U.S. patent application number 12/258610 was filed with the patent office on 2010-04-29 for self-stabilized and anti-whirl drill bits and bottom-hole assemblies and systems for using the same.
Invention is credited to Riadh Boualleg, Steven Hart, Kjell Haugvaldstad, Bertrand Lacour, OLIVIER SINDT.
Application Number | 20100101867 12/258610 |
Document ID | / |
Family ID | 41506506 |
Filed Date | 2010-04-29 |
United States Patent
Application |
20100101867 |
Kind Code |
A1 |
SINDT; OLIVIER ; et
al. |
April 29, 2010 |
SELF-STABILIZED AND ANTI-WHIRL DRILL BITS AND BOTTOM-HOLE
ASSEMBLIES AND SYSTEMS FOR USING THE SAME
Abstract
A wellsite system includes a drill string suspended within a
borehole, and a bottom hole assembly with a drill bit at its lower
end, where the drill bit is a self stabilized and anti-whirl drill
bit. The drill bit includes an interior cavity in fluid
communication with the drill string, and a plurality of gauge pads
located on the exterior of the drill bit. One or more of the gauge
pads include an orifice in communication with the interior cavity,
where the orifice is arranged at an angle relative to cutters fixed
to the drill bit. The drill bit is configured such that a fluid
continuously flows from each of the orifices.
Inventors: |
SINDT; OLIVIER;
(Gloucestershire, GB) ; Hart; Steven; (Bristol,
GB) ; Lacour; Bertrand; (Willingham, GB) ;
Boualleg; Riadh; (Cambridge, GB) ; Haugvaldstad;
Kjell; (Vanvikan, NO) |
Correspondence
Address: |
SCHLUMBERGER OILFIELD SERVICES
200 GILLINGHAM LANE, MD 200-9
SUGAR LAND
TX
77478
US
|
Family ID: |
41506506 |
Appl. No.: |
12/258610 |
Filed: |
October 27, 2008 |
Current U.S.
Class: |
175/393 |
Current CPC
Class: |
E21B 17/1092 20130101;
E21B 10/602 20130101; E21B 10/61 20130101 |
Class at
Publication: |
175/393 |
International
Class: |
E21B 10/60 20060101
E21B010/60 |
Claims
1. A drill bit, comprising: an interior cavity in fluid
communication with a drill string; a plurality of gauge pads
located on the exterior of the drill bit, at least one of the gauge
pads being formed with a plurality of cutters; and one or more of
the gauge pads having an orifice in communication with the interior
cavity, the orifice being positioned at an angle of approximately
90.degree. relative to the plurality of cutters arranged on the
respective gauge pad, wherein the drill bit is configured such that
a fluid continuously flows from each of the orifices to provide a
net stabilizing effect.
2. The drill bit of claim 1, wherein the fluid flow is sufficient
to urge the drill bit away from a wall of a borehole.
3. The drill bit of claim 1, wherein the drill bit comprises the
plurality of gauge pads each having an orifice in communication
with the interior cavity.
4. The drill bit of claim 3, wherein the drill bit comprises three
gauge pads each having an orifice in communication with the
interior cavity.
5. The drill bit of claim 4, wherein the orifices are spaced about
120.degree. on center around the exterior of the drill bit.
6-8. (canceled)
9. A bottom hole assembly, comprising: an interior cavity in fluid
communication with a drill string; a plurality of stabilization
pads located on the exterior of the bottom hole assembly, at least
one of the stabilization pads being formed with a plurality of
cutters; and one or more of the stabilization pads having an
orifice in communication with the interior cavity to provide a net
stabilizing force to the bottom hole assembly, wherein the orifice
is positioned at an angle of approximately 90.degree. relative to
the plurality of cutters arranged on the respective stabilization
pad.
10. The bottom hole assembly of claim 9, wherein the bottom hole
assembly is configured such that a fluid continuously flows from
each of the one or more orifices.
11. The bottom hole assembly of claim 10, wherein the fluid flow is
sufficient to urge the drill bit away from a wall of a borehole
thereby stabilizing said drill bit in the borehole.
12. The bottom hole assembly of claim 9, wherein the bottom hole
assembly comprises the plurality of stabilization pads each having
an orifice in communication with the interior cavity.
13. The bottom hole assembly of claim 12, wherein the bottom hole
assembly comprises three stabilization pads each having an orifice
in communication with the interior cavity.
14. The bottom hole assembly of claim 13, wherein the orifices are
spaced about 120.degree. on center around the exterior of the
bottom hole assembly.
15-16. (canceled)
17. A wellsite system comprising: a drill string; a kelly coupled
to the drill string; and a drill bit comprising: an interior cavity
in fluid communication with the drill string; a plurality of gauge
pads located on the exterior of the drill bit, at least one of the
gauge pads being formed with a plurality of cutters; and one or
more of the gauge pads having an orifice in communication with the
interior cavity, the orifice being positioned at an angle of
approximately 90.degree. relative to the plurality of cutters
arranged on the respective gauge pad, wherein the drill bit is
configured such that a fluid continuously flows from at least one
of said orifices to provide a net stabilizing effect on the
wellsite system.
Description
FIELD OF THE INVENTION
[0001] The present invention relates to systems and methods for
preventing whirl and other deviations of the drill bit and/or
bottom-hole assembly while drilling within a wellbore.
BACKGROUND OF THE INVENTION
[0002] Drill bit whirl and deviations are a significant problem
within the drilling industry. Oil, gas, water, and other natural
resources are often located between 4,000 and 10,000 feet below
ground. As a result, even a one-degree deviation of an well can
result in a significant increase in drilling distance, time and
cost.
[0003] In some application, the driller seeks a vertical wellbore.
A smooth vertical wellbore facilitates running larger casing with
minimal clearance and affords the possibility of using an extra
string of casing at some later state in well construction
operations. A wellbore that drifts away from and back into
verticality can eliminate this option. Additionally, if multiple
wellbore are drilled from a single platform, deviations can cause
drill string collisions.
[0004] Even in controlled steering or directional drilling
applications, it may be highly desirable to maintain the desired
trajectory, for example when drilling to targets below faulted
rocks, in steeply dipping beds, or in tectonically active
areas.
[0005] Additionally, drill bit whirl, a condition wherein the bit's
center of rotation shifts away from its geometric center, leads to
several problems. These problems include non-cylindrical holes,
wellbore deviation, and excessive bit wear.
[0006] Conventional anti-whirl drill bits attempt to reduce whirl
by creating an imbalanced side force by cutter(s)-rock interaction.
This imbalance force will only have a predictable magnitude and
direction if the cutting action is smooth and continuous and the
cutters are not worn or damaged. Neither of these conditions occur
regularly as cutting action is often a discrete process rather than
a continuous one (as when the cutters generate chips rather than
continuous cuttings). When the rock is removed by a chipping
action, the magnitude and direction is neither constant nor
predictable.
[0007] Accordingly, there is a continued need for apparatus and
methodology for preventing whirl and deviations.
SUMMARY OF THE INVENTION
[0008] This section will be added once the claims are
finalized.
DESCRIPTION OF THE DRAWINGS
[0009] For a fuller understanding of the nature and desired objects
of the present invention, reference is made to the following
detailed description taken in conjunction with the accompanying
drawing figures wherein like reference characters denote
corresponding parts throughout the several views and wherein:
[0010] FIG. 1 illustrates a wellsite system in which the present
invention can be employed.
[0011] FIG. 2 illustrates a drill bit according to the present
inventions.
[0012] FIG. 2A illustrates a drill bit according to the present
inventions within a borehole.
[0013] FIG. 3A illustrates a cross-section of a drill bit centered
within a borehole.
[0014] FIG. 3B illustrates a cross-section of a drill bit located
off-center within a borehole.
DETAILED DESCRIPTION OF THE INVENTION
[0015] The present invention provides apparatus and methods for
preventing whirl and other deviations of the drill bit and/or
bottom-hole assembly while drilling within a wellbore.
[0016] The inventions provide herein are adapted for use in a range
of drilling operations such as oil, gas, and water drilling. As
such, the bit body is designed for incorporation in wellsite
systems that are commonly used in the oil, gas, and water
industries. An exemplary wellsite system is depicted in FIG. 1.
[0017] FIG. 1 illustrates a wellsite system in which the present
invention can be employed. The wellsite can be onshore or offshore.
In this exemplary system, a borehole 11 is formed in subsurface
formations by rotary drilling in a manner that is well known.
Embodiments of the invention can also use directional drilling, as
will be described hereinafter.
[0018] A drill string 12 is suspended within the borehole 11 and
has a bottom hole assembly 100 which includes a drill bit 105 at
its lower end. The surface system includes platform and derrick
assembly 10 positioned over the borehole 11, the assembly 10
including a rotary table 16, kelly 17, hook 18 and rotary swivel
19. The drill string 12 is rotated by the rotary table 16,
energized by means not shown, which engages the kelly 17 at the
upper end of the drill string. The drill string 12 is suspended
from a hook 18, attached to a traveling block (also not shown),
through the kelly 17 and a rotary swivel 19 which permits rotation
of the drill string relative to the hook. As is well known, a top
drive system could alternatively be used.
[0019] In the example of this embodiment, the surface system
further includes drilling fluid or mud 26 stored in a pit 27 formed
at the well site. A pump 29 delivers the drilling fluid 26 to the
interior of the drill string 12 via a port in the swivel 19,
causing the drilling fluid to flow downwardly through the drill
string 12 as indicated by the directional arrow 8. The drilling
fluid exits the drill string 12 via ports in the drill bit 105, and
then circulates upwardly through the annulus region between the
outside of the drill string and the wall of the borehole, as
indicated by the directional arrows 9. In this well known manner,
the drilling fluid lubricates the drill bit 105 and carries
formation cuttings up to the surface as it is returned to the pit
27 for recirculation.
[0020] The bottom hole assembly 100 of the illustrated embodiment
includes a logging-while-drilling (LWD) module 120, a
measuring-while-drilling (MWD) module 130, a roto-steerable system
and motor, and drill bit 105.
[0021] The LWD module 120 is housed in a special type of drill
collar, as is known in the art, and can contain one or a plurality
of known types of logging tools. It will also be understood that
more than one LWD and/or MWD module can be employed, e.g. as
represented at 120A. (References, throughout, to a module at the
position of 120 can alternatively mean a module at the position of
120A as well.) The LWD module includes capabilities for measuring,
processing, and storing information, as well as for communicating
with the surface equipment. In the present embodiment, the LWD
module includes a pressure measuring device.
[0022] The MWD module 130 is also housed in a special type of drill
collar, as is known in the art, and can contain one or more devices
for measuring characteristics of the drill string and drill bit.
The MWD tool further includes an apparatus (not shown) for
generating electrical power to the downhole system. This may
typically include a mud turbine generator powered by the flow of
the drilling fluid, it being understood that other power and/or
battery systems may be employed. In the present embodiment, the MWD
module includes one or more of the following types of measuring
devices: a weight-on-bit measuring device, a torque measuring
device, a vibration measuring device, a shock measuring device, a
stick slip measuring device, a direction measuring device, and an
inclination measuring device.
[0023] A particularly advantageous use of the system hereof is in
conjunction with controlled steering or "directional drilling." In
this embodiment, a roto-steerable subsystem 150 (FIG. 1) is
provided. Directional drilling is the intentional deviation of the
wellbore from the path it would naturally take. In other words,
directional drilling is the steering of the drill string so that it
travels in a desired direction.
[0024] Directional drilling is, for example, advantageous in
offshore drilling because it enables many wells to be drilled from
a single platform. Directional drilling also enables horizontal
drilling through a reservoir. Horizontal drilling enables a longer
length of the wellbore to traverse the reservoir, which increases
the production rate from the well.
[0025] A directional drilling system may also be used in vertical
drilling operation as well. Often the drill bit will veer off of a
planned drilling trajectory because of the unpredictable nature of
the formations being penetrated or the varying forces that the
drill bit experiences. When such a deviation occurs, a directional
drilling system may be used to put the drill bit back on
course.
[0026] A known method of directional drilling includes the use of a
rotary steerable system ("RSS"). In an RSS, the drill string is
rotated from the surface, and downhole devices cause the drill bit
to drill in the desired direction. Rotating the drill string
greatly reduces the occurrences of the drill string getting hung up
or stuck during drilling. Rotary steerable drilling systems for
drilling deviated boreholes into the earth may be generally
classified as either "point-the-bit" systems or "push-the-bit"
systems.
[0027] In the point-the-bit system, the axis of rotation of the
drill bit is deviated from the local axis of the bottom hole
assembly in the general direction of the new hole. The hole is
propagated in accordance with the customary three point geometry
defined by upper and lower stabilizer touch points and the drill
bit. The angle of deviation of the drill bit axis coupled with a
finite distance between the drill bit and lower stabilizer results
in the non-collinear condition required for a curve to be
generated. There are many ways in which this may be achieved
including a fixed bend at a point in the bottom hole assembly close
to the lower stabilizer or a flexure of the drill bit drive shaft
distributed between the upper and lower stabilizer. In its
idealized form, the drill bit is not required to cut sideways
because the bit axis is continually rotated in the direction of the
curved hole. Examples of point-the-bit type rotary steerable
systems, and how they operate are described in U.S. Patent
Application Publication Nos. 2002/0011359; 2001/0052428 and U.S.
Pat. Nos. 6,394,193; 6,364,034; 6,244,361; 6,158,529; 6,092,610;
and 5,113,953 all herein incorporated by reference.
[0028] In the push-the-bit rotary steerable system there is usually
no specially identified mechanism to deviate the bit axis from the
local bottom hole assembly axis; instead, the requisite
non-collinear condition is achieved by causing either or both of
the upper or lower stabilizers to apply an eccentric force or
displacement in a direction that is preferentially orientated with
respect to the direction of hole propagation. Again, there are many
ways in which this may be achieved, including non-rotating (with
respect to the hole) eccentric stabilizers (displacement based
approaches) and eccentric actuators that apply force to the drill
bit in the desired steering direction. Again, steering is achieved
by creating non co-linearity between the drill bit and at least two
other touch points. In its idealized form the drill bit is required
to cut side ways in order to generate a curved hole. Examples of
push-the-bit type rotary steerable systems, and how they operate
are described in U.S. Pat. Nos. 5,265,682; 5,553,678; 5,803,185;
6,089,332; 5,695,015; 5,685,379; 5,706,905; 5,553,679; 5,673,763;
5,520,255; 5,603,385; 5,582,259; 5,778,992; 5,971,085 all herein
incorporated by reference.
[0029] Particular embodiments of the inventions described herein
provide drill bits 105 and bottom-hole assemblies 100 for reducing
whirl and/or deviations.
Anti-Whirl Bits
[0030] FIG. 2 depicts a drill bit 105. Drill bit 105 includes a
trailing end 202 and a cutting portion 204. Trailing end 202 is
adapted for direct or indirect connection with drill string 12.
Cutting portion 204 includes one or more ribs 206a, 206b, 206c,
206d. Ribs 206 include gauge sections 208, which contact the walls
of the borehole that has been drilled by cutters 210. Although
cutters 210 are only depicted on rib 206b, cutters 210 can be
configured on a plurality or all of ribs 206 as advantageous for
particular drilling situations.
[0031] In embodiments of the present invention, one or more
orifices 212 are located on the exterior of drill bit 105. Orifices
212 can be located on gauge sections 208 or in valleys 214 between
ribs 206. The orifices 212 allow fluid 26 from the interior of
drill string 12 to exit the drill bit to achieve stability and
reduce whirl. Additional orifices can be located on drill bit 105,
for example, on the leading end 216 for lubrication and removal of
cuttings as is known in the art.
[0032] In some embodiments, drill bit 105 contains a single orifice
212. Drill fluid 26 flows from orifice 212, and contacts the wall
of borehole 11, creating a side force substantially perpendicular
to the orientation of orifice 212 and gauge section 208. This
force, creates an anti-whirl effect.
[0033] In some embodiments, the orifice 212 is positioned
substantially opposite from the majority of cutters 210. For
example, if the cutters 210 are located longitudinally along the
drill bit 105, the orifice 212 can be located about 180.degree.
from the cutters 210. In such an embodiment, drill fluid released
from the orifice 212 creates a side force that pushes the bit in
the direction of the cutters 210. This embodiment (1) causes in
increased contact between cutters 210 and the wall of borehole 11,
and/or (2) neutralizes side forces resulting from contact between
the cutters 210 and the borehole wall.
[0034] In other embodiments, the orifice 212 is positioned
approximately 90.degree. behind the majority of the cutters 210. As
illustration of this principle, consider the situation depicted in
FIG. 2A. Drill bit 105 is rotating counter-clockwise in borehole
11. Cutters 210 are about to impact a protuberance 218 from
borehole wall 220. If protuberance 218 is particularly strong
material, protuberance will remain intact at least momentarily when
first contacted by cutters 210. The rotational force on drill bit
105 will cause drill bit 105 to move in the negative y direction
until gauge pad 206a contacts borehole wall 220. However, if
orifice 212 is located on gauge pad 206a, the drilling fluid 26
will generate a force in the positive y direction, counteracting
the tendency of the drill bit 105 to move off center. Moreover, the
positive y force moves the entire bit 105, thereby providing
additional force to cutters 210 and assisting in borehole
propagation.
[0035] Other cutter 210 and orifice 212 configurations are within
the scope of these inventions. For example, the aggregate force
vector generated by the rotation of the drill bit 105 and contact
with a plurality of cutters 210 can be calculated using known
equations and technology. The orifice 212 can be configured to
counteract the most probable force vectors.
[0036] By utilizing the hydraulic force of drilling fluid 26 from
orifice 212, drill bits 105 produce a more predictable and constant
imbalance force to reduce and/or prevent bit whirl. The direction
of the imbalance force is known given the position of the port. The
magnitude of the imbalance force is a function of the distance
between the orifice 212 and borehole wall 220, the differential
pressure between the drilling fluid 26 in the borehole and the
drilling fluid 26 in the drill string 12, and the geometry (e.g.
shape and size) of the orifice 212. Furthermore, wear and damage to
the cutters 210 should not affect the amplitude and direction of
the side force.
[0037] In some embodiments, the exterior of orifice 212 is
surrounding by a raised annulus or other geometric feature in order
to form greater hydraulic pressure as drilling fluid 26 exits
orifice 212. Such a feature and/or the entire gauge section 206 can
be coated with or fabricated entirely from a wear resistant or
hardfaced material such as polycrystalline diamond (PCD).
Self-Stabilized Bits and Bottom Hole Assemblies
[0038] Another embodiment of the invention utilizes one or more
orifices 212 to stabilize a drill bit 105 and/or bottom hole
assembly (BHA) within a borehole.
[0039] FIG. 3A depicts a cross-section of a drill bit 105 with
three gauge pads 206a, 206b, 206c generally spaced (e.g. 1200 on
center) around the circumference of the drill bit 105, each having
an orifice 212a, 212b, 212c, respectively. Drilling fluid 26
(represented by the thick lines) flows from inside the drill bit
105 through orifices 212a, 212b, 212c.
[0040] The drill bit 105 depicted in FIG. 3A is generally centered
within borehole 11. Accordingly, any hydraulic forces created by
the drilling fluid will cancel each other. However, if drill bit
105 moves off center as depicted in FIG. 3B, the amplitude of the
force vector generated by drilling fluid 26 from orifice 212a will
increase as the space between orifice 212a and borehole wall 220
decrease. Concurrently, any force vector generated by orifices 212b
and 212c will decrease, resulting in a net force vector
(represented by arrow 222) pushing the bit away from the wall
220.
[0041] In some embodiments, fluid flow to the one or more orifices
is limited by one or more valve (e.g. choke valves). A single valve
may be connected to each orifice by tubing or other means. More
preferably, each orifice is independently regulated by a separate
valve. Independent regulation ensures that the volume of drilling
fluid 26 flowing to a particular orifice 212 does not increase
beyond a desired threshold so as to deprive other orifices 212 or
other ports (e.g. ports located on the leading edge 216 of drill
bit 105).
[0042] While the embodiment in FIGS. 3A and 3B depicts a drill bit
105 with three orifices 212, the inventions described herein
encompass the use of fluid with any number of orifices 212 for the
stabilization of a drill bit 105 or bottom hole assembly. For
example, a drill bit 105 with a single orifice would produce a
similar effect as a drill bit 105 with three orifices. As the drill
bit 105 rotated, the force generated by the single orifice would
increase in amplitude as the orifice passed through regions in
which the drill bit 105 was closer to the borehole wall 220. This
increased force would urge the drill bit 105 back center.
Furthermore, drill bits and bottom hole assemblies having two,
three, four, five, or six orifices, and the like are within the
scope of the invention.
[0043] The principles described herein can be applied to
stabilization pads located along the exterior of bottom hole
assembly 100 and other portions of the drill string 12.
Stabilization pads act similarly to gauge pads to minimize movement
of the bottom hole assembly and drill string. In such an
embodiment, one or more orifices are added to one or more
stabilization pads to allow drilling fluid 26 to act as described
herein.
Combination Anti-Whirl and Self-Stabilized Bits
[0044] The principles of anti-whirl and self-stabilized bits
described herein can be combined to produce a bit 105 that produces
net imbalanced side force to reduce whirl while still providing one
or more orifices to correct a drift from center of the borehole 11.
In such an embodiment, one of a plurality of orifices 212 is larger
in cross-sectional area to produce an imbalance side force.
[0045] The foregoing specification and the drawings forming part
hereof are illustrative in nature and demonstrate certain preferred
embodiments of the invention. It should be recognized and
understood, however, that the description is not to be construed as
limiting of the invention because many changes, modifications and
variations may be made therein by those of skill in the art without
departing from the essential scope, spirit or intention of the
invention.
* * * * *