Note: Descriptions are shown in the official language in which they were submitted.
BI-DIRECTIONAL "REAM ON CLEAN" WELLBORE REAMER TOOL
Field of the Invention
[0001] The present invention relates to tools for drilling a wellbore in a
formation, and more
particularly to a bi-directional "ream on clean" wellbore reamer tool.
Background of the Invention
[0002] A wellbore reamer is a rotary cutting tool used for drilling oil and
gas wells to enlarge
the diameter of a wellbore being drilled through a subsurface formation to a
specified size,
smooth the wall of the wellbore, help stabilize the bottom hole assembly,
straighten the wellbore
if kinks or doglegs are encountered, and drill directionally. The reamer
rotates about a
longitudinal axis of the drill string. The reamer includes cutting structures
for enlarging the
diameter of the wellbore in a subterranean formation by shearing, crushing,
and/or cracking
wellbore walls of the formation during rotation of the drill string. In use,
high forces are exerted
on the cutting structures, particularly in the forward-to-rear direction. Over
time, the working
surface or cutting edge of each cutter that continuously contacts the
formation eventually wears
down and/or fails.
[0003] Further, the quality of the wellbore produced when drilling can have a
dramatic impact
on the total well construction time and cost and sometimes can even determine
success or failure.
Wellbore quality is generally related to the "smoothness" of the wellbore or
the "tortuosity."
Tortuosity refers to undesirable deviations from the planned wellbore
trajectory, corresponds to
wellbore irregularities or oscillations, and can take many shapes, such as
spiraling, rippling and
hour-glassing. Spiraling occurs when the center of the drill bit follows a
more or less helical
path around the true centerline of the planned wellbore trajectory. A spiraled
wellbore has a
significant impact on drilling efficiency and cost. "Micro-tortuosity" refers
to the induced
deviation from the planned wellbore trajectory while drilling at a much
smaller survey interval,
typically every one to three feet, and is visible only when using a high
resolution survey tool
recorded at approximately one survey per foot. In the absence of any specific
technology to
1
Date Recue/Date Received 2021-03-12
improve the quality of the wellbore, there is little recognition of the
potential benefits that might
be achieved should some reamer tool be available for drilling a "truer"
wellbore, one that
followed a straighter line or smoother arc with minimal deviation. Reduction
or elimination of
tortuosity is widely regarded by those skilled in the art as a significant
success factor in drilling
operations.
[0004] Further, such problems contribute to the increment of the friction
factor while drilling.
The friction factor can be considered as the force resisting the relative
rotation and downhole or
uphole motion of the drill string. A high friction factor means a further
degradation of the
drilling conditions as the tool is working under high levels of drag and
torque. Conversely, a low
friction factor characterizes a high-quality wellbore with a smooth path which
is desirable before
running casing on the wellbore. Some downhole reamers are meant for "dedicated
reamer run,"
meaning that once the hole is drilled, the operator pulls the drill string out
of the hole to replace
the downhole tools and to include a "dedicated reamer" on the drill string to
conditionate the
wellbore before running casing. The "reaming while drilling technology" allows
use of a
specifically designed downhole reamer to ream the wellbore while drilling is
in progress. Such
reamers have been proven to reduce friction during drilling operations, and
obviate the need for a
dedicated reamer run after reaching total depth. Those skilled in drilling
operations are familiar
with the effect of cuttings settling on the lower side of the wellbore once
the flow or the rotation
has ceased. By resuming drilling operations, the cuttings already settled
start to move slowly to
surface once rotation is provided to the drill string and a flow rate is re-
established. Usually
cutting structures in other reamers are required to work through the cuttings
domes and do not
have clear access to the wellbore walls during certain time periods, which not
only reduces the
effectiveness of the tool but also increases the torque as more friction is
added.
Summary of the Invention
[0005] The present invention relates to a wellbore reamer tool used in
downhole oil well
operations, specifically in reaming while drilling applications without
distinction between back
reaming operations and front reaming operations. In particular, the present
invention relates to a
bi-directional "ream on clean" wellbore reamer tool featuring a unique "ream
on clean
2
Date Recue/Date Received 2021-03-12
technology" as will be described herein. As used herein, the term "bi-
directional" refers to the
tool's capacity to shear the wellbore in back reaming operations and front
reaming operations.
As used herein, the terms "ream" and "reaming" refer to enlarging the diameter
of a wellbore
being drilled through a subsurface formation to a desired size and smoothing
the radial wall of
the wellbore. As used herein, the terms "ream on clean technology" or "ream on
clean" refer to
the tool's capacity to expose the clean wellbore surface to the cutting
inserts as a downhole
impeller has placed the cuttings settlements back in circulation. A wellbore
surface clean of
cuttings and debris before reaming improves the cutting action of the cutting
inserts which will
subsequently ream on a clean wellbore.
[0006] In addition, the wellbore reamer tool includes several beneficial
features, notably two
helical impellers, two cutting portions, and an integral blade stabilizer. The
first helical impeller
is positioned at a downhole end for lifting and directing uphole flow of
formation cuttings to a
precise position between the blades of the first cutting portions. The first
helical impeller
provides a wellbore clean of cuttings and debris before reaming in order to
improve the cutting
action of the cutting inserts which will subsequently ream on a clean
wellbore. The cutting
portions define pockets for mounting radially insertable and field replaceable
cutting inserts
comprising cutters for reaming the wellbore to yield the formation cuttings.
An integral
stabilizer comprising "S"-shaped stabilizer blades is positioned between the
cutting portions for
providing radial and tilt support while driving the formation cuttings uphole.
The second helical
impeller is positioned above the second cutting portions for boosting newly
incorporated
formations cuttings generated by the cutting portions uphole towards surface.
[0007] Broadly, in one aspect, the invention comprises a wellbore reamer tool
positionable on
a drill string in a wellbore comprising:
a first helical impeller positioned at a downhole end for cleaning the
wellbore of
formation cuttings in advance of reaming by first and second cutting portions,
and directing the
formation cuttings to a desired position on the first cutting portions;
the first and second cutting portions comprising a plurality of radially
insertable cutter
inserts comprising cutters for reaming the wellbore to yield the formation
cuttings;
3
Date Recue/Date Received 2021-03-12
an integral blade stabilizer positioned between the first and second cutting
portions for
supporting the tool while driving uphole flow of the formation cuttings; and
a second helical impeller positioned above the second cutting portions for
cleaning the
wellbore and boosting newly incorporated formations cuttings uphole towards
surface.
[0008] In some embodiments, the tool further comprises a downhole end
having a
threaded pin connection for coupling to a bottom hole assembly or a drill
pipe, and an uphole end
having a threaded box connection for coupling to the drill string.
[0009] In some embodiments, the tool further comprises downhole spiral
hardbands
positioned at the downhole end and uphole spiral hardbands positioned at the
uphole end for
proving erosion protection.
[00010] In some embodiments, each of the first helical impeller and the
second helical
impeller comprises a plurality of helical blades and helical grooves between
the helical blades for
allowing uphole flow of formation cuttings therethrough.
[00011] In some embodiments, the helical blades comprise odd blades and
even blades,
the even blades comprising straight-edged extension blades.
[00012] In some embodiments, each of the first and second cutting portions
comprises a
bladed portion defining a plurality of pockets configured for mounting cutter
inserts and wedge
retainers.
[00013] In some embodiments, the bladed portion comprises a plurality of
substantially
straight-edged and axially extending blades spaced evenly and radially around
the bladed portion
about a central longitudinal axis of the tool.
[00014] In some embodiments, the pockets are spaced evenly and radially
around the
bladed portion about the central longitudinal axis, and positioned between the
blades.
4
Date Recue/Date Received 2021-03-12
[00015] In some embodiments, the pockets comprise rims defining notches,
opposed end
walls, opposed side walls, and bases for seating the cutter inserts, the bases
defining apertures for
receiving attachment means therethrough for securing the cutter inserts within
the pockets.
[00016] In some embodiments, the cutter inserts are positioned within the
pockets, and
spaced evenly and radially around the bladed portion about the central
longitudinal axis, and
positioned between the blades.
[00017] In some embodiments, each cutter insert comprises a cutter insert
body defining a
first recess and a second recess configured for receiving the cutters, the
cutters being arranged
linearly in an inner row and an outer row and inclined at a predetermined
angle.
[00018] In some embodiments, each of the first and second recesses is
aligned
substantially parallel to each other, with the second recess being positioned
below the first
recess.
[00019] In some embodiments, the cutters are evenly spaced apart in the
first recess to be
positioned in an alternating fashion with the cutters evenly spaced apart in
the second recess.
[00020] In some embodiments, the cutters comprise polycrystalline diamond
compact
cutters.
[00021] In some embodiments, the cutter insert is secured within the
pocket by fixedly
attaching the wedge retainers to the bladed portion.
[00022] In some embodiments, a wedge retainer is positioned at each end of
the cutter
insert body, and defines openings corresponding with the apertures in the
bases of the pockets for
receiving attachment means for securing the cutter insert to the blade
portion.
Date Recue/Date Received 2021-03-12
[00023] In some embodiments, the integral blade stabilizer comprises a
plurality of
substantially "S"-shaped stabilizer blades, and an outer diameter larger than
outer diameters of
the first cutting portion and the second cutting portion.
[00024] In another aspect, the invention comprises a method of enlarging a
wellbore
diameter comprising:
positioning in the wellbore a drill string including a wellbore reamer tool
attached
thereto, the wellbore reamer tool including:
a first helical impeller positioned at an downhole end;
first and second cutting portions comprising a plurality of radially
insertable
cutter inserts comprising cutters;
an integral blade stabilizer positioned between the first and second cutting
portions; and
a second helical impeller positioned above the second cutting portions; and
moving the drill string and the wellbore reamer tool longitudinally in the
wellbore while
rotating the drill string and the wellbore reamer tool.
[00025] In some embodiments, the method further comprises rotating the
first helical
impeller to clean the wellbore of formation cuttings in advance of reaming by
the first and
second cutting portions.
[00026] In some embodiments, the cutters engage and ream the radial wall
of the wellbore
to generate the formation cuttings, with an inner row of the cutters reaming
before an outer row
of the cutters.
[00027] In some embodiments, the method further comprises rotating the
integral blade
stabilizer for driving uphole flow of the formation cuttings while supporting
the wellbore reamer
tool.
6
Date Recue/Date Received 2021-03-12
[00028] In some embodiments, the method further comprises rotating the
second helical
impeller for cleaning the wellbore and boosting newly incorporated formations
cuttings uphole
towards surface.
[00029] Additional aspects and advantages of the present invention will be
apparent in
view of the description, which follows. It should be understood, however, that
the detailed
description and the specific examples, while indicating preferred embodiments
of the invention,
are given by way of illustration only, since various changes and modifications
within the scope
of the invention will become apparent to those skilled in the art from this
detailed description.
Brief Description of the Drawings
[00030] The invention will now be described by way of an exemplary
embodiment with
reference to the accompanying simplified, diagrammatic, not-to-scale drawings.
In the drawings:
[00031] FIG. 1 (PRIOR ART) is a schematic partial cross-sectional
elevation view of an
example well system.
[00032] FIG. 2 is a perspective view of one embodiment of a wellbore
reamer tool of the
present invention.
[00033] FIG. 3 is a schematic perspective view of downhole spiral
hardbands of the
wellbore reamer tool of FIG. 2.
[00034] FIG. 4 is a schematic perspective view of a first helical impeller
and a first cutting
portion of the wellbore reamer tool of FIG. 2.
[00035] FIG. 5 is perspective view of a portion of the first helical
impeller of FIG. 4, with
arrows representing the flow of cuttings within helical grooves defined by odd
and even helical
blades of the first helical impeller.
7
Date Recue/Date Received 2021-03-12
[00036] FIG. 6 is a perspective view of the first cutting portions and the
first helical
impeller of FIG. 4, with an arrow representing the combined flow of cuttings
from the first
helical impeller being directed uphole towards the first cutting portion.
[00037] FIG. 7 is a perspective view of the first cutting portions of the
wellbore reamer
tool of FIG. 2, showing the cutting insert before assembly into the first
cutting portions.
[00038] FIG. 8 is a cross-sectional transverse view of the first cutting
portions of FIG. 7
before assembly of three cutting inserts, and the wellbore wall shown in
phantom.
[00039] FIG. 9 is a perspective view of the first cutting portions of the
wellbore reamer
tool of FIG. 2, showing the cutting inserts assembled into the first cutting
portions.
[00040] FIG. 10 is a cross-sectional transverse view of the first cutting
portions of FIG. 9
with three cutting inserts assembled into the first cutting portions, and the
wellbore wall shown
in phantom.
[00041] FIG. 11 is an exploded perspective view of a radially insertable
cutting insert
including inner and outer rows of cutters, a pair of wedge retainers, and
attachment means.
[00042] FIG. 12 is a front perspective view of a cutter insert showing
inner and outer rows
of cutters.
[00043] FIG. 13 is a cross-sectional transverse view of the cutting
portions, showing the
positioning of the inner and outer rows of cutters of FIG. 12 in relation to
the body of the cutting
portions, and the wellbore wall shown in phantom.
[00044] FIG. 14 is an exploded cross-sectional transverse view of a
cutting portion of FIG.
13, showing the working diameter for the inner and outer rows of cutters and
the wellbore wall
shown in phantom.
8
Date Recue/Date Received 2021-03-12
[00045] FIG. 15 is a schematic representation of axial displacement of the
cutting inserts
in the cutting portions of FIG. 13 for progressive exposure of the reaming
surfaces.
[00046] FIG. 16 is a perspective view of an integral blade stabilizer of
the wellbore reamer
tool of FIG. 2.
[00047] FIG. 17 is a cross-sectional transverse view of the integral blade
stabilizer of FIG.
15, showing the working maximum diameter of the stabilizer and the wellbore
wall diameter
both in phantom.
[00048] FIG. 18 is a perspective view of second cutting portions and a
second helical
impeller of the wellbore reamer tool of FIG. 2.
Detailed Description of Preferred Embodiments
[00049] NOTATION AND NOMENCLATURE
[00050] Certain terms are used throughout the following description and
claims to refer to
particular components and configurations. As one of ordinary skill will
appreciate, companies
may refer to a component by different names. This document does not intend to
distinguish
between components that differ in name but not function. In the following
discussion and in the
claims, the singular forms "a," "an," and "the" include plural referents
unless the context clearly
dictates otherwise. The terms "including," "comprises," and "comprising" are
used in an open-
ended fashion, and thus should be interpreted to mean "including, but not
limited to...", and as
referring to elements, components, or steps in a non-exclusive manner,
indicating that the
referenced elements, components, or steps may be present, or utilized, or
combined with other
elements, components, or steps that are not expressly referenced. Also, the
term "couple,"
"couple," or "coupling" is intended to mean either a direct or indirect
physical connection, an
indirect connection as being through other components. In interpreting the
disclosure, all terms
should be interpreted in the broadest possible manner consistent with the
context.
9
Date Recue/Date Received 2021-03-12
[00051] The disclosure may repeat reference numerals and/or letters in the
various
examples or figures. This repetition is for the purpose of simplicity and
clarity and does not in
itself dictate a relationship between the various embodiments and/or
configurations discussed.
Further, spatially relative terms, such as beneath, below, lower, above,
upper, uphole, downhole,
upstream, downstream, and the like, may be used herein for ease of description
to describe one
element or feature's relationship to another element(s) or feature(s) as
illustrated, the upward
direction being toward the top of the corresponding figure and the downward
direction being
toward the bottom of the corresponding figure. The uphole direction refers to
the direction along
the longitudinal axis of the wellbore that leads back to the surface, or away
from the drill bit. In
a situation where the drilling is more or less along a vertical path, downhole
is truly in the down
direction and uphole is truly in the up direction, but in horizontal drilling,
the terms up and down
are ambiguous, so the terms downhole and uphole are used to designate relative
positions along
the drill string. The downhole direction refers to the direction along the
longitudinal axis of the
wellbore that looks toward the furthest extent or toe of the wellbore.
Downhole is also the
direction toward the location of the drill bit and other elements of the
bottom-hole assembly.
Similarly, in a wellbore approximating a horizontal direction, there is a
"high" side of the
wellbore and a "low" side of the wellbore, which refer to those points on the
circumference of
the wellbore that are closest and farthest, respectively, from the surface of
the land or water.
[00052] Unless otherwise stated, the spatially relative terms are intended
to encompass
different orientations of the apparatus in use or operation in addition to the
orientation depicted
in the figures. For example, if an apparatus in the figures is turned over,
elements described as
being "below" or "beneath" other elements or features would then be oriented
"above" the other
elements or features. Thus, the exemplary term "below" can encompass both an
orientation of
above and below. The apparatus may be otherwise oriented (rotated 90 degrees
or at other
orientations) and the spatially relative descriptors used herein may likewise
be interpreted
accordingly.
[00053] Moreover, even though a figure may depict a horizontal wellbore or
a vertical
wellbore, unless indicated otherwise, it should be understood by those skilled
in the art that the
apparatus according to the present disclosure is equally well-suited for use
in wellbores having
Date Recue/Date Received 2021-03-12
other orientations including, deviated wellbores, multilateral wellbores, or
the like. Likewise,
unless otherwise noted, even though a figure may depict an onshore operation,
it should be
understood by those skilled in the art that the apparatus according to the
present disclosure is
equally well-suited for use in offshore operations and vice-versa.
[00054] BI-DIRECTIONAL "REAM ON CLEAN" WELLBORE REAMER TOOL
[00055] FIG. 1 (PRIOR ART) is a schematic partial cross-sectional
elevation view of a
well system 10 that generally includes a generally cylindrical wellbore 12
extending from a
wellhead 14 at the surface 16 downward into the earth into a subterranean zone
18 corresponding
to a single formation, a portion of a formation, or more than one formation
accessed by the well
system 10, and a given well system 10 can access one, or more than one,
subterranean zone 18.
After some or all of the wellbore 12 is drilled, a portion of the wellbore 12
extending from the
wellhead 14 to the subterranean zone 18 is lined with lengths of casing 20.
The wellbore 12 can
be drilled in stages, and the casing 20 may be installed between stages.
[00056] The depicted well system 10 is a vertical well, with the wellbore
12 extending
substantially vertically from the surface 16 to the subterranean zone 18. The
concepts herein,
however, are applicable to many other different configurations of wells,
including horizontal,
slanted or otherwise deviated wells, and multilateral wells with legs
deviating from an entry well.
A drill string 22 is shown as having been lowered from the surface 16 into the
wellbore 12. The
drill string 22 may be a series of jointed lengths of drill pipe coupled
together end-to-end. The
drill string 22 includes one or more well tools, including a wellbore reamer
tool 24 and a drill bit
26. The drill bit 26 is rotated by rotating the drill string 22 at the surface
16. With weight
applied by the drill string 22, the rotating drill bit 26 engages the
formation and forms the
wellbore 12 toward a target zone. During the drilling process, drilling fluids
are circulated to
clean the cuttings while the drill bit 26 is advanced through the formation.
As the drill string 22
and the drill bit 26 are rotated, the wellbore reamer tool 24 cuts away the
formation, this process
is known as "reaming while drilling". The formation cuttings mix with and are
suspended within
the drilling fluid and pass up through an annular space 118 between the wall
of the wellbore 12
and the outer surface of the drill string 22 to the surface 16.
11
Date Recue/Date Received 2021-03-12
[00057] FIG. 2 is a perspective view of an exemplary wellbore reamer tool
28 that can be
used as the wellbore reamer tool 24 of FIG. 1 (PRIOR ART). The reamer tool 28
is carried on
the drill string 22. The reamer tool 28 is shown generally to comprise an
elongated substantially
cylindrical body 30 having a downhole end 32, an uphole end 34, a tool neck
36, and defining a
central bore 38 extending therethrough. In some embodiments, the reamer tool
28 is coupled to
other tools of the bottom hole assembly or another drill pipe at the downhole
end 32 by a
threaded pin connection 39. In some embodiments, the reamer tool 28 is coupled
to the drill
string 22 by a threaded box connection 41 at the uphole end 34. Downhole and
uphole spiral
hardbands 40, 42 are positioned on the downhole and uphole ends 32, 34
respectively (FIGS. 2
and 3). In some embodiments, the downhole and uphole spiral hardbands 40, 42
are formed
from tungsten carbide or diamond. The downhole and uphole spiral hardbands 40,
42 provide
erosion protection at the downhole and uphole ends 32, 34 of the reamer tool
28.
[00058] The reamer tool 28 includes a central axis A-A which defines a
central
longitudinal axis along the length of and through the center of the reamer
tool 28 (e.g., through
the center of the body 30). During drilling operations, the reamer tool 28 is
rotated about the
central axis A-A and moved up and/or down while rotating to enlarge the
diameter of the
wellbore previously drilled by the drill bit 26. The central axis A-A may
define a rotational axis
of the reamer tool 28, for example, during operation of the reamer tool 28.
[00059] In some embodiments, the reamer tool 28 comprises downhole spiral
hardbands
40, a first helical impeller 44, first cutting portions 46, an integral blade
stabilizer 48, second
cutting portions 50, a second helical impeller 52, and uphole spiral hardbands
42. In some
embodiments as shown in FIG. 2, the reamer tool 28 comprises in sequence, from
the downhole
end 32 to the uphole end 34, downhole spiral hardbands 40, a first helical
impeller 44, first
cutting portions 46, an integral blade stabilizer 48, second cutting portions
50, a second helical
impeller 52, and uphole spiral hardbands 42.
[00060] First Helical Impeller
[00061] As used herein, the term "helical" means being in the shape of a
helix or a curve
that goes around a central tube or cone shape in the form of a spiral. As
shown in FIG. 2, the
12
Date Recue/Date Received 2021-03-12
first helical impeller 44 is positioned downhole proximate the downhole end 32
of the reamer
tool 28. In some embodiments, the first helical impeller 44 is positioned
downhole proximate
the downhole end 32 of the reamer tool 28 between the downhole spiral
hardbands 40 and the
first cutting portions 46.
[00062] In some embodiments, the first helical impeller 44 comprises a
plurality of odd
and even helical blades 114 (FIG. 4). In some embodiments, the first helical
impeller 44
comprises six helical blades including three odd blades (i.e., designated as
blades "1, 3, and 5")
and three even blades (i.e., designated as blades "2, 4 and 6"). The odd
blades end before the
even blades. The even blades comprise straight-edged extension blades to
direct the cuttings to a
desired position between blades 68 in the first cutting portions 46. In some
embodiments, a
helical groove 116 is defined between each adjacent helical blade 114 to allow
the flow of the
cuttings therethrough. The helical groove 116 ending at the end of each odd
blade allows the
flow of the cuttings in the uphole direction. As shown in FIG. 5, the flow of
the cuttings within
the helical grooves 116 is directed by the odd and even blades 114. The
helical grooves 116
ending at the ends of the odd blades allow flow in the uphole direction
(indicated by the short
arrow). This flow combines with the flow directed by the even blades
(indicated by the long
arrow). As shown in FIG. 6, the straight edged extension blades 114 direct the
combined flow of
the cuttings in the uphole direction (indicated by the single arrow) towards
the grooves 67
between the blades 68 of the first cutting portions 46.
[00063] The first helical impeller 44 is configured or sized to ensure
that the helical blades
114 do not directly contact the wall of the wellbore 12. In some embodiments,
the first helical
impeller 44 has an outer diameter which is smaller than the diameter of the
wellbore 12. Having
a smaller outer diameter than the diameter of the wellbore 12 allows the first
helical impeller 44
to rotate freely without the helical blades 114 impacting and potentially
damaging the wall of the
wellbore 12. By sizing the first helical impeller 44 in this manner,
sufficient clearance space
may be provided between the helical blades 114 and the wall of the wellbore 12
to ensure the
generation of sufficient turbulence and subsequent controlled flow while
removing the cuttings.
The first helical impeller 44 functions to increase the flow velocity of
existing and newly
generated cuttings from downhole, directing them uphole within the wellbore 12
to the surface
13
Date Recue/Date Received 2021-03-12
16. The first helical impeller 44 thus "cleans" the wellbore 12 in advance of
the reaming to be
performed by the first and second cutting portions 46, 50. As the reamer tool
28 is advanced
further downhole, the first and second cutting portions 46, 50 ream on the
cleaned wellbore 12.
[00064] First Cutting Portion and Second Cutting Portion
[00065] The reamer tool 28 comprises first cutting portions 46 and second
cutting portions
50. In some embodiments, the first cutting portions 46 are positioned downhole
proximate the
downhole end 32 of the reamer tool 28 and between the first helical impeller
44 and the integral
blade stabilizer 48 (FIGS. 2 and 4). In some embodiments, the second cutting
portions 50 are
positioned uphole proximate the uphole end 34 of the reamer tool 28 between
the integral blade
stabilizer 48 and the second helical impeller 52 (FIGS. 2 and 18).
[00066] In some embodiments, each of the first and second cutting portions
46, 50
comprises a bladed portion 58 defining a plurality of pockets 60 formed in the
face 62 of the
bladed portion 58 and configured to radially receive and accommodate cutter
inserts 64 and
wedge retainers 66 (FIGS. 7-10). In some embodiments, the face 62 of the
bladed portion 58 is
formed of tungsten carbide. In some embodiments, the bladed portion 58
comprises three
pockets 60. In some embodiments, the bladed portion 58 comprises a plurality
of blades 68
spaced evenly and radially around the bladed portion 58 about the central axis
A-A. In some
embodiments, the blades 68 are substantially straight-edged and extend
axially. In some
embodiments, the bladed portion 58 comprises three blades 68.
[00067] In some embodiments, the pockets 60 are spaced evenly and radially
around the
bladed portion 58 about the central axis A-A, and positioned in between the
blades 68 (FIG. 8).
In some embodiments, there are three pockets 60. In some embodiments, the
pockets 60 on the
first and second cutting portions 46, 50 are oriented in different axial
positions in the blades 68.
In some embodiments, each pocket 60 is in the shape of a geometric stadium,
namely a rectangle
having a pair of semi-circles positioned at opposite ends. In some
embodiments, the pocket 60
comprises a rim 70 defining a notch 72, opposed end walls 74, opposed side
walls 76, and a base
78 upon which the cutter insert 64 is seated (FIG. 7). In some embodiments,
the length of the
notch 72 is the same or similar to the length of the inner row of the cutters
90b. In some
14
Date Recue/Date Received 2021-03-12
embodiments, the opposed end walls 74 are curved. In some embodiments, the
opposed side
walls 76 are straight. It will be appreciated by those skilled in the art that
other shapes such as
for example, rectangular, square, oval, and the like, are included within the
scope of the
invention. In some embodiments, the base 78 defines one or more apertures 80
for receiving
attachment means 82 therethrough to fixedly attach one or more wedge retainers
66 to the bladed
portion 58, thereby securing and retaining the cutter insert 64 within the
pocket 60.
[00068] It is contemplated that the number, size, shape, and positioning
of the pockets 60
and blades 68 may vary. Such factors may be dictated for example, by the
dimensions of the
blade portion 58, and the corresponding number and dimensions of the cutter
inserts 64. The
cutter inserts 64 can be readily inserted or detached from the corresponding
pockets 60 for
inspection, reinsertion, repair, or replacement if necessary. In some
embodiments, the cutter
inserts 64 are positioned within the pockets 60 so as to be spaced evenly and
radially around the
bladed portion 58 about the central axis A-A, and positioned in between the
blades 68 (FIG. 10).
[00069] As shown in FIG. 11, each cutter insert 64 comprises a cutter
insert body 84
defining a first recess 86 and a second recess 88. Each recess 86, 88 is
configured for receiving a
plurality of cutters 90a, 90b arranged linearly in rows and inclined at a
predetermined attacking
angle (FIGS. 12-15). The attacking angle is selected so as to ensure that the
cutters 90a, 90b
may remove cuttings from the wall of the wellbore 12 in a precise amount on
each radial step
and that the torque while reaming may be minimized.
[00070] In some embodiments, at least two rows representing "outer" and
"inner" rows of
cutters 90a, 90b are arranged linearly within the cutter insert 64. In some
embodiments, the
inner row of cutters 90b is arranged linearly within the first recess 88. In
some embodiments, the
outer row of cutters 90a is arranged linearly within the second recess 86. In
some embodiments,
the outer row has fewer cutters 90a compared to the number of cutters 90b in
the inner row. In
some embodiments, the outer row comprises three cutters 90a in the first
recess 86. In some
embodiments, the inner row comprises four cutters 90b in the second recess 88.
Date Recue/Date Received 2021-03-12
[00071] In some embodiments, each recess 86, 88 is substantially
rectangular-shaped. In
some embodiments, the first and second recesses 86, 88 are aligned
substantially parallel to each
other, with the second recess 88 being positioned "below" the first recess 86
(FIGS. 12 and 13).
In some embodiments, the first recess 86 has a length shorter than the length
of the second recess
88 to accommodate fewer cutters 90a. In some embodiments, the first recess 86
includes a
partially scalloped edge 92 which defines clearance spaces to accommodate the
incline of each
individual cutter 90a. In some embodiments, the second recess 88 has a
substantially straight
edge 94 facing the partially scalloped edge 92 of the first recess 86. The
cutters 90a are evenly
spaced apart in the first recess 86 to be positioned in an alternating fashion
with the cutters 90b
also evenly spaced apart in the second recess 88. The cutters 90a, 90b are
thereby balanced to
ream with a minimum torque.
[00072] The cutters 90a, 90b are fabricated to combine both toughness and
hardness in
order to prevent them from failing under normal forces of use for long life.
In some
embodiments, the cutters 90a, 90b are represented as a disk-shaped (FIGS. 11
and 12). In some
embodiments, the cutters 90a are represented as square-shaped when viewed in
cross-section
(FIG. 10). In some embodiments, the cutters 90b are represented as rectangular-
shaped with a
single rounded corner when viewed in cross-section (FIG. 10). A cutting
surface 96 comprising
a hard, super-abrasive material, such as mutually bound particles of
polycrystalline diamond
forming a so-called "diamond table," may be provided on a substantially
circular end surface of a
substrate of each cutter 90a, 90b. Suitable substrates include, but are not
limited to, hard metallic
materials such as tungsten carbide. Such cutters 90a, 90b are often referred
to as "polycrystalline
diamond compact" (PDC) cutters. The PDC cutters 90a, 90b are fabricated
separately from the
cutter insert body 84 and secured by their substrates within the first and
second recesses 86, 88
by brazing or welding.
[00073] In some embodiments, the cutter insert 64 is securely mounted or
retained within
the pocket 60 by fixedly attaching one or more wedge retainers 66 to the
bladed portion 58. In
some embodiments, a wedge retainer 66 is positioned at each end of the cutter
insert body 84
(FIGS. 4, 7, 9, 11, and 18). In some embodiments, the wedge retainer 66
comprises a
substantially square-shaped wedge body 98 having a curved edge 100 (FIG. 11).
The wedge
16
Date Recue/Date Received 2021-03-12
retainer 66 defines corresponding openings 110 extending through the wedge
body 98 which
align with the apertures 80 in the base 78 of the pocket 60. In some
embodiments, the wedge
retainer 66 defines four openings 110 evenly spaced in a square-like
configuration. The
openings 110 of the wedge retainer 66 are configured to receive, accommodate,
and allow the
passage of attachment means therethrough. Suitable attachment means 82
include, but are not
limited to, bolts, screws, and the like. In some embodiments, the attachment
means 82 are bolts.
In such a configuration, the cutter insert 64 may be removably secured within
the pocket 60 to
facilitate relatively easy removal, inspection, repair, and replacement of
components of the cutter
insert 64 if damaged. The wedge retainer 66 may be made of any suitable hard
material
including, but not limited to, steel, or steel alloy. The bolts 82 may be made
of steel alloy.
[00074] As shown in FIGS. 7-9, the cutter insert 64 and wedge retainers 66
are installed
into the pocket 60 by placing a wedge retainer 66 at each end of the cutter
insert 64, and aligning
the inner row of the cutters 90b with the notch 72 of the pocket 60. The notch
72 has the same or
similar length as the length of the inner row of the cutters 90b in order to
define a clearance
space to accommodate the incline of each individual cutter 90b. The cutter
insert 64 is seated on
the base 78 of the pocket 60, and the curved edges 100 of the wedge retainers
66 seat against the
curved opposed end walls 74 of the pocket 60. The cutter insert 64 and wedge
retainers 66 lie
flush with the face 62 of the base portion 58, with the cutters 90a, 90b
protruding above the rim
70 and notch 72 of the pocket 60 (FIGS. 9 and 10). The attachment means 82
extend through the
openings 110 of the wedge retainers 66 and the apertures 80 of the pocket 60
to securely mount
and retain the cutter insert 64 to the blade portion 58 during use.
[00075] The first and second cutting portions 46, 50 are strategically
positioned and
spaced apart at a predetermined distance in order to provide multiple pockets
60 and to allow
flexibility for the positioning of any desired number of cutter inserts 64
along the length of the
reamer tool 28 as needed (FIG. 2). The multiple pockets 60 are positioned
circumferentially and
axially in both the uphole and downhole positions in order to allow more
coverage from the
cutters 90a, 90b in one single rotation. In some embodiments, six pockets 60
supporting six
cutter inserts 64 providing multiple inner and outer rows of cutters 90a, 90b
are present on the
reamer tool 28 (FIG. 2). In such a configuration, substantial reaming
capability can be achieved
17
Date Recue/Date Received 2021-03-12
by the attacking angle of such multiple rows of cutters 90a, 90b to cut or
ream the precise
amount of cuttings from the wall of the wellbore 12 on each radial step to
guarantee lower torque
while reaming (FIG. 10).
[00076] Without being bound by any theory, the multiple rows of cutters
90a, 90b may
help to maintain the mechanical integrity of the outer cutters 90a by reaming
smaller diameters
predominantly with the internal cutters 90b. This may allow sliding drilling
without adding drag
or increasing friction since the integrity of the outer cutters 90a may be
less compromised. As
used herein, the term "slide drilling" means drilling by rotating the drill
bit downhole without
rotating the drill string from the surface. Slide drilling is commonly used to
build and control or
correct hole angle in directional drilling operations. Without turning the
drill string, the drill bit
is rotated and drills in the direction it points. By controlling the amount of
hole drilled in the
sliding versus the rotating mode, the wellbore trajectory can be precisely
controlled. The outer
and inner rows of cutters 90a, 90b are placed into a predetermined radial
position to allow a
progressive reaming during rotation, meaning that the maximum diameter which
the inner cutters
90b can reach is smaller than the maximum diameter which the outer cutters 90a
can reach
(FIGS. 12-14).
[00077] FIG. 15 shows the axial displacement of the cutting inserts 64 for
progressive
exposure of the reaming surfaces. All three pockets 60 holding the cutting
inserts 64 at the same
downhole and uphole positions have an axial displacement between them
(indicated by dashed
lines), allowing the cutting inserts 64 to sit in an axial position where the
cutters 90a, 90b are not
aligned. As the reamer tool 28 rotates and moves in the downhole direction
during front reaming
operations, the trajectory of the cutters 90a, 90b comprises a helical
trajectory. Having multiple
axially displaced cutters 90a, 90b allows more reaming coverage as every axial
position creates a
new helical trajectory. Such axial displacement of the cutting inserts 64
enables coverage of
wider areas while shearing the wall of the wellbore 12.
[00078] Without being bound by any theory, providing strategically
positioned multiple
inner and outer rows of cutters 90b, 90a for reaming the wall of the wellbore
12 may improve
wellbore quality which is generally related to the "smoothness" of the
wellbore or the
18
Date Recue/Date Received 2021-03-12
"tortuosity." The configuration and positioning of multiple cutters 90a, 90b
along the length of
the reamer tool 28 may reduce the micro-tortuosity and high frequency wellbore
spiraling,
thereby producing a smooth, high-quality, un-spiraled wellbore.
[00079] Integral Blade Stabilizer
[00080] In some embodiments, the integral blade stabilizer 48 is
positioned at an uphole
position of the reamer tool 28 between the first cutting portions 46 and the
second cutting
portions 50. As shown in FIGS. 16 and 17, the integral blade stabilizer 48
comprises a plurality
of substantially "S"-shaped stabilizer blades 112. In some embodiments, the
integral blade
stabilizer 48 comprises three stabilizer blades 112. The length and outer
diameter of the integral
blade stabilizer 48 provides radial support and tilt support to the reamer
tool 28.
[00081] Without being bound by any theory, the "S"-shaped stabilizer
blades 112 may
help to prevent or minimize the sliding or movement of the cuttings in the
downhole direction in
the event that the flow circulation stops. The "S" shape may also help to
reduce friction during
slide drilling. In the event of a stabilizer blade 112 sitting on the low side
of the wellbore 12 (for
example, of horizontal wells), the friction between the stabilizer blade 112
and the wall of the
wellbore 12 is minimized since only a partial area of the surface of the
stabilizer blade 112 shall
contact the wellbore 12 due to the stabilizer blade 112 being "S"-shaped.
[00082] In some embodiments, the outer diameter of the integral blade
stabilizer 48 is
larger than the outer diameter of each of the first and second cutting
portions 46, 50. Having a
larger outer diameter confers 3600 support around the circumference of the
reamer tool 28 which
may confer stability to the drill string 22, and limits the amount of debris
removed by the cutters
90a, 90b per radial step (FIG. 17).
[00083] Second Helical Impeller
[00084] As shown in FIG. 2, the second helical impeller 52 is positioned
uphole proximate
the uphole end 34 of the reamer tool 28. In some embodiments, the second
helical impeller 52 is
positioned uphole proximate the uphole end 34 of the reamer tool 28 above both
the first and
second cutting portions 46, 50. In some embodiments, the second helical
impeller 52 is
19
Date Recue/Date Received 2021-03-12
positioned uphole proximate the uphole end 34 of the reamer tool 28 between
the second cutting
portion 50 and the tool neck 36.
[00085] In some embodiments, the second helical impeller 52 comprises a
plurality of
helical blades 56 (FIG. 18). In some embodiments, a helical groove 54 is
defined between each
adjacent helical blade 56. In some embodiments, the helical blades 56 comprise
odd blades and
even blades. In some embodiments, the second helical impeller 52 comprises six
helical blades
including three odd blades (i.e., designated as blades "1, 3, and 5") and
three even blades (i.e.,
designated as blades "2, 4 and 6").
[00086] The second helical impeller 52 is configured or sized to ensure
that the helical
blades 56 do not directly contact the wall of the wellbore 12. In some
embodiments, the second
helical impeller 52 has an outer diameter which is smaller than the diameter
of the wellbore 12.
Having a smaller outer diameter than the diameter of the wellbore 12 allows
the second helical
impeller 52 to rotate freely without the helical blades 56 impacting and
potentially damaging the
wall of the wellbore 12. By sizing the second helical impeller 52 in this
manner, sufficient
clearance space may be provided between the helical blades 56 and the wall of
the wellbore 12 to
ensure the generation of sufficient turbulence and subsequent controlled flow
while removing the
cuttings. The second helical impeller 52 functions to increase the flow
velocity of the newly
created cuttings.
[00087] MANUFACTURE
[00088] In some embodiments, the reamer tool 28 comprises in sequence,
from the
downhole end 32 to the uphole end 34, downhole spiral hardbands 40, a first
helical impeller 44,
first cutting portions 46, an integral blade stabilizer 48, second cutting
portions 50, a second
helical impeller 52, and an uphole spiral hardbands 42. During manufacture,
the reamer tool 28
may be configured as one integral piece or as separate pieces which are
interconnected together
to define the unitary central bore 38 extending through the reamer tool 28.
The cutter inserts 64,
cutters 90a, 90b, wedge retainers 66, and attachments means 82 are preferably
manufactured
separately for assembly into the pockets 60 of the bladed portions 58. The
cutter inserts 64 can
Date Recue/Date Received 2021-03-12
then be readily connected or detached from the pockets 60 for inspection,
reinsertion, repair, or
replacement if necessary.
[00089] The reamer tool 28 can be constructed from any material or
combination of
materials having suitable properties such as, for example, mechanical
strength, ability to
withstand cold and adverse field conditions, corrosion resistance, and ease of
machining.
Suitable materials include, for example, steel alloy, high strength alloy
steel, stainless steel,
synthetic diamond materials, tungsten carbide, or other appropriate materials
known to those
skilled in the art.
[00090] In some embodiments, the first helical impeller 44, the first
cutting portions 46,
the integral blade stabilizer 48, the second cutting portions 50, and the
second helical impeller 52
are covered by a harder material to protect the reamer tool 28 from erosion
due to the constant
interaction with the wellbore surface. Suitable materials include, but are not
limited to, synthetic
diamond and tungsten carbide.
[00091] In some embodiments, the downhole spiral hardbands 40 and the
uphole spiral
hardbands 42 are made from harder materials to protect the downhole end 32 and
the uphole end
34 from erosion due to the constant interaction with the wellbore surface.
Suitable materials
include, but are not limited to, synthetic diamond and tungsten carbide.
[00092] OPERATION
[00093] The operation of drilling a wellbore is commonly known to those
skilled in the art
and will not be discussed in detail. A typical well system 10 was previously
described herein
(FIG. 1, PRIOR ART). Prior to operation, the completely assembled reamer tool
28 is coupled
into the drill string 22 to become integral to the drill string 22, for
example, such that the reamer
tool 28 is positioned on the drill string 22 as part of the drill string 22.
[00094] The drill bit 26 is rotated by rotating the drill string 22 at the
surface 16. With
weight applied by the drill string 22, the rotating drill bit 26 engages the
formation and forms a
borehole toward a target zone, generating cuttings as the drill bit 26 is
advanced through the
21
Date Recue/Date Received 2021-03-12
formation. Drilling fluids are circulated to clean the cuttings. The reamer
tool 28 including all
its components is rotated concurrently with the rotating drill string 22.
During rotation, the first
helical impeller 44 increases the flow velocity of the existing cuttings which
are deposited or
accumulate as the drill bit 26 is advancing through the formation, and places
such cuttings back
into circulation to a specific position between the blades 68 of the first
cutting portions 46 (FIG.
6). The first helical impeller 44 thus "cleans" the borehole in advance of the
reaming to be
performed by the first and second cutting portions 46, 50. The second helical
impeller 52
increases the flow velocity of the newly incorporated cuttings through the
annular 118 towards
the surface 16.
[00095] To ream the radial wall of the wellbore 12, the cutters 90a, 90b
of the first cutting
portions 46 shear against the wall of the wellbore 12, with the inner rows of
cutters 90b engaging
or contacting the wall of the wellbore 12 followed by the outer rows of
cutters 90a to enlarge the
diameter of the wellbore 12 during rotation of the reamer tool 28 about
central axis A-A. The
newly generated formation cuttings are mixed into the cuttings stream to be
suspended within the
drilling fluid and the flow is directed uphole.
[00096] Similarly, the cutters 90a, 90b of the second cutting portions 50
shear against the
wall of the wellbore 12, with the inner rows of cutters 90b contacting the
wall followed by the
outer rows of cutters 90a to enlarge the diameter of the wellbore 12 during
rotation of the reamer
tool 28 about central axis A-A. The newly generated formation cuttings are
mixed into the
cuttings stream to be suspended within the drilling fluid and the flow is
directed uphole by
rotation of the second helical impeller 52. The cuttings stream passes up
through an annular
space 118 between the wall of the wellbore 12 and the outer surface of the
drill string 22 to the
surface 16 for removal.
[00097] APPLICATIONS
[00098] One or more of the following applications may be realized when
practicing some
embodiments of the invention: (i) the reamer tool 28 may function as a
wellbore conditioner,
drill string stabilizer, and bi-directional reamer apparatus; (ii) the reamer
tool 28 may allow
reaming out sections of high frequency wellbore spiraling, key seats and
doglegs while cleaning
22
Date Recue/Date Received 2021-03-12
the wellbore and keeping the bottom hole assembly centralized; (iii) the
reamer tool 28 may be
used for vertical or horizontal wells to reduce the friction factor between
the drill string and the
wellbore, thus reducing the rotary torque while drilling and increasing the
transfer of Weight on
Bit; and (iv) as the wellbore is continuously reamed while drilling, the
overall quality of the
wellbore eliminates the need for the standard dedicated reamer run prior to
running casing or
multi-stage completions strings and the associated costs. This is achieved by
the reamer tool 28
which combines engineered flow control, enhanced wellbore cleaning, reaming on
a cleaned
wellbore, and optimized positioning of cutters on radially insertable cutting
inserts along the
length of the reamer tool 28.
[00099]
The particular embodiments disclosed above are illustrative only, as the
present
disclosure may be modified and practiced in different but equivalent manners
apparent to those
skilled in the art having the benefit of the teachings herein. While numerous
changes may be
made by those skilled in the art, such changes are encompassed within the
scope of the subject
matter defined by the appended claims. Furthermore, no limitations are
intended to the details of
construction or design herein shown, other than as described in the claims
below. It is therefore
evident that the particular illustrative embodiments disclosed above may be
altered or modified
and all such variations are considered within the scope of the present
disclosure.
23
Date Recue/Date Received 2021-03-12
