolling cone cutter are disposed between the kerfing
segments. Chipway ports are defined to improve the egress of rock
cuttings as they are generated at the bottom of the wellbore.
[0012] A primary disadvantage of the prior art designs is that they
are extremely difficult and expensive to manufacture. The
efficiency of a drill bit is determined by a well recognized "cost
per foot" equation. The equation is based on the cost of operating
the drilling rig, the "trip time" need to replace the drill bit at
a given depth, the rate of penetration of the drill bit, the life
of the drill bit, and the cost of the drill bit. Due to the
extremely high cost of manufacturing the prior art designs, they
have proven to be inefficient in a cost per foot analysis.
[0013] Another disadvantage of the prior art designs is the time
required for manufacturing the drill bits. In the drilling industry
today, there is significant pressure to keep inventory levels very
low. This is combined with the reality that drill bit selection
decisions are often made while drilling, in response to the
drilling rate achieved and the condition of the dull bit removed
from the hole. The prior art kerf-cutting hybrid bits having
combined kerf cutting segments and rolling cone cutters take far
too long to manufacture, and are far too expensive to keep in
inventory. The result is that they have become an impractical
choice for the oilfield drilling.
[0014] Another disadvantage of the prior art designs is that they
are less durable than required. The prior art designs combining
inner and outer kerfing segments wherein each cover the entire
circumference of the well bore. The assembly of rotating cone
cutting structures within the geometrical constraints of the fully
circumferential kerfing segments provides numerous challenges. For
example, prior art hybrid drilling bits utilize relatively smaller
bearing and seal systems which are less reliable when drilling
larger diameter holes. Similarly, the smaller cones present a
design constraint which require correspondingly smaller cutting
elements on the cones. As with the sealed bearing system, these
elements are less durable, and drill slower than the larger cutting
elements conventionally used when drilling wells of the same
diameter.
[0015] Another disadvantage of the prior art designs is that they
lack cutting removal ability, limiting the life of cutting elements
and rates of penetration at which the drill bits can operate, and
subjecting the bits to balling and premature failure.
SUMMARY OF THE INVENTION
[0016] The present invention is a significant improvement over that
described in the above enumerated prior art patents. The
improvements of the present invention relate to both the location
and relationship between cutting elements, as well as to the
design, construction and manufacture of the drill bit. A principal
advantage of the present invention is that it provides a drill bit
capable of drilling more efficiently than prior art designs
[0017] Another advantage of the present invention is that it
provides a hybrid bit design that is modular, permitting reduced
inventories of component parts for assembly of multiple
configurations of drill bits. Another advantage of the present
invention is that it provides a hybrid bit design that can be
assembled quickly, making the finished product deliverable faster
than prior art designs. Another advantage of the present invention
is that it provides a hybrid drill bit design that incorporates
larger component cutting elements and larger bearing and seal
systems which is more durable and drills faster.
[0018] Another advantage of the present invention is that it
provides a hybrid drill bit design having very large flow relief
area between the kerfing segments, allowing the bit to perform at
very high rates of penetration without cutting build-up and balling
of the bit. Other advantages of the present invention will become
apparent from the following descriptions, taken in connection with
the accompanying drawings, wherein, by way of illustration and
example, an embodiment of the present invention is disclosed.
[0019] In carrying out principles of the present invention, in
accordance with a preferred embodiment thereof, a modular kerfing
drill bit is disclosed, having a bit body with a threaded
connection for attachment to a drill string member at it's upper
end. A base portion is provided below the connection, having an
outside surface, and a bottom surface. At one or more slots are
formed in the base portion. A cutter assembly is provided having a
leg which is insertable into the slot of the bit body. A journal
extends downward and inward from a transition portion of the leg,
towards the center of the bit body. A cone is rotatably mounted on
the journal. A plurality of cutters are located extending outward
from the surface of the cone. A kerfing segment extends downward
from the leg, beyond the journal. A plurality of cutters are
positioned in the bottom of the kerfing segment.
BRIEF DESCRIPTION OF THE DRAWINGS
[0020] FIG. 1 is an isometric view of a preferred embodiment of the
present invention of a modular kerfing rock drilling bit in which
three cutter assemblies are employed.
[0021] FIG. 2 is an isometric view of a preferred embodiment of the
bit body of the present invention, with the cutter assemblies
unattached.
[0022] FIG. 3 is an isometric view of the cutter assembly disclosed
in FIG. 1, viewed in the direction of the center and lead faces of
the leg.
[0023] FIG. 4 is an isometric view of a cutter assembly of the
preferred embodiment illustrated in FIG. 3, viewed in the direction
of the back and lead faces of the leg.
[0024] FIG. 5 is a side view of the cutter assembly illustrated in
FIGS. 3 and 4, viewed in the direction of the center face of the
leg.
[0025] FIG. 6 is a side view of the cutter assembly illustrated
FIG. 5, rotated 90.degree. and viewed in the direction of the lead
face of the leg.
[0026] FIG. 7 is a side-sectional view of the cutter assembly
illustrated in FIG. 6.
[0027] FIG. 8 is a side view of the preferred embodiment of the
present invention illustrated in FIG. 1, viewed in the direction of
the back face of a leg.
[0028] FIG. 9 is a side view of the preferred embodiment of the
present invention illustrated in FIG. 8, with the drill bit rotated
60.degree., and viewed in the direction between cutter
assemblies.
[0029] FIG. 10 is a bottom view of the preferred embodiment
illustrated in FIGS. 1-3.
[0030] FIG. 11 is a top view of the preferred embodiment
illustrated in FIGS. 1-4, showing the fluid channels internal to
the bit body.
[0031] FIG. 12 is an isometric view of an alternative embodiment of
the present invention of a modular kerfing rock drilling bit, in
which a single cutter assembly is employed in combination with two
kerfing assemblies.
[0032] FIG. 13 is an isometric view of a kerfing assembly of the
alternative embodiment disclosed in FIG. 12, shown disengaged from
the body.
[0033] FIG. 14 is a side view of the alternative embodiment
disclosed in FIG. 12, and viewed in the direction between kerfing
assemblies.
[0034] FIG. 15 is a bottom view of the alternative embodiment of
the present invention disclosed in FIG. 12.
DETAILED DESCRIPTION OF THE INVENTION
[0035] FIG. 1 is an isometric view of a preferred embodiment of the
present invention for a Modular Kerfing Drill Bit 10. In the
embodiment shown, drill bit 10 has a body 12. Body 12 has a
connection 14 for attachment to a drill string member (not shown).
Body 12 has a base 16 below connection 14 and contiguous thereto.
Cutter assemblies 100 are shown attached to body 12.
[0036] FIG. 2 is an isometric view of a preferred embodiment of bit
body 12 of the present invention, shown with cutter assemblies 100
unattached. In this view, it is seen that base 16 has a generally
cylindrical outer portion 18 and a bottom 20. Slots 22 are formed
in base 16, and intersect both outer portion 18 and bottom 20.
Slots 22 are formed for secure location of cutter assemblies 100.
Also in body 12, ports 24 are provided, and interconnect to
internal passage 26 (dashed line).
[0037] FIG. 3 is an isometric view of a preferred embodiment of a
cutter assembly 100. Cutter assembly 100 has a leg 110. Leg 110 has
a lead face 112 and an opposite trailing face 114 (best seen in
FIG. 8). Leg 110 has a center face 116 and an opposite back face
118 (best seen in FIG. 4). Leg 110 has a bottom face 120 and a
transition face 122. A journal 126 (not visible in this view)
extends downward, substantially perpendicular to transition face
122.
[0038] FIG. 4 is another isometric view of cutter assembly 100
illustrated in FIG. 3, viewed in the direction of back face 118 and
lead face 112 of leg 110. In this view, it is seen that a reservoir
cap 128 is located on back face 118 of leg 110. In the preferred
embodiment, reservoir cap 128 encloses an internal lubrication
system 130 (best seen in FIG. 7). Also in the preferred embodiment
illustrated, a plurality of gage buttons 132 are located on back
face 118. Also in the preferred embodiment illustrated, a
stabilizer pad 134 is provided below back face 118 on leg 110.
[0039] Still referring to FIG. 4, an external junk channel 136 is
disposed circumferentially above stabilizer 134. Cutter assembly
100 has a kerfing segment 140 extending downward from junk channel
136. In a less preferred embodiment, kerfing segment 140 extends
downward from stabilizer 134.
[0040] Kerfing segment 140 supports a plurality of kerf cutters 142
mounted in cutter supports 144. Referring to FIG. 4, in the
preferred embodiment, annular junk slots 146 are vertically
disposed between cutter supports 144, and merge with junk channel
136.
[0041] In a specifically preferred embodiment, kerf cutters 142 are
synthetic diamond cutting elements. Specific examples of these
types of cutting elements include polycrystalline diamond compacts
(PDC's) and thermally stable diamond compacts (TSP's). There are
numerous material and geometric variations of these products that
are well known and readily available in the drilling industry. In a
less preferred embodiment, kerf cutters 142 are natural
diamonds.
[0042] FIG. 5 is a side view of cutter assembly 100 illustrated
also in FIG. 3 and 4. In FIG. 5, cutter assembly 100 is viewed from
the center of drill bit 10. Referring to FIG. 5, (see also FIG. 3),
an internal flow channel 150 is disposed circumferentially above
transition face 122. Kerfing segment 140 extends downward from flow
channel 150. Internal flow slots 152 are vertically disposed
between cutter supports 144, and merge with flow channel 150.
[0043] As can be seen in FIG. 5, cutter supports 144 support kerf
cutters 142 in an angular deployment. This configuration provides a
flow passage 154 between kerf cutters 142, and connects internal
flow slots 152 to external junk slots 146.
[0044] FIG. 6 is a side view of cutter assembly 100 illustrated
FIG. 5, rotated 90.degree. and viewed in the direction of lead face
112 of leg 110. FIG. 7 is a side-sectional view of cutter assembly
100 illustrated in FIG. 6. As seen in FIG. 6 and FIG. 7, a cone 180
is rotatably mounted on journal 126. Cone 180 has a plurality of
teeth 182 attached to it. In the preferred embodiment, teeth 182
are interference fit within holes predrilled in cone 180. Also in
the preferred embodiment, teeth 182 are made of a material
substantially harder than the formation to be drilled, such as
sintered tungsten carbide.
[0045] As can also be inferred from FIG. 7, internal lubrication
system 130 is contiguous to the external surface of journal 126 and
the internal surface of cone 180, so as to provide lubrication
between journal 126 and cone 180.
[0046] FIG. 8 is a side view of drill bit 10, viewed in the
direction of back face 118 of leg 110. From this view, it can be
seen that a large clearance is provided between trailing face 114
of one cutter assembly 100 and lead face 112 of the adjacent cutter
assembly 100. FIG. 9 is a side view of the preferred embodiment of
drill bit 10, as illustrated in FIG. 8, with drill bit 10 rotated
60.degree., and viewed in a direction between cutter assemblies
100. FIG. 10 is a bottom view of the preferred embodiment
illustrated in FIGS. 1-3. In the preferred embodiment,
interchangeable nozzles 28 are removably connectable to ports
24.
[0047] FIG. 11 is a top view of the preferred embodiment of drill
bit 10. In this view, it is seen that cones 180 have dissimilar
cutting structures such that combined, they can rotate without
interfering, and can best cover the bottom of the wellbore. This is
noted by the designation of each cone 180 with a different
alphanumeric suffix a through c.
[0048] Similarly, in the preferred embodiment, each kerf cutter 142
on a given cutter assembly 100 is located at a different radial
distance to the center of drill bit 10. This is noted by the
designation of each kerf cutter 142 with a different alphanumeric
suffix a through c, with a designating the innermost kerf cutter
142 and c designating the outermost kerf cutter 142. In this
manner, drill bit 10 can be specifically designed so that the
combined physical forces acting on the combined cutters 142 and 182
on any given cutter assembly 100 are collectively, substantially
equal. This provides a drill bit 10 that operates more
efficiently.
[0049] FIG. 12 is an isometric view of an alternative embodiment of
the present invention for a modular kerfing rock drilling bit 11,
in which drill bit 11 incorporates a single cutter assembly 100
having a rotating cone 180 with teeth 182. In this embodiment
shown, drill bit 10 has a body 12. Body 12 has a connection 14 for
attachment to a drill string member (not shown). Body 12 has a base
16 below connection 14 and contiguous thereto. Unique to this
embodiment, a single cutter assembly 100 is shown attached to body
12. A pair of kerfing assemblies 200 are attached to bit body 12 in
place of cutter assemblies 100.
[0050] FIG. 13 is an isometric view of kerfing assembly 200
disclosed in FIG. 12, shown detached from bit body 12 of drill bit
11. Kerfing assembly 200 has a leg 210. Leg 210 has a lead face 212
and an opposite trailing face 214 (best seen in FIG. 14). Leg 210
has a center face 216 and an opposite back face 218 (best seen in
FIG. 14). Leg 210 has a bottom face 220 and a transition face 222.
Unlike cutter assemblies 100, there is no journal 126 extending
from transition face 222, and no cone 182 having teeth 184 mounted
thereon.
[0051] Referring back to FIG. 2, bit body 12 of previously
disclosed can readily serve as bit body 12 of the alternative
embodiment, shown with cutter assembly 100 and kerfing assemblies
200 unattached. In this view, it is seen that base 16 has a
generally cylindrical outer portion 18 and a bottom 20. Slots 22
are formed in base 16, and intersect both outer portion 18 and
bottom 20. Slots 22 are formed for secure locations of cutter
assembly 100 and kerfing assemblies 200. Also, in body 12, ports 24
are provided, and interconnect to internal passage 26 (dashed
line).
[0052] FIG. 14 is a side view of the alternative embodiment of
drill bit 11 disclosed in FIG. 12, viewed in the direction between
kerfing assemblies 200, and having cutter assembly 100 and kerfing
assemblies 200 attached in slots 22 of bit body 12. From this view,
it can be seen that a large clearance is provided between trailing
face 214 of one kerfing assembly 200 and lead face 212 of the
adjacent kerfing assembly 200.
[0053] FIG. 15 is a bottom view of the embodiment of drill bit 10
disclosed in FIG. 12. In this view, it can be seen that cone 180
has teeth 182, and is the only rolling cutting element on drill bit
11.
[0054] The foregoing detailed description is to be clearly
understood as being given by way of illustration and example, the
spirit and scope of the present invention being limited solely by
the appended claims.
OPERATION OF THE INVENTION
[0055] As seen in FIG. 1, the preferred embodiment of Modular
Kerfing Drill Bit 10 of the present invention is unique and vastly
different from the prior art kerfing bit designs. Prior art designs
are consistent in having fully circumference kerfing rows with
cutters uniformly distributed thereon. The present design departs
radically from this concept.
[0056] As seen in FIG. 2, body 12 is comprised of base 16 extending
from bottom 20. Bottom 20 is preferable a threaded connection such
as an API connection as is well known in the drilling industry.
Bottom 20 is thus suitable for secure connection to a drill collar,
bit sub, or other drilling tool. The inside of body 12 provides
internal passage 26 which is connected to ports 24 located on
bottom surface 20 of body 12.
[0057] Internal passage 26 and ports 24 provide a passageway for
drilling fluid. Since drilling fluid is most advantageously
provided at high velocity, in the preferred embodiment, ports 24
are receivable of interchangeable nozzles 28 made of a hard metal,
such as tungsten carbide, or titanium carbide (see FIG. 10 and FIG.
15). The hardness of the hard metal nozzles provides wear
resistance to the abrasive forces associated with the high-velocity
flow of the drilling fluid through the constricted diameter of the
nozzles. In this embodiment, nozzles 28 can be interchangeably
selected based on known operating parameters to optimize the
hydraulic benefit of the drilling fluid on the performance of drill
bit 10.
[0058] Body 12 has at least one slot 22 formed on base 16. Slots 22
intersect outer portion 18 and bottom 20. Slots 22 provide a secure
location for cutter assemblies 100, and/or kerfing assemblies
200.
[0059] Cutter assembly 100 is shown in FIGS. 3-6, unattached to
body 12. Cutter assembly 100 has a leg 110. Leg 110 has a lead face
112 (FIG. 3) and an opposite trailing face 114 (best seen in FIG.
8). The reference to lead and trailing indicate the normal
direction of rotation of the drill string and drill bit 10. Leg 110
also has a center face 116 (FIG. 5) and an opposite back face 118
(FIG. 4). Leg 110 also has a bottom face 120 and a transition face
122. Lead face 112, trailing face 114, and bottom face 120 are
dimensionally and geometrically configured to fit in close
tolerance within slots 22 of body 12. This is seen in FIG. 1.
[0060] As seen in FIG. 1, and also in FIGS. 8-10, legs 10 of cutter
assemblies 100 extend radially outwards from outer portion 18 of
base 16. As is clearly visible in FIG. 10, this provides a very
large annular opening for the vertical passage of cutting laden
drilling fluid between cutter assemblies 100, body 12 and the side
wall of the well bore. The size of this passage far exceeds the
passage found in conventional kerfing bit designs, and thus
resolves a principal disadvantage of the prior designs which rely
on full circumference bit bodies and kerf cutter
configurations.
[0061] In the paragraph above, and herein below, the terms
"vertical" and "horizontal" used in reference to the direction of
drilling fluid flow are made in reference to the central axis of a
vertically drilled well. This reference is made by way of example
only, for the purpose of understanding the operation of the
invention. The reference is not intended as a limitation. The
present invention is capable of directional drilling operations in
any direction, including horizontally.
[0062] The preferred embodiment illustrated discloses drill bit 10
having three slots 22 in body 12, for accommodation of three cutter
assemblies 100. In another preferred embodiment not shown, drill
bit 10 has two slots 22 in body 12 for accommodation of two cutter
assemblies 100. In another preferred embodiment not shown, drill
bit 10 has four slots 22 in body 12 for accommodation of a
combination of cutter assemblies 100 and kerfing assemblies 200. In
still another preferred embodiment, drill bit 10 has one slot 22 in
body 12 for accommodation of one cutter assembly 100.
[0063] Each cutter assembly 100 has a cylindrical journal 126
extending from transition face 122. In the preferred embodiment,
journal 126 extends downward, substantially perpendicular to
transition face 122. A cone 180 is mounted to each journal 126.
Cone 180 may be mounted to journal 126 in the manner known for
mounting cones to journal in conventional rotary drilling bits,
using legs 110 in exchange for rotary drill bit sections, which
normally include the base 16 and connection 14 portions as well.
Cones 180 have teeth 182 located about the outer surface of cone
180.
[0064] As seen in FIG. 7, a lubrication system 130 may be located
in leg 110 to provide a lubricant between rotatable cone 180 and
journal 126. Lubrication system 130 may include a lubricant
reservoir and pressure compensation means beneath a reservoir cap
128. In the preferred embodiment, reservoir cap 128 is located on
back face 118 of leg 110. As drill bit 10 experiences increases in
pressure at deeper well depths, or in response to increases in
drilling fluid density, the pressure compensation means adjusts the
pressure of the lubricant between rotatable cone 180 and journal
126, to prevent drilling fluid from entering between rotatable cone
180 and journal 126, and causing failure of the bearing
relationship between them.
[0065] In the preferred embodiment illustrated, teeth 182 are
tungsten carbide inserts, press fit into cone 180. Teeth 182 may be
made of other materials and may be otherwise attached to cones 180.
As an example, teeth 182 may be machined from the cone material.
Teeth 182 may include a hard material deposited on them to increase
their wear resistance. In the preferred embodiment, a plurality of
gage buttons 132 are located on back face 118 to protect leg cutter
assembly 100 from abrasive wear resulting from contact with side of
the well bore. This location of gage buttons 132 provides
particular protection to reservoir cap 128.
[0066] Beneath gage buttons 132, a stabilizer section 134 extends
outward from back face 118 of leg 110. Stabilizer 134 acts to
stabilize and center drill bit 10 in the well bore during rotary
drilling operations, increasing drilling rate and drill bit life by
assisting drill bit 10 to drill a true and centered well bore.
Since the present invention lacks full circumference kerfing
sections, stabilizer 134 can extend the full width of leg 110, and
still provide vertical passage for cutting laden drilling fluid.
This capability substantially simplifies the manufacturing process
of drill bit 10.
[0067] As seen in FIG. 4, external junk channel 136 is disposed
circumferentially above stabilizer 134 providing horizontal passage
for cutting laden drilling fluid, interlaced with the vertical
passage provided between cutter assemblies 100.
[0068] Referring to FIG. 4, kerfing segment 140 extends downward
from junk channel 136. Kerfing segment 140 supports a plurality of
kerf cutters 142 mounted in cutter supports 144. Annular junk slots
146 are vertically disposed between cutter supports 144. Annular
junk slots 146 provide vertical passage for cutting laden drilling
fluid between individual kerf cutters 142, and are interlaced with
horizontally disposed junk channel 136, which is in turn interlaced
with the vertical passage provided between cutter assemblies
100.
[0069] Kerf cutters 142 are primarily shear cutting elements that
also impart compressive forces to fail the formation being drilled.
As a result of this process, high flow rates of drilling fluid at
the kerf cutter 142 and formation interface are preferable to lower
flow rates. This helps removes the cuttings and lower the
temperature at the interface of kerf cutter 142 and the formation.
It is detrimental to performance when the cuttings generated by
kerf cutters 142 and teeth 182 are limited in their ability to
escape from the center of drill bit 10 (or 11) to the annular
section of the well bore surrounding drill bit 10 (or 11).
[0070] Teeth 182 on cones 180 are primarily compressive cutting
elements, that also impart shear forces to fail the formation being
drilled. As a result of this process, high jet impact forces
imparted to the hole face being drilled are preferable to lower
impact forces. The higher impact forces help dislodge cuttings and
prevents re-drilling the chips that remain on the formation
face.
[0071] Notwithstanding the optimization requirements of kerf
cutters 142 and teeth 182 of cones 180, it is further noted that
drilling systems are limited in the amount pressure their equipment
can tolerate. Selecting smaller nozzles to increase jet impact
forces beneficial to teeth 182 increases the drilling system
operating pressure. Increasing pump speed to achieve flow rates
beneficial to kerf cutters 142 likewise increases the drilling
system operating pressure.
[0072] Thus, it is advantageous to be able to interchangeably
select nozzles 28, and to have a contiguous connections between
relief's on bit 10 (or 11) sufficient to readily permit removal of
the cuttings generated by bit 10 (or 11). The present invention
accomplishes this. First, there are interchangeable nozzles 28
connectable to ports 24. Second, there is a contiguous mesh of
vertically and horizontally oriented flow channels and flow slots
that being near nozzles 28 on the internal portions of legs 110 and
continue to the outer portions of legs 110. Third, the contiguous
mesh is interconnected to very large annular spaces provided
between cutter assemblies 100 (and kerfing assemblies 200) in the
modular, non-circumferential design of drill bit 10 (and 11).
[0073] FIG. 5 is a side view of cutter assembly 100 illustrated
also in FIG. 3 and 4. In FIG. 5, cutter assembly 100 is viewed from
the center of drill bit 10. Referring to FIG. 5, (see also FIG. 3),
an internal flow channel 150 is disposed circumferentially above
transition face 122, in the immediate proximity of where cuttings
will be generated by teeth 182 on cone 180. Kerfing segment 140
extends downward from flow channel 150. On the inside of kerfing
segment 140, internal flow slots 152 are vertically disposed
between cutter supports 144, and merge with flow channel 150.
[0074] As can be seen in FIG. 5, cutter supports 144 support kerf
cutters 142 in an angular deployment. This configuration provides
flow passages 154 between kerf cutters 142, which connect internal
flow slots 152 to external junk slots 146. This is best seen in
FIG. 4, which also illustrates external junk slots 146 merged to
junk channel 136, which is itself contiguous with both lead face
112 and trailing face 114 of leg 110. Lead face 112 and trailing
face 114 of leg 110 define the boundaries of the large annular
relief between cutter assemblies 100.
[0075] FIG. 9 is a side view of drill bit 10, as viewed between
adjacent cutter assemblies 100. From this view, the large annular
clearance provided between trailing face 114 of one cutter assembly
100 and lead face 112 of the adjacent cutter assembly 100 is
clearly visible.
[0076] Likewise, in the alternative embodiment for drill bit 11,
seen in FIG. 13, kerfing assemblies 200 have an internal flow
channel 250 is disposed circumferentially above transition face
222. Kerfing segment 240 extends downward from flow channel 250. On
the inside of kerfing segment 240, internal flow slots 252 are
vertically disposed between cutter supports 244, and merge with
flow channels 250.
[0077] Flow passages 254 between kerf cutters 142, connect internal
flow slots 252 to external junk slots 246. This is best seen in
FIG. 12, which also illustrates external junk slots 146 merged to
junk channel 236, which is itself contiguous with both lead face
212 and trailing face 214 of leg 210. Lead face 212 and trailing
face 214 of leg 210 define the boundaries of the large annular
relief between kerfing assemblies 200, and between kerfing
assemblies 200 and cutter assembly 100.
[0078] FIG. 7 is a side-sectional view of cutter assembly 100. As
can also be inferred from FIG. 7, internal lubrication system 130
is contiguous to the external surface of journal 126 and the
internal surface of cone 180, so as to provide pressure neutralized
lubrication between journal 126 and cone 180, and to prevent the
intrusion of drilling fluid between journal 126 and cone 180, in
the manner that is well known in the industry.
[0079] FIG. 14 is a side view of alternative embodiment drill bit
11, as viewed between adjacent kerfing assemblies 200. From this
view, the large annular clearance provided between trailing face
214 of one kerfing assembly 200 and lead face 212 of the adjacent
kerfing assembly 200 is clearly visible.
[0080] FIG. 10 is a top view of the preferred embodiment of drill
bit 10. In this view, it is seen that cones 180 have dissimilar
cutting structures such that combined, they can rotate without
interfering, and can best cover the bottom of the wellbore. This is
noted by the designation of each cone 180 with a different
alphanumeric suffix a through c.
[0081] Similarly, in the preferred embodiment, each kerf cutter 142
on a given cutter assembly 100 is located at a designated radial
distance to the center of drill bit 10, known as the radial
position of the kerf cutter 142. The radial position of each kerf
cutter 142 may be unique. This is noted by the designation of each
kerf cutter 142 with a different alphanumeric suffix a through c,
with a designating the innermost kerf cutter 142 and c designating
the outermost kerf cutter 142. In this manner, drill bit 10 can be
specifically designed so that the combined physical forces acting
on the combined cutters 142 and 182 on any given cutter assembly
100 are collectively, substantially equal. This provides a drill
bit 10 that operates more efficiently. Due to the modular
construction of drill bit 10, modification can be made on the basis
of test and/or field results with minimal disruption to the
manufacturing process.
[0082] FIG. 15 is a top view of the preferred embodiment of drill
bit 11. In this view, it is seen that cone 180 is considerably
larger than cone 180 of drill bit 10. In this embodiment, cone 180
and teeth 182 will drill substantially the entire well face
internal to the placement of kerf cutter 142. The larger structure
of a single cone 180 provides substantial design flexibility
related to the larger components associated with a single cone bit,
since cone size is reduced relative to hole size to accommodate
outer diameter kerf cutters 142. Also, the larger structure of a
single cone 180 provides substantial design as associated with the
different performance characteristic of a single cone drill bit
11.
[0083] Moreover, the modular design of the present invention, while
disclosed in detail a three-cone embodiment drill bit 10 and a
one-cone embodiment drill bit 11, it can easily be configured to
accommodate two cutting assemblies 100 and a single kerfing
assembly 200. Likewise, by adding or removing slots 22 on body 12,
other combinations of cutter assemblies 100 and kerfing assemblies
200 can be created.
[0084] The foregoing detailed description is to be clearly
understood as being given by way of illustration and example, the
spirit and scope of the present invention being limited solely by
the appended claims.
* * * * *