Note: Descriptions are shown in the official language in which they were submitted.
Systems and Methods for Minimizing Downhole Tool Vibrations and Disturbances
Background
[0001] This section is intended to introduce the reader to various aspects of
art that may be
related to various aspects of the presently described embodiments. This
discussion is believed to
be helpful in providing the reader with background information to facilitate a
better
understanding of the various aspects of the described embodiments.
Accordingly, it should be
understood that these statements are to be read in this light and not as
admissions of prior art.
[0002] Downhole drilling system can be subject to various vibrations and
disturbances during
a drilling operation. Generally, vibrations and disturbances can be classified
into three types:
axial, torsional, and lateral. The occurrences of these vibrations or
disturbances often lead to
excessive wear on downhole tools, increased logging error, and even immediate
damage of the
downhole tools. For example, axial vibrations such as bit bounce may damage
bit cutter and
bearings. Lateral vibrations may cause a drill string or bottom hole assembly
to impact the
wellbore wall. Stick slip is a type of torsional vibration in which the drill
bit becomes stationary,
or stuck, for a period of time and then exerts a rotational acceleration as
the bit breaks free.
Typically disturbances such as stick-slip may be controlled by altering the
surface parameters to
find the combination of rotary speed (RPM) and weight on bit (WOB) which
minimize the
effects of a stick-slip event. Specifically, the RPM and WOB are increased
and/or decreased on a
trial and error basis, allowing the downhole tool operators to find the
smoothest combination. In
the majority of cases controlling stick-slip usually means scarifying
performance, penetration
rate (ROP) as parameters are usually reduced to limit the depth of cut by the
polycrystalline
diamond compact (PDC) drill bit.
Summary
[0002a] In
accordance with a general aspect, there is provided a downhole vibration
minimization device, comprising: a housing comprising a drilling fluid flow
path; a sensor
configured to sense a vibration frequency and amplitude of a tool vibration;
and a force generator
configured to open and close the drilling fluid flow path at a pulse frequency
approximately 180
degrees out of phase with the vibration frequency, thereby minimizing the tool
vibration.
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10002b] In accordance with another aspect, there is provided a downhole
vibration
minimization device, comprising: a housing comprising a wall comprising a
housing side
opening formed therein; an inner spool located within the housing, the inner
spool comprising a
wall surrounding a drilling fluid flow path, the wall comprising a spool side
opening formed
therein; wherein the inner spool is rotatable with respect to the housing,
controllably overlapping
and separating the housing side opening and the spool side opening; and
wherein overlapping of
the housing side opening and the spool side opening places the drilling fluid
flow path in fluid
communication with an annular space external to the housing.
10002c] In accordance with a further aspect, there is provided a method of
drilling a well
with a downhole tool, comprising: sensing a vibration of a downhole tool, the
vibration having a
vibration frequency and amplitude; opening and closing a drilling fluid flow
path based on the
vibration frequency and amplitude; and generating forces at a pulse frequency
from the opening
and closing of the drilling fluid flow path to minimize the vibration of the
downhole tool.
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Brief Description of the Drawings
[0003] For a detailed description of the embodiments of the invention,
reference will now be made to the accompanying drawings in which:
[0004] FIG. 1 depicts a drilling system with a vibration minimization system
performing a well drilling operation, in accordance with example
embodiments;
[0005] FIG. 2A depicts a transverse cross-sectional view of a downhole
vibration minimization device for axial pulse generation, in accordance with
example embodiments;
[0006] FIG. 2B depicts a radial cross-sectional view of the device of FIG. 2A,
in accordance with example embodiments;
[0007] FIG. 3A depicts a transverse cross-sectional view of a downhole
vibration minimization device for radial pulse generation, in accordance with
example embodiments;
[0008] FIG. 3B depicts a radial cross-sectional view of the device of FIG. 3A,
in accordance with example embodiments;
[0009] FIG. 4A depicts a transverse cross-sectional view of a downhole
vibration minimization device for tangential pulse generation, in accordance
with example embodiments; and
[0010] FIG. 4B depicts a radial cross-sectional view of the device of FIG. 4A,
in accordance with example embodiments.
Detailed Description
[0011] The present disclosure is directed towards systems and methods for
minimizing vibrations and disturbances of a downhole tool commonly caused
by stick-slip, bit bounce, bit whirl, lateral shocks, resonance, and the like.
Specifically, the present disclosure is directed towards a vibration
minimization
system that senses vibrations or disturbances experienced by the downhole
tool. The system then generates movements which antagonize the vibrations or
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disturbances, thereby minimizing or even cancelling out the vibrations or
disturbances. The movements are generated by the opening and closing of a
drilling fluid flow path.
[0001] The system of the present disclosure will be specifically described
below such that the system is used to minimize tool vibrations and
disturbances
in a wellbore, such as a subsea well or a land well. Further, it will be
understood that the present disclosure is not limited to only drilling an oil
well.
The present disclosure also encompasses natural gas wellbores, other
hydrocarbon wellbores, or wellbores in general. Further, the present
disclosure
may be used for the exploration and formation of geothermal wellbores
intended to provide a source of heat energy instead of hydrocarbons.
[0002] Referring to the drawings, FIG. 1 depicts a drilling system 100
performing a well drilling operation, in accordance with example
embodiments. The drilling system 100 includes a drill string 102 disposed in a
directional wellbore 101. The drill string 102 includes a plurality of drill
pipes
104 coupled end to end extending from the surface 106. The drill string 102
further includes a bottom hole assembly (BHA) 108 coupled to the drill pipes
104 at the distal end of the drill string 102. The drill pipes 104 provide the
length needed for the BHA to reach well bottom and to advance further into the
wellbore 116. The BHA 108 includes various tools for carrying out the
functions of the drilling operation. Specifically, in some embodiments, the
BHA 108 includes one or more measurement while drilling and/or logging
while drilling (MWD/LWD) tools 110, a vibration minimization device 112, a
motor or rotary steerable system (RSS) 114, a drill bit 116, and a telemetry
module 118.
[0003] The drilling system 100 further includes surface equipment such as a
derrick 122 and a mud pump 124. The derrick is configured to raise, lower,
and support the drill string 102 downhole. In some embodiments, the derrick
includes a kelly 126 that supports the drill string 102 as the drill string
102 is
lowered through a rotary table 128 which rotates the drill string 102. In one
or
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more embodiments, a topdrive is used to rotate the drill string 102 in place
of
the kelly 126 and the rotary table 128. In such embodiments, the drill bit 116
is
driven via rotation of the entire drill string 102 from the surface.
Alternatively,
in some embodiments, the drill bit 116 may be driven by the motor or RSS 114
without rotating the rest of the drill string 102. As the drill bit 116
rotates, the
drill bit 116 creates the wellbore 101 that passes through various formations
120.
[0004] The mud pump 124 circulates drilling fluid through a feed pipe 130
and downhole through the interior of drill string 102, through orifices in
drill
bit 116 or elsewhere along the drill string 102, and back to the surface via
an
annulus 132 around the drill string 102, and back to the surface 106. The
drilling fluid removes cuttings from the wellbore 101 and aids in maintaining
the integrity of the wellbore 101. The drilling fluid may also drive the motor
or
RSS 114.
[0005] The MWD/LWD tools 110 collect measurements and data relating to
various wellbore and formation properties as well as the position of the drill
bit
116 and various other drilling conditions as the drill bit 116 extends the
wellbore 116 through the formations 120. The LWD/MWD tools 110 may
include a device for measuring formation resistivity, a gamma ray device for
measuring formation gamma ray intensity, devices for measuring the
inclination and azimuth of the drill bit 116, pressure sensors for measuring
drilling fluid pressure, temperature sensors for measuring borehole
temperature, among others.
[0006] The telemetry module 118 receives data provided by the various
sensors of the drill string 102 (e.g., sensors of the MWD/LWD tools 110, motor
or RSS 114), and transmits the data to a surface control unit 134. Data may
also
be provided by the surface control unit 134, received by the telemetry module
118, and transmitted to the tools (e.g., LWD/MWD tools 110, motor or RSS
114) of the drill string 102. In one or more embodiments, mud pulse telemetry,
wired drill pipe, acoustic telemetry, or other telemetry technologies known in
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the art may be used to provide communication between the surface control unit
134 and the telemetry module 118.
[0007] In one or more embodiments, the surface control unit 134 may
communicate directly with the LWD/MWD tools 110 and/or the motor or RSS
114. The surface control unit 134 may be a computer stationed at the well
site,
a portable electronic device, a remote computer, or distributed between
multiple locations and devices. The surface control unit 134 may also control
functions of the equipment of the drill string 102 or derrick 122.
[0008] As the drill bit 116 drills through the formation 120, the BHA 108 may
experience various physical disturbances such as stick-slip, bit bounce, bit
whirl, shocks, resonance, and the like. These disturbances may cause excess
vibration or undesired movements of the BHA 108. The vibration minimization
device 112 is configured to generate pulses or movements aimed at neutralizing
these vibrations or disturbances, thereby cancelling out the vibrations or
disturbances.
[0009] FIG. 2A depicts a transverse cross-sectional view of a downhole
vibration minimization device 200 for axial force generation, in accordance
with example embodiments. FIG. 2B depicts a radial cross-sectional view of
the same device 200. In some embodiments, the device 200 includes a housing
202 having a drilling fluid flow path 204, a sensor 206 configured to sense a
vibration frequency of a tool vibration, and a force generator 208 configured
to
open and close the drilling fluid flow path 204. When the drilling fluid flow
path 204 is open, drilling fluid can flow through the device 200. In some
embodiments, the drilling fluid flow path 204 is kept open when the device 200
is inactive. Closing of the drilling fluid flow path 204 while drilling fluid
is
being injected through the drill string 102 causes an axial force to be
applied in
the direction of the fluid impact against a barrier, acting as a fluid hammer.
[0010] The pulse generator 208 can be constructed in many ways. In one or
more embodiments, the pulse generator 208 includes a first disk 210 and a
second disk 212 located inside the housing and in the drilling fluid flow
path.
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In some embodiments, the first disk 210 and the second disk 212 are located
within the housing 202 and axially adjacent to each other. The first disk 210
and the second disk 212 are also rotatable with respect to each other. Each of
the disks 210, 212 includes at least one flow passage 214. The example disks
in
FIG. 2 each have four flow passages 214, but the disks 210, 212 can be
designed to have any number, shape, or size of flow passes.
[0011] When the first disk 210 and the second disk 212 are rotated into a
position in which at least one flow passage 214 of the first disk 210 overlaps
at
least one flow passage 214 of the second disk 214, the overlap provides an
opening 216 for the drilling fluid to pass, thereby opening the drilling fluid
flow path 204. When first disk 210 and the second disk 212 are rotated into a
position in which the flow passages 214 are separated and there is no overlap,
the disks 210, 212 become a barrier and the drilling fluid flow path 204 is
closed. Controlled rotation of the disks 210, 212 with respect to one another
brings the flow passages 214 into and out of overlap, thereby controllably
opening and closing the drilling fluid flow path 204.
[0012] The pulse generator 208 further includes a motor 218 coupled to at
least one of the first disk 210 or second disk 212. In some embodiments, the
motor 218 is couple to the disk via a shaft 220. The motor 218 controls
rotation
of the disks 210, 212 with respect to each other, thereby controlling opening
and closing of the drilling fluid flow path 204. The motor 218 may include an
electric motor, a hydraulic motor, or any other rotational drive mechanism.
One
of the first and second disks 210, 212 is a stationary disk and coupled to the
housing 202, and the other is a rotating disk coupled to the motor 218 and
configured to rotate with respect to the stationary disk and the housing 202.
[0013] In one or more embodiments, the sensor 206 is configured to sense
vibrations and disturbances of the BHA 108 and a processing unit 222 receives
the sensor readings. The vibrations and disturbance may be represented as a
waveform having a vibration frequency and amplitude. In one example, fast
Fourier transfoim processing of the vibration sensor signals may be used to
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produce the spectra of the downhole BHA vibration. Using this data, a pulsing
scheme is determined for controlling opening and closing of the drilling fluid
flow path 204. Using feedback control, the pulse generator 208 may be
controlled in real time to reduce the downhole vibrations. In some
embodiments, the pulsing scheme is configured to have a frequency
approximately 180 degrees offset from the frequency of the BHA vibration,
thereby substantially cancelling out the BHA vibrations. The pulse generator
208 is controlled to open and close the drilling fluid flow path 204,
generating
pulses according to the pulse scheme. The terms approximately and
substantially are used herein to be inclusive of a margin of error while
remaining within the scope of the present disclosure.
[0014] In one or more embodiments, the motor 218 controllably drives the
rotating disk 212 in a constant circular direction while varying the
rotational
speed based on pulse scheme. In some embodiments, the pulse amplitude is
related to the amount of flow that is restricted as the flow passages 214 in
the
rotating disk 212 rotate out of alignment with the flow passages 214 in the
stationary disk 210. Thus, the amplitude of the pulse may be controlled to
match that of the BHA vibrations. The rotating disk 212 may be controlled to
rotationally oscillate back and forth. For example, the amplitude may be
controlled by adjusting the amount of angular rotation of the rotating disk
212
relative to the stationary disk 210 such that only a controllable portion of
the
flow passages 214 overlap. The pulse frequency may be adjusted by the
frequency of the back and forth oscillation of the rotating disk 212. In some
embodiments, the pulse generator 208 may have multiple controlled rotating
disk mechanisms for adjusting more than one frequency at a time.
[0015] As the opening and closing of the drilling fluid flow path 204 affects
the flow of the drilling fluid, the pulses may interfere with mud pulse
telemetry
signals which are carried by the same drilling fluid. To resolve this, the
telemetry module 118 is configured to detect the pulses generated by the pulse
generator 208 and search for a new transmission frequency range which is
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outside of the pulse frequency range. Thus data carried on this transmission
frequency range can be clearly distinguished. In some embodiments, the
surface control unit 134 detects the pulses and searches for the new
transmission frequency range. In some embodiments, the telemetry module 118
or the surface control unit 134 scans multiple band widths for data symbol
content and discard channels that fall within or close to the pulse
frequencies.
In some embodiments, the pulse generator 208 may be used as a mud data
generator, generating pulses which carry data.
[0016] In addition to imparting axial forces on the BHA 108, the controllable
jetting of fluid from the inside of the drill string radially and/or
tangentially out
towards a return annulus may be used to counteract the radial and torsional
forces induced during, for example, stick/slip. FIG. 3A depicts a transverse
cross-sectional view of a downhole vibration extermination device 300 for
radial pulse generation, in accordance with one or more embodiments. FIG. 3B
depicts a radial cross-sectional view of the same device 300. The device 300
includes a housing 302 and an inner spool 304 located within the housing 302.
The inner spool 304 is hollow, creating a drilling fluid flow path 310 and
permitting drilling fluid to flow therethrough. The inner spool 304 is
rotatable
with respect to the housing 302. In some embodiments, the housing 302
includes one or more flow passages 308 formed in the wall of the housing 302.
The inner spool 304 may likewise include one or more flow passages 306
formed in the wall of the inner spool 304.
[0017] The inner spool 304 can be rotated to align or overlap the flow
passages 306 of the inner spool 304 with the flow passages 308 of the housing
302. When the flow passages 306 of the inner spool 304 are aligned or
overlapped with the flow passages 308 of the housing 302, the drilling fluid
flow path 310 inside the inner spool 304 is put in fluid communication with an
annular space outside of the housing 302 via the flow passages 306, 308,
permitting drilling fluid to jet out of the flow passages 306, 308. This
creates a
radial reaction force or pulse in the opposite direction of the jet stream. ln
some
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embodiments, the housing 302 is also rotatable with respect to the wellbore
such that the direction of the radial force can be controlled. In some
embodiments, seals 312 are placed between the inner spool 304 and the
housing 302 to prevent leaking of drilling fluid.
[0018] The frequency and amplitude of the pulses can be determined similar
to the axial pulse generation device 200 of FIGS. 2A and 2B, in which a sensor
detects tool vibrations or disturbances in the radial direction and a
processor
determines a pulse scheme for counteracting and thus cancelling out the tool
vibrations or disturbances. A motor then rotates the inner spool 304 and/or
housing 302 accordingly.
[0001] FIG. 4A depicts a transverse cross-sectional view of a downhole
vibration minimization device 400 for tangential pulse generation, in
accordance with one or more embodiments. FIG. 4B depicts a radial cross-
sectional view of the same device 400. The device 400 includes a housing 402
and an inner spool 404. The inner spool 404 is hollow, creating a drilling
fluid
flow path 410 and permitting drilling fluid to flow therethrough. The inner
spool 404 is also rotatable with respect to the housing 402. The housing 402
includes one or more tangential flow passages 408 formed through the wall of
the housing 402. The inner spool 404 may likewise include one or more flow
passages 406 formed in the wall of the inner spool 404.
[0002] The inner spool 404 can be rotated to align or overlap the flow
passages 406 of the inner spool 404 with the tangential flow passages 408 of
the housing 402. When the flow passages 406 of the inner spool 404 are
aligned or overlapped with the flow passages 406 of the housing 402, the
drilling fluid flow path 410 inside the inner spool 404 is put in fluid
communication with an annular space outside of the housing via the flow
passages 406,408, permitting drilling fluid to flow out of the flow passages
406,408. This creates a tangential reaction force or torque in the opposite
direction of the jet stream, which may result in an angular force. In some
embodiments, the housing 402 is also rotatable with respect to the wellbore
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such that the direction of the tangential reaction force can be controlled. In
some embodiments, seals 412 are placed between the inner spool 404 and the
housing 402 to prevent leaking of drilling fluid.
[0003] The frequency and amplitude of the forces can be determined similar
to the axial vibration extermination system 200 of FIGS. 2A and 2B and radial
pulse generation device 300 of FIGS. 3A and 3B, in which a sensor detects tool
vibrations or disturbances in the radial direction and a processor deteimines
a
force scheme for counteracting and thus minimizing or cancelling out the tool
vibrations or disturbances. A motor then rotates the inner spool 404 and/or
housing 402 accordingly.
[0004] In one or more embodiments, a drilling system 100 may include any
individual or combination of the vibration extermination systems 200, 300,
400, which can be operated in tandem to cancel out combined axial, torsional,
and lateral vibrations and disturbances.
[0005] In addition to the embodiments described above, many examples of
specific combinations are within the scope of the disclosure, some of which
are
detailed below:
[CLAIMS BANK TO BE COMPLETED AFTER CLAIMS ARE
FINALIZED]
[0006] This discussion is directed to various embodiments of the invention.
The drawing figures are not necessarily to scale. Certain features of the
embodiments may be shown exaggerated in scale or in somewhat schematic
form and some details of conventional elements may not be shown in the
interest of clarity and conciseness. Although one or more of these embodiments
may be preferred, the embodiments disclosed should not be interpreted, or
otherwise used, as limiting the scope of the disclosure, including the claims.
It
is to be fully recognized that the different teachings of the embodiments
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discussed may be employed separately or in any suitable combination to
produce desired results. In addition, one skilled in the art will understand
that
the description has broad application, and the discussion of any embodiment is
meant only to be exemplary of that embodiment, and not intended to intimate
that the scope of the disclosure, including the claims, is limited to that
embodiment.
[0007] Certain terms are used throughout the description and claims to refer
to particular features or components. As one skilled in the art will
appreciate,
different persons may refer to the same feature or component by different
names. This document does not intend to distinguish between components or
features that differ in name but not function, unless specifically stated. In
the
discussion and in the claims, the terms "including" and "comprising" are used
in an open-ended fashion, and thus should be interpreted to mean "including,
but not limited to... ." Also, the term "couple" or "couples" is intended to
mean
either an indirect or direct connection. In addition, the terms "axial" and
"axially" generally mean along or parallel to a central axis (e.g., central
axis of
a body or a port), while the teims "radial" and "radially" generally mean
perpendicular to the central axis. The use of "top," "bottom," "above,"
"below," and variations of these terms is made for convenience, but does not
require any particular orientation of the components.
[0008] Reference throughout this specification to "one embodiment," "an
embodiment," or similar language means that a particular feature, structure,
or
characteristic described in connection with the embodiment may be included in
at least one embodiment of the present disclosure. Thus, appearances of the
phrases "in one embodiment," "in an embodiment," and similar language
throughout this specification may, but do not necessarily, all refer to the
same
embodiment.
[0009] Although the present invention has been described with respect to
specific details, it is not intended that such details should be regarded as
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limitations on the scope of the invention, except to the extent that they are
included in the accompanying claims.
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