U.S. patent application number 14/873723 was filed with the patent office on 2016-07-21 for wellbore conditioning system.
The applicant listed for this patent is Extreme Technologies, LLC. Invention is credited to James D. Isenhour, Gilbert Troy Meier.
Application Number | 20160208559 14/873723 |
Document ID | / |
Family ID | 48044122 |
Filed Date | 2016-07-21 |
United States Patent
Application |
20160208559 |
Kind Code |
A1 |
Isenhour; James D. ; et
al. |
July 21, 2016 |
Wellbore Conditioning System
Abstract
A wellbore conditioning system is disclosed. The system
comprises at least one shaft and at least two eccentric unilateral
reamers, wherein the unilateral reamers are positioned at a
predetermined distance from each other and the unilateral reamers
are positioned at a predetermined rotational angle from each
other.
Inventors: |
Isenhour; James D.;
(Windsor, CO) ; Meier; Gilbert Troy; (Vernal,
UT) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Extreme Technologies, LLC |
Vernal |
UT |
US |
|
|
Family ID: |
48044122 |
Appl. No.: |
14/873723 |
Filed: |
October 2, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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13644218 |
Oct 3, 2012 |
9163460 |
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14873723 |
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61542601 |
Oct 3, 2011 |
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61566079 |
Dec 2, 2011 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 10/46 20130101;
E21B 10/28 20130101; E21B 44/00 20130101; E21B 10/26 20130101; E21B
7/28 20130101 |
International
Class: |
E21B 10/28 20060101
E21B010/28; E21B 10/46 20060101 E21B010/46; E21B 7/28 20060101
E21B007/28 |
Claims
1.-20. (canceled)
21. An apparatus for use on a drill string for increasing the drift
diameter of a well bore during drilling, comprising: at least one
eccentric reamer positioned on the drill string, wherein each
reamer has a plurality of cutting blades extending a distance
radially outwardly from the outer surface of the reamer, wherein a
first cutting blade extends a first distance and, in an order
counter to the direction of rotation, each additional cutting blade
extends an equal or greater distance than the preceding cutting
blade, and the plurality of blades defining a curved cutting area
extending approximately 50% or less of the circumference of each
reamer.
22. The apparatus of claim 21, further comprising grooves disposed
between the cutting blades.
23. The apparatus of claim 21, wherein each set of cutting blades
is arranged along a spiral path along the surface of the associated
reamer.
24. The apparatus of claim 21, further comprising an array of two
or more cutting teeth extending from each of the cutting blades and
tangentially to each reamer.
25. The apparatus of claim 24, wherein the teeth of each of the
plurality of cutting blades of each reamer are offset from the
teeth of the adjacent cutting blades.
26. The apparatus of claim 24, wherein each tooth is comprised of
carbide or diamond.
27. The apparatus of claim 24, wherein the teeth face the direction
of rotation.
28. The apparatus of claim 21, further comprising a coupling
adapted to receive a bottom hole assembly.
29. The apparatus of claim 21, wherein the apparatus is positioned
behind a drill bit.
30. The apparatus of claim 29, wherein the apparatus is positioned
at least 100 feet behind the drill bit.
31. The apparatus of claim 24, wherein the teeth of each of the
plurality of cutting blades are longitudinally overlapping from the
teeth of the adjacent cutting blades.
32. A well bore drilling device, comprising: a drill string; a
drill bit positioned at the end of the drill string; and at least
one eccentric reamer positioned on the drill string, wherein each
reamer has a plurality of cutting blades extending a distance
radially outwardly from the outer surface of the reamer, wherein a
first cutting blade extends a first distance and, in an order
counter to the direction of rotation, each additional cutting blade
extends an equal or greater distance than the preceding cutting
blade, and the plurality of blades defining a curved cutting area
extending approximately 50% or less of the circumference of each
reamer.
33. The device of claim 32, further comprising grooves disposed
between the cutting blades.
34. The device of claim 32, wherein each set of cutting blades is
arranged along a spiral path along the surface of the associated
reamer.
35. The device of claim 32, further comprising an array of two or
more cutting teeth extending from each of the cutting blades and
tangentially to each reamer.
36. The apparatus of claim 35, wherein the teeth of each of the
plurality of cutting blades of each reamer are offset from the
teeth of the adjacent cutting blades.
37. The apparatus of claim 35, wherein each tooth is comprised of
carbide or diamond.
38. The apparatus of claim 35, wherein the teeth face the direction
of rotation.
39. The apparatus of claim 32, wherein the pair of similar
eccentric reamers are positioned at least 100 feet behind the drill
bit.
40. The apparatus of claim 35, wherein the teeth of each of the
plurality of cutting blades are longitudinally overlapping from the
teeth of the adjacent cutting blades.
41. An apparatus for use on a drill string for increasing the drift
diameter of a well bore during drilling, comprising: a pair of
similar eccentric reamers positioned opposingly on the drill
string, wherein each reamer has a plurality of cutting blades
extending a distance radially outwardly from the outer surface of
the reamer, wherein a first cutting blade extends a first distance
and, in an order counter to the direction of rotation, each
additional cutting blade extends an equal or greater distance than
the preceding cutting blade, and the plurality of blades defining a
curved cutting area extending approximately 50% or less of the
circumference of each reamer.
42. The apparatus of claim 41, further comprising grooves disposed
between the cutting blades.
43. The apparatus of claim 41, wherein each set of cutting blades
is arranged along a spiral path along the surface of the associated
reamer.
44. The apparatus of claim 41, further comprising an array of two
or more cutting teeth extending from each of the cutting blades and
tangentially to each reamer.
45. The apparatus of claim 44, wherein the teeth of each of the
plurality of cutting blades of each reamer are offset from the
teeth of the adjacent cutting blades.
46. The apparatus of claim 44, wherein each tooth is comprised of
carbide or diamond.
47. The apparatus of claim 44, wherein the teeth face the direction
of rotation.
48. The apparatus of claim 41, further comprising a coupling
adapted to receive a bottom hole assembly.
49. The apparatus of claim 41, wherein the apparatus is positioned
behind a drill bit.
50. The apparatus of claim 49, wherein the apparatus is positioned
at least 100 feet behind the drill bit.
51. The apparatus of claim 44, wherein the teeth of each of the
plurality of cutting blades are longitudinally overlapping from the
teeth of the adjacent cutting blades.
52. A well bore drilling device, comprising: a drill string; a
drill bit positioned at the end of the drill string; and a pair of
similar eccentric reamers positioned opposingly on the drill
string, wherein each reamer has a plurality of cutting blades
extending a distance radially outwardly from the outer surface of
the reamer, wherein a first cutting blade extends a first distance
and, in an order counter to the direction of rotation, each
additional cutting blade extends an equal or greater distance than
the preceding cutting blade, and the plurality of blades defining a
curved cutting area extending approximately 50% or less of the
circumference of each reamer.
53. The device of claim 52, further comprising grooves disposed
between the cutting blades.
54. The device of claim 52, wherein each set of cutting blades is
arranged along a spiral path along the surface of the associated
reamer.
55. The device of claim 52, further comprising an array of two or
more cutting teeth extending from each of the cutting blades and
tangentially to each reamer.
56. The apparatus of claim 55, wherein the teeth of each of the
plurality of cutting blades of each reamer are offset from the
teeth of the adjacent cutting blades.
57. The apparatus of claim 55, wherein each tooth is comprised of
carbide or diamond.
58. The apparatus of claim 55, wherein the teeth face the direction
of rotation.
59. The apparatus of claim 52, wherein the pair of similar
eccentric reamers are positioned at least 100 feet behind the drill
bit.
60. The apparatus of claim 55, wherein the teeth of each of the
plurality of cutting blades are longitudinally overlapping from the
teeth of the adjacent cutting blades.
Description
REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to provisional applications
U.S. Provisional Application Ser. No. 61/542,601, filed Oct. 3,
2011, and U.S. Provisional Application Ser. No. 61/566,079, filed
Dec. 2, 2011, both entitled "Wellbore Conditioning System," both of
which are specifically and entirely incorporated by reference.
BACKGROUND
[0002] 1. Field of the Invention
[0003] The invention is directed to wellbore conditioning systems
and devices. In particular, the invention is directed to systems
and devices for conditioning horizontal wellbores.
[0004] 2. Background of the Invention
[0005] Drill bits for drilling oil, gas, and geothermal wells, and
other similar uses typically comprise a solid metal or composite
matrix-type metal body having a lower cutting face region and an
upper shank region for connection to the bottom hole assembly of a
drill string formed of conventional jointed tubular members which
are then rotated as a single unit by a rotary table or top drive
drilling rig, or by a downhole motor selectively in combination
with the surface equipment. Alternatively, rotary drill bits may be
attached to a bottom hole assembly, including a downhole motor
assembly, which is, in turn, connected to a drill string wherein
the downhole motor assembly rotates the drill bit. The bit body may
have one or more internal passages for introducing drilling fluid,
or mud, to the cutting face of the drill bit to cool cutters
provided thereon and to facilitate formation chip and formation
fines removal. The sides of the drill bit typically may include a
plurality of radially or laterally extending blades that have an
outermost surface of a substantially constant diameter and
generally parallel to the central longitudinal axis of the drill
bit, commonly known as gage pads. The gage pads generally contact
the wall of the borehole being drilled in order to support and
provide guidance to the drill bit as it advances along a desired
cutting path or trajectory.
[0006] During the drilling of horizontal oil and gas wells, for
example, the trajectory of the wellbore is often uneven and
erratic. The high tortuosity of a wellbore, brought about from
geo-steering, directional drilling over corrections, and/or
formation interaction, makes running multi stage expandable packer
assembles or casing in such wells extremely difficult and sometimes
impossible. While drilling long reach horizontal wells, the
friction generated from the drill string and wellbore interaction
severely limits the weight transfer to the drill bit, thus lowering
the rate of penetration and potentially causing numerous other
issues and, in a worst case scenario, the inability to reach the
total planned depth of the well.
[0007] Currently the majority of hole enlargement tools have either
a straight mechanical engagement or hydraulic engagement. These
tools have had several reliability issues, including: premature
engagement, not opening to their desired position, and not closing
fully, all of which can lead to disastrous results. Such tools
include expandable bits, expandable hole openers, and expandable
stabilizers. The use of conventional fixed concentric stabilizers
and reaming-while-drilling tools have also proven to be ineffective
in most cases.
SUMMARY OF THE INVENTION
[0008] The present invention overcomes the problems and
disadvantages associated with current strategies and designs and
provides new tools and methods of conditioning wellbores.
[0009] An embodiment of the invention is directed to a wellbore
conditioning system. The system comprises at least one shaft and at
least two unilateral reamers extending from the at least one shaft.
The unilateral reamers are positioned at a predetermined distance
from each other and the unilateral reamers are positioned at a
predetermined rotational angle from each other.
[0010] Preferably, each unilateral reamer extends from an outer
surface of the at least one shaft in a direction perpendicular to
the axis of rotation of the shaft. In the preferred embodiment,
each reamer is comprised of a plurality of blades, wherein each
blade has a larger radius than a previous blade in the direction of
counter rotation. The system preferably further comprises a
plurality of cutters coupled to each blade. Each cutter is
preferably a Polycrystalline Diamond Compact (PDC) cutter. The
system also preferably further comprises at least one dome slider
coupled to each blade. Preferably, each dome slider is a PDC dome
slider.
[0011] Preferably, there is a recess in the at least one shaft
adjacent to each reamer. In the preferred embodiment, the at least
one shaft and reamers are made from a single piece of material.
Preferably there are a plurality of shafts and each shaft comprises
one reamer.
[0012] Another embodiment of the invention is directed to a
wellbore drilling string. The wellbore drilling string comprises a
drill bit, a downhole mud motor, a measurement-while-drilling (MWD)
device relaying the orientation of the drill bit and the downhole
mud motor to a controller, and a wellbore conditioning system. The
wellbore conditioning system comprises at least one shaft and at
least two eccentric unilateral reamer extending from the shaft. The
unilateral reamers are positioned at a predetermined distance from
each other and the unilateral reamers are positioned at a
predetermined rotational angle from each other. The wellbore
conditioning system is positionable within the wellbore drill
string at a location in or around the bottom hole assembly.
[0013] Preferably, each unilateral reamer extends from an outer
surface of the at least one shaft in a direction perpendicular to
the axis of rotation of the at least one shaft. In the preferred
embodiment, each reamer is comprised of a plurality of blades,
wherein each blade has a larger radius than a previous blade in the
direction of counter rotation. The wellbore conditioning system
preferably further comprises a plurality of cutters coupled to each
blade. Each cutter is preferably a Polycrystalline Diamond Compact
(PDC) cutter. The wellbore conditioning system preferably also
further comprises at least one dome slider coupled to each blade.
Preferably, each dome slider is a PDC dome slider.
[0014] Preferably, there is a recess in the at least one shaft
adjacent to each reamer. In the preferred embodiment, the at least
one shaft and reamers are made from a single piece of material.
Preferably, there is a plurality of shafts and each shaft comprises
one reamer.
[0015] Other embodiments and advantages of the invention are set
forth in part in the description, which follows, and in part, may
be obvious from this description, or may be learned from the
practice of the invention.
DESCRIPTION OF THE DRAWING
[0016] The invention is described in greater detail by way of
example only and with reference to the attached drawing, in
which:
[0017] FIG. 1 is a schematic of an embodiment of the system of the
invention.
[0018] FIGS. 2-4 are views of an embodiment of the reamers of the
invention.
[0019] FIG. 5 is an exaggerated view of an embodiment of the system
within a wellbore.
DESCRIPTION OF THE INVENTION
[0020] As embodied and broadly described herein, the disclosures
herein provide detailed embodiments of the invention. However, the
disclosed embodiments are merely exemplary of the invention that
may be embodied in various and alternative forms. Therefore, there
is no intent that specific structural and functional details should
be limiting, but rather the intention is that they provide a basis
for the claims and as a representative basis for teaching one
skilled in the art to variously employ the present invention
[0021] A problem in the art capable of being solved by the
embodiments of the present invention is conditioning narrow
wellbores without interfering with the drilling devices. It has
been surprisingly discovered that positioning a pair of unilateral
reamers along a shaft allows for superior conditioning of narrow
wellbores compared to existing technology.
[0022] FIG. 1 depicts a preferred embodiment of the wellbore
conditioning system 100. In the preferred embodiment, wellbore
condition system 100 is comprised of a single shaft. However, in
other embodiments, wellbore conditioning system 100 is comprised of
leading shaft 105a and trailing shaft 105b, as shown in FIG. 1.
While two shafts are shown, another number of shafts can be used,
for example, three or four shafts can be used. Preferably the total
shaft length is ten feet, however the shaft can have other lengths.
For example, the total shaft length shaft can be eight feet or
twelve feet in length. In embodiments with two shafts, shafts 105a
and 105b are coupled at joint 110 (in FIG. 1, joint 110 is shown
prior to coupling shafts 105a and 105b). In the preferred
embodiment, joint 110 is a screw joint, wherein the male portion of
joint 110 attached to shaft 105b has exterior threads and the
female portion of joint 110 attached to shaft 105a has interior
threads. However, another type of coupling can be used, for example
the portions of joint 110 depicted in FIG. 1 can be reversed with
the male portion on shaft 105a and the female portion on shaft
105b. Furthermore, other methods of joining shaft 105a to shaft
105b can be implemented, such as welding, bolts, friction joints,
and adhesive. In the preferred embodiment, upon being joined,
shafts 105a and 105b are coaxial and rotate in unison. Furthermore,
in the preferred embodiment, joint 110 may be more resistant to
bending, breaking, or other failure than if shafts 105a and 105b
were a uni-body shaft.
[0023] In the preferred embodiment the shaft is comprised of steel,
preferably 4145 or 4140 steel alloys. However, the shaft can be
made of other steel alloys, aluminum, carbon fiber, fiberglass,
iron, titanium, tungsten, nylon, other high strength materials, or
combinations thereof. Preferably, the shaft is milled out of a
single piece of material, however other methods of creating the
shaft can be used. For example, the shaft can be cast, rotomolded,
made of multiple pieces, injection molded, and combinations
thereof. The preferred outer diameter of the shaft is approximately
5.5 inches, however the shaft can have other outer diameters (e.g.
10 inches, 20 inches, 30 inches, or another diameter common to
wellbores). As discussed herein, the reamers extend beyond the
outer diameter of the shaft.
[0024] As shown in FIG. 1, in the two shaft embodiment, each of
shafts 105a and 105b has a single unilateral reamer 115a and 115b,
respectively. In the uni-body shaft embodiment, the shaft has at
least two unilateral reamers 115a and 115b. Each reamer 115a and
115b projects from the body of the shaft on one, single side of the
shaft. Furthermore, each reamer 115a and 115b is preferably
situated eccentrically on the body of shafts 105a and 115b such
that the centers of mass of the reamers 115a and 115b are not
coaxial with the centers of mass of the body of shafts 105a and
115b. As can be seen in FIG. 1, reamer 115a projects in a first
direction (upwards on FIG. 1), while reamer 115b projects in a
second direction (downwards on FIG. 1). While reamers 115a and 115b
are shown 180.degree. apart from each other, there can be other
rotational configurations. For example, reamers 115a and 115b can
be 90.degree., 45.degree., or 75.degree. apart from each other. In
the preferred embodiment, reamers 115a and 115b are identical,
however deviations in reamer configuration can be made depending on
the intended use of the system 100.
[0025] As shown in the embodiment of the system 100 depicted in
FIG. 5, in operation, the first reamer 115a bores into one portion
of the wellbore 550 while the second reamer 115b bores into a
diametrically opposed portion of the wellbore 550. The opposing
forces (shown by the arrows in FIG. 5) created by the diametrically
opposed reamers centralize the system 100 within the wellbore 550.
This self-centralizing feature allows system 100 to maintain a
central location within wellbore 500 while having no moving
parts.
[0026] In the preferred embodiment each of reamers 115a and 115b
has four blades, however, there can be another number of blades
(e.g., one blade, three blades, or five blades). Preferably, the
radius of each of the four blades projects from shafts 105a and
105b at a different increment. The incremental increase in the
radius of the blades allows the first blade in the direction of
counter rotation (i.e., the first blade to contact the surface of
the wellbore) to remove a first portion of the wellbore wall, the
second blade in the direction of counter rotation to remove a
second, greater portion of the wellbore wall, the third blade in
the direction of counter rotation to remove a third, greater
portion of the wellbore wall, and the fourth blade in the direction
of counter rotation to remove a fourth, greater portion of the
wellbore wall, so that, after the fourth blade, the wellbore is the
desired size. The progressing counter rotation blade radius layout
creates an equalizing depth of cut. Cutter work load is evenly
distributed from blade to blade as the wellbore is being enlarged
and conditioned. This calculated cutter work rate reduces impact
loading. The reduction of impact loading translates into reduced
torque and cutter fatigue. Furthermore, due to the gradual increase
of the radius of the blades, there is a smooth transition to full
bore diameter, which preferably reduces vibration and torque on
system 100.
[0027] As can be seen in FIGS. 2-4, each of the blades has a
plurality of cutters. Preferably, the cutters are Polycrystalline
Diamond Compact (PDC) cutters. However, other materials, such as
aluminum oxide, silicon carbide, or cubic boron nitride can be
used. Each of the cutters is preferably 7/11 of an inch (16 mm) in
diameter, however the cutters can have other diameters (i.e., 1/2
an inch, 3/4 of an inch, or 5/8 of an inch). The cutters are
preferably replaceable and rotatable. In certain embodiments, the
cutters have a beveled outer edge to prevent chipping and reduce
the torque generated from the cutting structure. In a preferred
embodiment, the blades have at least one dome slider 555, as shown
in FIG. 5. Preferably, the dome slider 555 is made of the same
material as the cutters. The dome slider 555 is preferably a
rounded or semi rounded surface that reduces friction with the
wellbore wall while the system slides though the wellbore, thus
protecting the cutters from damage. The dome sliders 555 contact
the surface of the wellbore 550 wall or casing and create a
standoff of the reamer blade which aids in the ability of the
system 100 to slide through the wellbore 550 when the drill string
is not in rotation. Additionally, during operation of system 100,
dome sliders 555 allow the system to rotate within wellbore 550
with less friction than without the dome sliders, thereby
decreasing the torque needed to rotate the system and reducing the
damage to the casing and the cutting structure of the tool during
the tripping operation. Furthermore, as the system 100 slides
through or rotates within a casing, the dome sliders 555 protect
the casings from the cutters.
[0028] Returning to FIG. 1, disposed on either side of each of
reamers 115a and 115b are preferably recesses 120a and 120b.
Recesses 120a and 120b have a smaller diameter than the body of
shafts 105a and 105b. Preferably, recesses 120a and 120b facilitate
debris removal while system 100 is conditioning. Furthermore,
recesses 120a and 120b may increase the ease of milling reamers
115a and 115b.
[0029] Reamers 115a and 115b are preferably disposed along the
shaft at a predetermined distance apart. For example, the reamers
can be 4 feet, 5 feet, 6 feet, or another distance apart. The
distance between reamers 115a and 115b as well as the rotational
angle of reamers 115a and 115b can be optimized based on the
characteristics (e.g., the desired diameter and curvature) of the
wellbore. The further apart, both in distance and rotation angle,
the two reamers are positioned, the narrower the wellbore system
100 can drift through. The outer reamer body diameter plays a
critical part in the performance of system 100. Furthermore, having
adjustable positioning of the reamers 115a and 115b allows system
100 to achieve multiple pass-thru/drift requirements using the
single tool.
[0030] Preferably, system 100 is positioned at a predetermined
location up-hole from the directional bottom-hole assembly. The
directional bottom-hole assembly may included, for example, the
drill bit, bit sub, downhole mud motor (e.g. a bent housing motor),
and a measurement-while-drilling device, drill collars, a
directional control device, and other drilling devices. By placing
the wellbore conditioning system in or around the bottom hole
assembly of the drill string, the reaming tool will have little to
no adverse affect on the ability to steer the directional assembly
or on the rate of penetration, and can achieve the desired build or
drop rates.
[0031] Other embodiments and uses of the invention will be apparent
to those skilled in the art from consideration of the specification
and practice of the invention disclosed herein. All references
cited herein, including all publications, U.S. and foreign patents
and patent applications, are specifically and entirely incorporated
by reference. It is intended that the specification and examples be
considered exemplary only with the true scope and spirit of the
invention indicated by the following claims. Furthermore, the term
"comprising of" includes the terms "consisting of" and "consisting
essentially of."
* * * * *