TELEMETRICALLY OPERABLE PACKERS
BACKGROUND
1. Field of the Invention
The present disclosure relates generally to systems, tools and associated methods
utilized in conjunction with hydrocarbon recovery wells. More particularly, embodiments of
the disclosure relate to apparatuses and methods for setting well annulus packers.
2. Background Art
In the hydrocarbon production industry, packers are used for testing, treating and
various other sealing and partitioning operations in a wellbore. A packer is often coupled to
an outer surface of a mandrel, e.g. , a string of production tubing or other work string, and run
into the wellbore in a radially contracted state. Once the packer arrives at its intended
destination in the wellbore, an elastomeric sealing element of the packer can be radially
expanded to establish a seal with a surrounding surface, e.g., casing pipe or a geologic
formation, thereby setting the packer in the annulus between the mandrel and the surrounding
surface.
Annular packers can be set by a variety of methods. Some of these methods include
exerting a mechanical force (a setting force) on the sealing element to longitudinally
compress the sealing element, and thereby cause the sealing element to laterally swell into the
annulus. The setting force can be exerted on the sealing element by mechanically applying a
down-hole force from a surface location, e.g., by manipulating a service tool or work string.
Alternatively, the sealing element can be selectively actuated by opening a valve or bursting a
rupture disk to thereby permit hydraulic energy to be transferred from fluids present in the
wellbore to the sealing element. Often these valves must be opened by mechanical
intervention, by dropping a ball or dart, etc. from the surface, and these rupture disks are
often activated by the application of pressure from the surface. Additional tubing runs and
extra equipment can make these methods costly and time consuming. Since packers are often
required to be set, unset, and reset multiple times, the use of telemetrically operable packers
can significantly reduce the amount of intervention required, thereby reducing the cost and
complexity of many wellbore operations.
BRIEF DESCRIPTION OF THE DRAWINGS
The disclosure is described in detail hereinafter on the basis of embodiments
represented in the accompanying figures, in which:
FIG. 1 is a partially cross-sectional schematic view of a well system including a
plurality of telemetrically operable packers having setting mechanisms in telemetric
communication with a surface location in accordance with example embodiments of the
present disclosure;
FIG. 2 is a cross-sectional schematic view of a packer having a hydraulic setting
mechanism operable in the well system of FIG. 1 in accordance with example embodiments
of the present disclosure;
FIG. 3A is a cross-sectional schematic view of a packer having a packer slip and an
electromechanical setting mechanism in accordance with example embodiments of the
present disclosure;
FIG. 3B is a cross-sectional schematic view of the electromechanical setting
mechanism of FIG. 3A including a setting piston driven by an electromechanical actuator;
FIGS. 4A and 4B are cross-sectional schematic views of another electromechanical
setting mechanism including a piston driven by a plurality of electromechanical actuators
through a hydraulic reservoir;
FIG. 5 is a flowchart illustrating a method of operating packers having the setting
mechanisms of FIGS. 2, 3A and 4A in accordance with example embodiments of the present
disclosure;
FIG. 6 is a cross-sectional schematic view of a packer having a setting mechanism
that employs first and second piezoelectric valves and an electromechanical actuator for
controlling the flow of hydraulic energy through the setting mechanism in accordance with
example embodiments of the present disclosure;
FIGS 7A and 7B are cross-sectional schematic views of the first piezoelectric valve of
FIG. 6 in closed and open configurations respectively; and
FIG. 8 is a flowchart illustrating a method of operating a packer of FIG. 6 in
accordance with example embodiments of the present disclosure.
DETAILED DESCRIPTION
In the interest of clarity, not all features of an actual implementation or method are
described in this specification. Also, the "exemplary" embodiments described herein refer to
examples of the present invention. In the development of any such actual embodiment,
numerous implementation-specific decisions may be made to achieve specific goals, which
may vary from one implementation to another. Such would nevertheless be a routine
undertaking for those of ordinary skill in the art having the benefit of this disclosure. Further
aspects and advantages of the various embodiments and related methods of the invention will
become apparent from consideration of the following description and drawings.
The foregoing disclosure may repeat reference numerals and/or letters in the various
examples. 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 "below," "lower," "above," "upper," "up-hole,"
"down-hole," "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 in the figures. 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.
Figure 1 illustrates a well system 10 in accordance with example embodiments of the
present disclosure. In well system 10, a wellbore 12 extends through a geologic formation
"G" along a longitudinal axis A plurality of zones 14 (designated as zones 14a and
14b) are defined in the wellbore 12 by a plurality of packers 16 longitudinally spaced along a
work string 18. In some example embodiments, the work string 18 can comprise a string of
tubular members interconnected with one another (e.g., a production or injection tubing
string). Although the portion of the wellbore 12 that intersects the zones 14 is depicted as
being substantially horizontal, it should be understood that this orientation of the wellbore 12
is not essential to the principles of this disclosure. The portion of the wellbore 12 which
intersects the zones 14 could be otherwise oriented (e.g., vertical, inclined, etc.).
The packers 16 each include a sealing element 22 and setting mechanism 24. The
sealing elements 22 fluidly isolate the zones 14a and 14b from one another in the wellbore 12
and seal off an annulus 26 formed between the work string 18 and a casing 28, which lines
the wellbore 12. However, if the portion of the wellbore 12 which intersects the zones 14
were uncased or open hole, then the packers 16 could seal between the work string 18 and the
geologic formation "G." An annular space 26a, 26b is defined radially around the work
string 18 and longitudinally between the sealing elements 22 for each respective zone 14a,
14b. With the packers 16 properly set in the annulus 26, various tests or treatments can be
performed in one of the annular spaces 26a without contaminating or affecting the other
annular space 26b.
The setting mechanism 24 of each packer 16 can operate to radially expand the
respective sealing element 22 to set the packer 16 in the annulus 26. In some embodiments,
the setting mechanisms 24 are provided at an up-hole location with respect to each respective
sealing element 22. Other relative positions for the setting mechanism 24 are also
contemplated such as down-hole of the respective sealing element, radially adjacent the
respective sealing element and/or combinations thereof.
The setting mechanisms 24 can each be telemetrically coupled to a surface location
"S" by a communication unit 30. The communication units 30 can be communicatively
coupled to a surface unit 32 by wireless systems such as acoustic and electromagnetic
telemetry systems. Such systems generally include hydrophones or other types of transducers
to selectively generate and receive waves "W," which are transmissible through the geologic
formation "G" and/or a column of fluid in the wellbore 12. Both the communication unit 30
and the surface unit 32 can send and receive instructions, data and other information via the
waves "W." In some embodiments, the communication units 30 can additionally or
alternatively be communicatively coupled to the surface unit 32 by control lines 36, which
extend through the wellbore 12 to the surface location "S." The control lines 36 can include
hydraulic conduits, electrical wires, fiber optic waveguides or other signal transmission
media as appreciated by those skilled in the art.
Referring to FIG. 2, example embodiments a telemetrically operable packer 100 can
include a hydraulically actuated setting mechanism 102 for radially expanding a sealing
element 22, e.g., within the well system 10 of FIG. 1. Setting mechanism 102 includes a
generally cylindrical mandrel 104 that defines a longitudinal axis "X2." The mandrel 104 can
be constructed of a generally rigid material such as steel, and can include fasteners "F" such
as threads or other fasteners (not shown) disposed at longitudinal ends thereof to enable the
mandrel 104 to be interconnected into a work string 18 (FIG. 1). The sealing element 22 is
disposed radially about the mandrel 104, and can be constructed of rubber, a synthetic rubber,
or another suitable deformable material. The sealing element 22 is disposed axially between
an anchor 106 and a setting shoe 108. In some embodiments, the anchor 106 is formed
integrally with the mandrel 104, or is otherwise axially fixed with respect to the mandrel 104.
The setting shoe 108 is axially movable along the mandrel 104 in the directions of arrows Ai
and A2 (toward and away from the anchor 106) to set and unset the sealing element 22. In
some embodiments, both the anchor 106 and the setting shoe 108 are axially movable with
respect to the sealing element 22 for setting and unsetting the sealing element 22.
A setting piston 112 is coupled to the setting shoe 108 by threads "T" or another
mechanism such that axial motion is transferrable between the setting shoe 108 and the
setting piston 112. The setting piston 112 includes a flange 114 extending into a fluid
chamber 116. The flange 114 defines setting and unsetting faces 114a and 114b thereon.
The setting piston 112 is responsive to operating pressures applied to the setting and unsetting
faces 114a and 114b for reciprocal longitudinal movement with respect to the mandrel 104.
For example, hydraulic pressure can be applied to the setting face 114a to move the setting
piston 112 and the setting shoe 108 in a down-hole direction (arrow Ai), and hydraulic
pressure can be applied to the unsetting face 114b to move the setting piston 112 and the
setting shoe 108 in an up-hole direction (arrow A2) . The fluid chamber 116 is axially divided
into two sub-chambers 116a, 116b by the flange 114, and the two sub-chambers 116a, 116b
are fluidly isolated from one another by a seal 118 carried by the flange 114. Each subchamber
116a, 116b is fluidly coupled to an actuator such as pump 120 by a respective fluid
passage 122a, 122b extending through a housing 124. The pump 120 is operable to
selectively withdraw hydraulic fluid "H" from either sub-chamber 116a or 116b, and
simultaneously provide hydraulic fluid to the other sub-chamber, 116a or 116b. The
hydraulic fluid "H" imparts a force to the setting and unsetting faces 114a, 114b of the flange
114 to thereby move the setting piston 112 in both down-hole (arrow Ai) and up-hole (arrow
A ) longitudinal directions. Since the flange 114 can drive the setting piston 112 in two
longitudinal directions, the setting piston 112 can be described as a "dual-action" piston.
The pump 120 can include, or be part of, small diameter pump systems such as downhole
ram-pump systems provided by WellDynamics, Inc., or down-hole hydraulic pump
systems provided by Red Spider Technology, Ltd. These pump systems can be referred to as
"micro-pumps" as the pump 120 can exhibit very small diameters, e.g., diameters about one
half inch or less.
The pump 120 is operatively and communicatively coupled to a controller 126, such
that the controller 126 can selectively instruct the pump 120 and receive feedback therefrom.
In some embodiments, the controller 126 can comprise a computer including a processor
126a and a computer readable medium 126b operably coupled thereto. The computer
readable medium 126b can include a nonvolatile or non-transitory memory with data and
instructions that are accessible to the processor 126a and executable thereby. In some
example embodiments, the computer readable medium 126b is operable to be pre
programmed with a plurality of predetermined sequences of instructions for operating the
pump 120, and/or other actuators to achieve various objectives. These instructions can also
include initiation instructions for each predetermined sequence of instructions. For example,
some of the predetermined sequences of instructions can initiated in response to receiving a
predetermined "START" signal (such as "SET" or "UNSET" signals) from the surface unit
32 (FIG. 1), some of the predetermined sequences of instructions can be initiated in response
to the passage of a predetermined amount of time from deployment, and some predetermined
sequences of instructions can be initiated only if the processor 126a determines that a
predetermined set of conditions have been met.
The controller 126 is communicatively coupled to communication unit 30, which as
described above, is communicatively coupled to the surface location "S" (FIG. 1). The
communication unit 30 can receive instructions from the surface location "S" and transmit
these instructions to the controller 126. For example, the communication unit 30 can receive
a unique "START" signal from an operator at the surface location, and transmit the
"START" signal to the controller 126. Responsive to receiving the "START" signal, the
controller 126 can execute one of the predetermined sequences of instructions for operating
the pump 120 stored on the computer readable medium 126b. The communication unit 30
can also transmit a confirmation signal to indicate that the controller 126 has determined that
the predetermined sequence of instructions has been completed, and/or an error signal in the
event the controller 126 determines that the setting mechanism 100 is not functioning within
a predetermined set of parameters.
A power source 128 is provided to supply energy for the operation of the pump 120,
controller 126, and/or communication unit 30. In some embodiments, power source 128
comprises a local power source such as a battery that is self-contained within the setting
mechanism 100 or a self-contained turbine operable to generate electricity responsive to the
flow of wellbore fluids therethrough. In some embodiments, power source 128 comprises a
connection with the surface location "S" (FIG. 1), e.g., an electric or hydraulic connection to
the surface location through control lines 36.
Referring to FIG. 3A, example embodiments of a packer 200 include an
electromechanical setting mechanism 202. Packer 200 includes a mandrel 204 defining a
longitudinal axis "X ." The setting mechanism 202, sealing element 22 and packer slips 206
are each disposed radially about the mandrel 204. The mandrel 204 can be constructed of a
steel pipe or other substantially rigid member, and can include threads or other fasteners (not
shown) at longitudinal ends thereof, which can facilitate interconnecting the packer 200 into a
work string 18 (FIG. 1). The setting mechanism 202 generally includes a control module
208, drive module 210 and a setting piston 212 disposed radially about the mandrel 204.
The drive module 210 can be longitudinally anchored to the mandrel 204 by
interconnecting ridges and grooves 214, and can be operable to bi-directionally move the
setting piston 212 along a portion of the mandrel 204 in the directions of arrows A and A4.
Since the drive module 210 is longitudinally anchored to the mandrel 204, an actuator (e.g.,
motor 222, see FIG. 3B described below) of the drive module 210 can be maintained in a
longitudinally stationary relation with the mandrel 204, and thus, a full force supplied by the
actuator can be applied to the setting piston 212 to move the setting piston 212 longitudinally
with respect to the mandrel 204. In some embodiments, the drive module 210 (and the
actuator thereof) can be longitudinally anchored to the mandrel 204 by fasteners, welding or
other recognized methods.
The drive module 210 can move the setting piston 212 in a first longitudinal direction
(arrow A ) along the mandrel 204 toward the sealing element 22. The setting piston 212
initially drives both the sealing element 22 and a cam wedge 216 in the first direction toward
the packer slips 206. The cam wedge 216 and the packer slips 206 engage one another along
inclined surfaces 218 such that the longitudinal motion of the cam wedge 216 in the first
longitudinal direction (arrow A ) drives the packer slips 206 radially outward until outer
gripping surfaces 220 dig into the metal of casing 28 (FIG. 1). Once the outer gripping
surfaces 220 of the packer slips 206 are engaged, the packer slips 206 impede further
longitudinal movement of the cam wedge 216. Thus, further longitudinal movement of the
setting piston 212 in the first direction longitudinally compresses the sealing element 22
between the setting piston 212 and the cam wedge 216. The sealing element 22 is thereby
expanded radially from the mandrel to seal against the casing 28 (FIG. 1). Thus, the sealing
element 22 can be set by movement of the setting piston 212 in the first longitudinal direction
(arrow A ) .
The sealing element 22 can be unset by employing the drive module 210 to move the
setting piston 212 in a second longitudinal direction (arrow A4), and thereby move the setting
piston 212 away from the sealing element 22. The sealing element 22 is then free to
longitudinally relax and radially withdraw from the casing 28.
Referring to FIG. 3B, the drive module 210 can include an actuator such as a motor
222, which can be a rotary stepper motor, servo motor or other type of electric motor. The
drive module can also include a gear box 224 and a transmission 226 that converts rotary
motion from the motor 222 and gear box 224 and to linear motion. The transmission 226 can
include a screw-drive, a rack and pinion mechanism or other rotary to linear mechanisms
recognized in the art. A drive shaft 228 is operably coupled to the transmission 226 to axially
move the setting piston 216 in the directions of arrows A and A4. In some example
embodiments, the drive module 210 can include solenoids (not shown), linear induction
motors (not shown), or other electrically operable linear actuators recognized in the art.
The control module 208 can include a power source 128, communication unit 30 and
a controller 126. As described above, the controller 126 can comprise a computer including a
processor 126a and a computer readable medium 126b operably coupled thereto. The
computer readable medium 126b can include instructions programmed thereon that are
accessible to the processor 126a and executable thereby to operate the motor 222. The
control module 208 generally enables an operator at the surface to selectively drive the
setting piston 212 and thereby set and unset the sealing element 22 (FIG. 3A).
Referring now to FIGS. 4A and 4B, example embodiments of a setting mechanism
302 can include a plurality of individual actuators 304 (designated as 304a and 304b)
disposed radially about a longitudinal axis "X4." Each of the individual actuators 304 can
comprise an individual electric motor 222 (designated as first and second electric motors
222a and 222b, respectively) that is longitudinally anchored to a mandrel 306. The first and
second electric motors 222a and 222b are operably coupled to a control module 208 as
described above. The setting mechanism 302 can also include a plurality of drive shafts 308
(designated as drive shafts 308a and 308b), an annular fluid reservoir 310 and a setting piston
312. As described in greater detail below, the individual actuators 304 are operable to move
the setting piston 312 longitudinally along the mandrel 306 (in the directions of arrows A
and A6) .
The drive shafts 308a and 308b are operably coupled to the first and second electric
motors 222a and 222b such that operation of the motors 222 moves the drive shafts 308a,
308b in longitudinal directions of arrows A and A . In some embodiments, the drive shafts
308a, 308b are operably coupled to the first and second electric motors 222a, 222b through a
gear box 224 (FIG. 3B) and transmission 226 (FIG. 3B) as described above. The first and
second electric motors 222a, 222b are operable to generate first and second longitudinal
forces, e.g., Pi and P2 respectively, which can be imparted to hydraulic fluid "H" through
drive shafts 308a, 308b. The hydraulic fluid "H" is disposed within annular fluid reservoir
310 defined around the mandrel 306.
The longitudinal forces Pi and P are parallel forces applied between the mandrel 306
and the hydraulic fluid "H," which the hydraulic fluid "H" combines and distributes to impart
a resultant longitudinal force P 3 to the setting piston 312. The hydraulic fluid "H" serves to
balance or compensate for differences in the magnitude of longitudinal forces Pi, P2. Thus,
the drive shafts 308a, 308b can be operated in a misaligned configuration where each drive
shaft 308a, 308b is disposed at a different longitudinal distance Ll L from the setting piston
312 without skewing the setting piston 312.
The fluid reservoir 310 includes a first section 310a in which the hydraulic fluid "H"
is in contact with the drive shafts 308a, 308b and a second section 310b in which the
hydraulic fluid "H" is in contact with the setting piston 312. As illustrated in FIG. 4B, the
first section 310a includes a plurality of radially-spaced sub-chambers 314a, 314b. 314c and
314d, corresponding to each drive shaft 308a, 308b. Although four radially-spaced subchambers
314a, 314b. 314c and 314d are illustrated in FIG. 4B, it should be appreciated that
more or fewer sub-chambers and corresponding drive shafts can be provided, A first crosssectional
area of the first section 310a {e.g., combined from each of the sub-chambers 314a,
314b. 314c and 314d) can be smaller than a second cross-sectional area of the second section
310b. Thus, a mechanical advantage can be realized from transmitting the forces Pi, P ,
through the hydraulic fluid to the setting piston 312. Those skilled in the art will recognize
that the pressure of the hydraulic fluid "H" will be equal at every point within the fluid
reservoir 310. Thus, the force P 3 imparted to the setting piston 312, which is distributed
across a larger cross-sectional area, can be greater than the forces Pi, P imparted from the
drive shafts 308a, 308b, which are distributed across a smaller cross-sectional area.
Referring to FIG. 5, an example operational procedure 400 that employs at least one
of the setting mechanisms 102, 202 and 302 can be initiated by preprogramming the
controller 126 at the surface location "S," e.g., by installing instructions and data onto the
computer readable medium 126b (step 402). The mandrel 104, 204, 316 can be
interconnected into a work string 18 (step 404), and the sealing element 22 and the setting
mechanism 102, 202, 302 can be run into the wellbore 12 (step 406) on the work string 18.
Once the sealing element 22 is in position, an operator can then send a "SET" telemetry
signal from the surface unit 32 to the communication unit 30 of the setting mechanism 102,
202, 302 (step 408). The communication unit 30 can transmit the "START" signal to the
processor 126a (step 410) to instruct the processor 126a to initiate an appropriate
predetermined sequence of instructions stored on computer readable medium 126b. The
processor 126a can execute the predetermined sequence of instructions to operate an actuator
(step 412), e.g., the pump 120, motor 222 or motors 222.
When the pump 120 (FIG. 2) of setting mechanism 102 is employed in step 412, the
pump 120 is operated to withdraw hydraulic fluid "H" from sub-chamber 116b and
simultaneously provide hydraulic fluid "H" to sub-chamber 116a, thereby urging the setting
piston 112 and setting shoe 108 toward the sealing element 22, e.g., in a compression
direction. Movement of the setting piston 112 and setting shoe 108 in the compression
direction causes the setting shoe 108 to compresses the sealing element 22 and thereby
radially expand the sealing element 22 from the mandrel 104. As illustrated in FIG. 2, the
compression direction is a down-hole direction (arrow Ai). In some example embodiments
(not shown), the setting piston 112 and/or the setting shoe 108 can be arranged with respect
to the sealing element 22 such that the compression direction can be an up-hole direction, a
radial direction or other directions to compresses the sealing element 22 and thereby radially
expand the sealing element 22 from the mandrel 104. As illustrated in FIG. 2, the sealing
element 22 can be longitudinally compressed between the setting shoe 108 and the anchor
106, thereby causing the sealing element 22 to expand radially from the mandrel 104.
When the motor 222 (FIG. 3B) or motors 222a, 222b (FIG. 4B) of setting
mechanisms 202 or 302 are employed in step 412, the motor or motors 222, 222a, 222b are
operated to drive the drive shafts 228 or drive shafts 308a, 308b in a compression or downhole
direction. Movement of the drive shafts 228, 308a and 308b in the compression or
down-hole direction urges the setting piston 212, 312 toward the sealing element 22 to
longitudinally compress the sealing element 22, and thereby cause the sealing element 22 to
radially expand into the annulus 26.
Once the processor 126a has executed the predetermined sequence of instructions, the
processor 126a can send a confirmation signal to the surface location "S" via the
communication unit 30 (step 414). In some embodiments, sensors or other feedback devices
(not shown) can be queried by the processor 126a (decision 416) to verify proper setting of
the sealing element 22, and when an error condition is identified, an error signal can be sent
to the surface location "S" (step 418).
When no error condition is identified, a wellbore test or other operation can be
performed in the wellbore 12 (step 420) as necessary with the sealing element 22 properly
set. When the wellbore test or other operation is complete, the sealing element 22 can be
unset by sending an "UNSET" telemetry signal from the surface unit 32 (step 422). The
communication unit 30 can receive the "UNSET" signal and transmit "UNSET" signal to the
controller 126 (step 424) to instruct the processor 126a to initiate another predetermined
sequence of instructions. The processor 126a can execute the predetermined sequence of
instructions (step 426) to operate the actuator to unset the sealing element 22.
For example the predetermined sequence of instructions can operate the pump 120 to
withdraw hydraulic fluid "H" from sub-chamber 116a and simultaneously provide hydraulic
fluid "H" to sub-chamber 116b, thereby urging the setting piston 112 and setting shoe 108
away from the sealing element 22, e.g., in an retracting direction. Movement of the setting
piston 112 and the setting shoe 108 in the retracting direction permits the sealing element 22
to be relaxed, thereby causing the sealing element 22 to withdraw radially toward the mandrel
104. The retracting direction can be an up-hole direction. Alternately or additionally, the
motor 222 (FIG. 3B) or motors 222a, 222b (FIG. 4B) can be operated to drive the drive shafts
228, 308a, 308b in the retracting or up-hole direction to permit the sealing element 22 to be
longitudinally relaxed.
Once the processor 126a has executed the predetermined sequence of instructions for
unsetting the sealing element 22, the processor 126a can again instruct the communication
unit 30 to send a confirmation signal to the surface location "S" (step 428). The work string
18 can then be moved to another location in the wellbore 12, and sealing element 22 can be
reset (return to step 408).
Referring to FIG. 6, some example embodiments of a telemetrically operable packer
500 can include a setting mechanism 502 with first and second valves 504 and 506 therein.
The first and second valves 504, 506 regulate fluid flow through the setting mechanism 502
to actuate a setting piston 508 and a setting shoe 510 defined at an end of the setting piston
508. The packer 500 includes a mandrel 512 defining a longitudinal axis X and an exterior
surface 514. Threads or other fasteners (not shown) can be provided on the mandrel 512 to
facilitate interconnection of packer 500 into a work string 18 (FIG. 1). Sealing element 22 is
disposed over a portion of the exterior surface 514 of the mandrel 512, and is responsive to
compression, e.g., longitudinal compression, by the setting piston 508 to expand radially
from the mandrel 512.
The setting mechanism 502 includes a housing 516 coupled to the mandrel 512. The
first valve 504 is disposed within an entry port 518 extending through the housing 516
between an exterior environment 520 of the setting mechanism 502 and a piston chamber 522
defined within the setting mechanism 502. The exterior environment 520 can include, e.g.,
the annulus 26 (FIG. 1) when the packer 500 is run into the wellbore 12. In some
embodiments (not shown) the exterior environment 520 can include an internal tubing
passageway (not shown) defined radially within the mandrel 512. The piston chamber 522
encloses a setting pressure face 508a of the setting piston 508 such that a fluid within the
piston chamber 522 can impart a force to the setting pressure face 508a to thereby move the
setting piston 508 in a compression or down-hole direction (arrow A7) . The second valve 506
is disposed within a pass-through port 524 defined within the setting piston 508, and controls
fluid flow between the piston chamber 522 and a dump chamber 526 defined within the
housing 516. The dump chamber 526 is remotely disposed with respect to the setting and
unsetting pressure faces 508a, 508b of the setting piston. The first and second valves 504,
506 are both coupled to controller 126, communication unit 30 and power source 128, which
together permit remote and/or telemetric operation of the first and second valves 504 and
506.
As described in greater detail below, first and second valves 504, 506 can be
selectively opened and closed to drive the setting piston 508 in longitudinal directions, e.g.,
the directions of arrows A7 and A . As the setting piston 508 is driven in the compression or
a down-hole direction (in the direction of arrow A7) a volume of the piston chamber 522 can
increase, while simultaneously, a volume of a reset chamber 530 can decrease. The reset
chamber 530 encloses a reset pressure face 508b of the setting piston 508. In some example
embodiments, the reset chamber 530 can be sealed or fluidly isolated within the housing 516,
and can be charged or filled with a compressible fluid. For example, the reset chamber 530
can be filled with a generally inert gaseous fluid such as argon or nitrogen "N," which
facilitates prevention of unintended chemical reactions. The nitrogen "N" can impart a force
to the unsetting pressure face 508b to move the setting piston 508 in retracting or an up-hole
direction (in the direction of arrow A ), and thereby decrease the volume of the piston
chamber 522.
In some example embodiments, a reset piston 534 can optionally be provided within
the piston chamber 522. The reset piston 534 can be driven in the longitudinal directions of
arrows A and A10 to thereby respectively decrease and increase the volume of the piston
chamber 522. The reset piston 534 can be driven by a reset actuator 536 such as a motor,
solenoid or hydraulic actuator, and in some example embodiments, can be controlled by
controller 126 or another separate controller (not shown) operatively coupled to the
communication unit 30. A check valve 540 can be provided in a passageway 542 extending
between the piston chamber 522 and the exterior environment 520. The check valve 540 can
prohibit fluid flow through the passageway 542 in a direction from the exterior environment
520 into the piston chamber 522, and permit fluid flow in an opposite direction, e.g., from the
piston chamber 522 into the exterior environment 520. Thus, fluid can be expelled from the
piston chamber 522, e.g., by activation of the reset piston 534 to decrease the volume of the
piston chamber 522. In some embodiments, a biasing member (not shown) such as a spring
or other mechanism can provided to maintain the check valve 540 in a closed position when a
pressure in the piston chamber 522 is below a predetermined threshold pressure.
In some example embodiments, telemetrically operable valves (not shown) can
alternately or additionally be disposed within the passageway 542, for selectively permitting
fluid to be expelled from the piston chamber 522 into the exterior environment 520. In some
example embodiments, fluid can be expelled from the piton chamber 522 into the dump
chamber 526 by activation of the piston 534.
The piston chamber 522 defines a maximum volume when the reset piston 534 is
moved as far as possible in retracting or the up-hole direction of arrow A10 and the setting
piston 508 is moved as far as possible in the in the compression or down-hole direction of
arrow A7. In some embodiments, the dump chamber 526 exhibits a volume that is at least
twice the maximum volume of the piston chamber 522, and can exhibit a volume that is
multiple times the maximum volume of the piston chamber 522. The relatively large volume
exhibited by the dump chamber 526 facilitates repeatedly evacuating the piston chamber 522
as described in greater detail below.
Referring now to FIGS. 7A and 7B, the first valve 504 can comprise a piezoelectric
valve having a piezoelectric element 546. The piezoelectric element 546 is operable to
generate an internal mechanical strain in response to an applied electrical field, e.g. , a drive
signal supplied thereto by the controller 126. When no drive signal is applied to the
piezoelectric element 546 from the controller 126, the first valve 504 is in a normally-closed
configuration (FIG. 7A) wherein the piezoelectric element 546 forms a seal with a valve seat
548. Fluid flow through the entry port 518 is thereby obstructed when the first valve is in the
closed configuration. When a drive signal is applied to the piezoelectric element 546 from
the controller 126, the first valve 504 moves to an open configuration (FIG. 6B) wherein the
piezoelectric element 546 is in a strained or deformed state that separates the piezoelectric
element 546 from the valve seat 548. Fluid flow through the entry port 518 is permitted
when the first valve 504 is in the open configuration. In some embodiments, the second
valve 506 also comprises a piezoelectric valve, and in some embodiments the first and/or
second valves 504, 506 can comprise other types of telemetrically activated valves.
Referring to FIG. 8, and with continued reference to FIGS. 1 and 6 through 7B,
example embodiments of an operational procedure 600 for employing the packer 500 are
illustrated. Initially, reset chamber 526 can be charged with a supply of a gaseous fluid such
as argon or nitrogen "N" at the surface location "S" (step 602). A sufficient quantity of
nitrogen "N" can be supplied to establish a charging pressure within the reset chamber 526
that is that is greater than an ambient surface pressure, e.g., greater than about 1 atmosphere.
The controller 126 can then be pre-programmed at the surface location "S" (step 604) by
installing instructions for operating the first and second valves 504, 506 and the reset actuator
536 onto the computer readable medium 126b. The first and second valves 504, 506 can be
moved to open configurations (step 606) such that the ambient surface pressure, e.g. , about 1
atmosphere, is established within the piston chamber 522 and the dump chamber 526. Since
the reset chamber 530 is charged to the charging pressure above the ambient surface pressure,
the setting piston 508 is urged away from the sealing element 22 (in the direction of arrow
A ) by the pressure of the nitrogen "N" in the reset chamber 530. The first and second valves
504, 506 can both be moved to the closed positions (step 608), thereby sealing the ambient
surface pressure within the piston chamber 522 and the dump chamber 526.
The packer 500 can be interconnected into the work string 18 (step 610) by threading
or coupling the mandrel 512 therein, and then the packer 500 can then be run into the
wellbore 12 on the work string 18 (step 612). Once the packer 500 is in position, the exterior
environment 520 can be defined by the annulus 26 (or an internal tubing passageway (not
shown) defined radially within the mandrel 512). A down-hole annulus pressure can be
significantly greater than the surface ambient pressure and the charging pressure. An
operator can then send a "SET" telemetry signal from the surface unit 32 to the
communication unit 30 (step 614), and the "SET" signal can be transmitted from the
communication unit 30 to controller 126 (step 616).
The processor 126a of the controller 126 can execute a predetermined sequence of
instructions stored on computer readable medium 126b to send a drive signal to the first valve
504 (step 618). The drive signal can move the first valve 504 to the open configuration (FIG.
7B) permitting fluid from the external environment 520 to increase the pressure in the piston
chamber 522 from the surface ambient pressure to the down-hole annulus pressure. This
increase in pressure drives the setting piston 508 in a compression or down-hole direction (in
the direction of arrow A7) . The compressive or down-hole movement of the setting piston
508 longitudinally compresses the sealing element 22 to radially expand the sealing element
22. The compressive or down-hole movement of the setting piston 508 also reduces the
volume of the reset chamber 530, thereby pressurizing the nitrogen "N" or other compressible
fluid therein.
The drive signal can be halted (step 620) to return the first valve 504 to the closed
configuration (FIG. 7A). With the first valve 504 in the closed configuration, the piston
chamber 522 is maintained at the down-hole annulus pressure, and the sealing element 22 is
thereby maintained in the set configuration. A wellbore test or other wellbore operations can
be performed (step 622) while the sealing element 22 is maintained in the set configuration.
When the wellbore test or other operation is complete, an operator can cause the
sealing element 22 can be unset by transmitting an "UNSET" or "DUMP" telemetry signal to
the communication unit 30 from the surface unit 32 (step 624). The communication unit 30
can receive the "DUMP" signal and transmit "DUMP" signal to the processor 126a of the
controller 126 (step 626). In response to receiving the "DUMP" signal, the processor 126a
can initiate another predetermined sequence of instructions to send a drive signal to the
second valve 506 (step 628), to thereby move the second valve to an open configuration.
Opening the second valve 506 equalizes the pressure in the piston chamber 522 and
the dump chamber 526. Since the dump chamber 526 is larger than the piston chamber 522,
the pressure within the piston chamber 522 is reduced. The pressure in the reset chamber 530
can then drive the setting piston 508 in the retracting or up-hole direction of arrow A , and
the sealing element 22 is permitted longitudinally relax, and radially withdraw toward the
mandrel 512.
In some example embodiments, the predetermined sequence of instructions executed
by the processor 126a in response to receiving the "DUMP" signal can include instructions to
send a drive signal to the reset actuator 536 (step 630) to drive the reset piston 534 into the
piston chamber, e.g., in the direction of arrow A9. The movement of the reset piston 534 into
the piston chamber 522 can drive at least a portion of the remaining fluid from the piston
chamber 522 into the exterior environment 520 (through the check valve 540) or into the
dump chamber 526 (through the second valve 506). The reset piston evacuates the piston
chamber 522, thereby reducing the pressure in the piston chamber 522.
The drive signal supplied to the second valve 506 can then be halted (step 632) to
close the second valve 506. The packer 500 can be moved to an alternate location in the
wellbore 12 (step 634), and the procedure 600 can return to step 614 to set the sealing
element 22 in the alternate location. Alternately, the packer 500 can be withdrawn from the
wellbore 12, if the well operations are complete.
In one aspect, the present disclosure is directed to a down-hole well control tool
activated in response to a telemetry signal. The down-hole well control tool can include a
mandrel that defines a longitudinal axis and is operable to interconnect the down-hole well
control tool within a work string. A setting piston is longitudinally movable over a portion of
the mandrel, and an actuator is longitudinally anchored to the mandrel and operable to
generate a first longitudinal force between the mandrel and the setting piston to move the
setting piston longitudinally with respect to the mandrel. A communication unit is coupled to
the mandrel for receiving a telemetry signal, a controller is coupled to the communication
unit and actuator to control the actuator in response to the telemetry signal; and a power
source is coupled to the mandrel for energizing at least one of the actuator, the
communication unit and the controller. In some exemplary embodiments, at least one packer
slip is operatively coupled to the setting piston such that the longitudinal motion setting
piston drives the at least one packer slip radially. In some exemplary embodiments, the at
least one packer slip includes outer gripping surfaces thereon that are operable to dig into a
metal of casing in response to radially driving the at least one packer slip. In some exemplary
embodiments, a sealing element is operably coupled to the setting piston and the at least one
packers slip such that longitudinal motion of the setting piston drives the at least one packer
slip radially until the packer slip engages a casing or other surface, and such that further
longitudinal movement of the setting piston compresses the sealing element to radially
expand the sealing element.
In another aspect, the present disclosure is directed to a down-hole packer. The
down-hole packer includes a mandrel that defines a longitudinal axis and an exterior surface.
A sealing element is disposed over a portion of the exterior surface of the mandrel, and the
sealing element is responsive to compression to expand radially from the mandrel. A setting
piston is longitudinally movable over a portion of the mandrel and is operably coupled to the
sealing element to compress the sealing element. At least one actuator is coupled to the
mandrel for longitudinally moving the setting piston relative thereto. A communication unit
is provided for receiving a telemetry signal, and a controller is coupled to the communication
unit and is responsive to the telemetry signal for controlling operation of the at least one
actuator. A power source is provided for energizing at least one of the controller, the
communication unit and the at least one actuator. In some exemplary embodiments, the at
least one actuator can include a valve operable to expose a setting pressure face of the setting
piston to a fluid pressure on an exterior environment of the down hole packer. In some
exemplary embodiments, the valve can include a piezoelectric element that is operable to
generate an internal mechanical strain in response to an applied electrical field, to thereby
move the valve between open and closed configurations. In some aspects, the present
disclosure is directed to method of employing the down-hole packer, wherein the method
includes deploying the down-hole packer into a wellbore such that the exterior environment
is an annulus defined between the down-hole and the wellbore.
In another aspect, the present disclosure is directed to a down-hole packer that
includes a mandrel defining a longitudinal axis and an exterior surface. A sealing element is
disposed over a portion of the exterior surface of the mandrel, and the sealing element is
responsive to compression to expand radially from the mandrel. A setting piston is
longitudinally movable over a portion of the mandrel and is operably coupled to the sealing
element to compress the sealing element. At least one actuator is coupled to the mandrel for
longitudinally moving the setting piston, and a communication unit is provided for receiving
a telemetry signal. The down-hole packer also includes a controller coupled to the
communication unit and responsive to the telemetry signal for controlling operation of the at
least one actuator. A power source is provided for energizing at least one of the controller,
the communication unit and the at least one actuator.
In some exemplary embodiments, the at least one actuator is longitudinally anchored
to the mandrel. The at least one actuator may include a pump for providing hydraulic fluid to
the setting piston to thereby move the setting piston longitudinally. In some exemplary
embodiments, the setting piston includes a fiange extending into a fluid chamber that is
axially divided into at least two sections by the flange, and wherein each of the at least two
sections of the fluid chamber is fluidly coupled to the pump such that hydraulic fluid can be
provided to one of the at least two sections and withdrawn from the other of the at least two
sections by the pump to move the setting piston in each of two longitudinal directions.
In one or more exemplary embodiments, the at least one actuator includes an electric
motor operably coupled to the setting piston for imparting longitudinal motion thereto. In
some exemplary embodiments, the at least one actuator includes a plurality of actuators
operable to provide parallel longitudinal forces to the setting piston. The plurality of
actuators may be operably coupled to the setting piston by a hydraulic fluid disposed within a
fluid chamber extending longitudinally between the plurality of actuators and setting piston.
The fluid chamber may exhibit a first cross-sectional area across which the parallel forces are
applied to the hydraulic fluid and a second cross-sectional area across which the hydraulic
fluid applies a combined resultant force to the setting piston, and the second cross-sectional
area may be relatively larger than the first cross-sectional area.
In another aspect, the present disclosure is directed to a down-hole well control tool
activated in response to a telemetry signal. The down-hole well control tool includes a
mandrel defining a longitudinal axis, and the mandrel has fasteners thereon for
interconnecting the mandrel within a work string. A setting piston is longitudinally movable
over a portion of the mandrel. A first electric motor is longitudinally anchored to the mandrel
and is operable to generate a first longitudinal force between the mandrel and the setting
piston to move the setting piston longitudinally with respect to the mandrel. A
communication unit is coupled to the mandrel for receiving a telemetry signal. A controller
is coupled to the communication unit and the first electric motor. The controller is operable
to control the first electric motor in response to the telemetry signal. A local power source is
coupled to the mandrel for energizing at least one of the electric motor, the communication
unit and the controller.
In one or more exemplary embodiments, the down-hole well control tool further
includes a sealing element coupled to the mandrel, and the sealing element is responsive to
compression by the setting piston to expand radially with respect to the mandrel. The downhole
well control tool may further include a fluid chamber extending longitudinally between
the first electric motor and the setting piston such that a hydraulic fluid disposed within the
fluid chamber is operable to impart a resultant longitudinal force on the setting piston in
response to application of the first longitudinal force thereto by the first electric motor. In
some exemplary embodiments, the down-hole well control tool further includes a second
electric motor longitudinally anchored to the mandrel that is operable to generate a second
longitudinal force between the mandrel and the setting piston through the hydraulic fluid. In
one or more exemplary embodiments, the controller is operably coupled to the second electric
motor, and the controller is operable to control both the first and second electric motors in
response to the telemetry signal.
In another aspect, the present disclosure is directed to a method of setting a packer in
a wellbore. The method includes (a) interconnecting a mandrel into a work string wherein
the mandrel has coupled thereto, a communication unit, a controller, an actuator, a setting
piston and a sealing element, (b) running the work string into a wellbore to dispose the
mandrel at a desired location within the wellbore, (c) sending a SET telemetry signal from a
surface location to the communication unit coupled to the mandrel, and (d) executing, with
the controller and in response to the SET telemetry signal, a predetermined sequence of
instructions to cause the actuator to generate a force between the mandrel and the setting
piston to thereby longitudinally move the setting piston to compress the sealing element.
In some exemplary embodiments, the method further includes energizing, with a
power source coupled to the mandrel, at least one of the actuator, the communication unit and
the controller. The method may further include sending, with the communication unit, a
confirmation signal to the surface location responsive to completing the predetermined
sequence of instructions. In one or more exemplary embodiments, the method further
includes sending, with the communication unit, an error signal to the surface location
responsive to detecting an error condition.
In one or more exemplary embodiments, controlling the actuator includes operating a
plurality of electric motors to impart parallel longitudinal forces to the setting piston through
a hydraulic fluid extending longitudinally between plurality of electric motors and the setting
piston. In some exemplary embodiments, the method further includes sending an UNSET
telemetry signal from the surface location to the communication unit, and executing, in
response to the UNSET telemetry signal, a predetermined sequence of instructions to cause
the actuator to relieve the force generated between the mandrel and the setting piston to
thereby longitudinally move the setting piston to longitudinally relax the sealing element. In
some exemplary embodiments, the method further includes moving the mandrel to an
additional location in the wellbore and repeating steps (c) and (d) to reset the sealing element
at the additional location.
Moreover, any of the methods described herein may be embodied within a system
including electronic processing circuitry to implement any of the methods, or a in a
computer-program product including instructions which, when executed by at least one
processor, causes the processor to perform any of the methods described herein.
The Abstract of the disclosure is solely for providing the United States Patent and
Trademark Office and the public at large with a way by which to determine quickly from a
cursory reading the nature and gist of technical disclosure, and it represents solely one or
more embodiments.
While various embodiments have been illustrated in detail, the disclosure is not
limited to the embodiments shown. Modifications and adaptations of the above embodiments
may occur to those skilled in the art. Such modifications and adaptations are in the spirit and
scope of the disclosure.

CLAIMS
WHAT IS CLAIMED IS:
1. A down-hole packer, comprising:
a mandrel defining a longitudinal axis and an exterior surface;
a sealing element disposed over a portion of the exterior surface of the mandrel, the
sealing element responsive to compression to expand radially from the mandrel;
a setting piston longitudinally movable over a portion of the mandrel and operably
coupled to the sealing element to compress the sealing element;
at least one actuator coupled to the mandrel for longitudinally moving the setting
piston;
a communication unit for receiving a telemetry signal;
a controller coupled to the communication unit and responsive to the telemetry signal
for controlling operation of the at least one actuator; and
a power source for energizing at least one of the controller, the communication unit
and the at least one actuator.
2. The down-hole packer of claim 1, wherein the at least one actuator is longitudinally
anchored to the mandrel.
3. The down-hole packer of claim 1, wherein the at least one actuator comprises a pump
for providing hydraulic fluid to the setting piston to thereby move the setting piston
longitudinally.
4. The down-hole packer of claim 3, wherein the setting piston comprises a flange
extending into a fluid chamber that is axially divided into at least two sections by the flange,
and wherein each of the at least two sections of the fluid chamber is fluidly coupled to the
pump such that hydraulic fluid can be provided to one of the at least two sections and
withdrawn from the other of the at least two sections by the pump to move the setting piston
in each of two longitudinal directions.
5. The down-hole packer of claim 1, wherein the at least one actuator comprises an
electric motor operably coupled to the setting piston for imparting longitudinal motion
thereto.
6. The down-hole packer of claim 1, wherein the at least one actuator comprises a
plurality of actuators operable to provide parallel longitudinal forces to the setting piston.
7. The down-hole packer of claim 6, wherein the plurality of actuators is operably
coupled to the setting piston by a hydraulic fluid disposed within a fluid chamber extending
longitudinally between the plurality of actuators and setting piston.
8. The down-hole packer of claim 7, wherein the fluid chamber exhibits a first crosssectional
area across which the parallel forces are applied to the hydraulic fluid and a second
cross-sectional area across which the hydraulic fluid applies a combined resultant force to the
setting piston, and wherein the second cross-sectional area is relatively larger than the first
cross-sectional area.
9. A down-hole well control tool activated in response to a telemetry signal, the downhole
well control tool comprising:
a mandrel defining a longitudinal axis, the mandrel having fasteners thereon for
interconnecting the mandrel within a work string;
a setting piston longitudinally movable over a portion of the mandrel;
a first electric motor longitudinally anchored to the mandrel and operable to generate
a first longitudinal force between the mandrel and the setting piston to move the setting
piston longitudinally with respect to the mandrel;
a communication unit coupled to the mandrel for receiving a telemetry signal;
a controller coupled to the communication unit and the first electric motor, the
controller operable to control the first electric motor in response to the telemetry signal; and
a local power source coupled to the mandrel for energizing at least one of the electric
motor, the communication unit and the controller.
10. The down-hole well control tool of claim 9, further comprising a sealing element
coupled to the mandrel, the sealing element responsive to compression by the setting piston
to expand radially with respect to the mandrel.
11. The down-hole well control tool of claim 9, further comprising a fluid chamber
extending longitudinally between the first electric motor and the setting piston such that a
hydraulic fluid disposed within the fluid chamber is operable to impart a resultant
longitudinal force on the setting piston in response to application of the first longitudinal
force thereto by the first electric motor.
12. The down-hole well control tool of claim 9, further comprising a second electric
motor longitudinally anchored to the mandrel and operable to generate a second longitudinal
force between the mandrel and the setting piston through the hydraulic fluid.
13. The down-hole well control tool of claim 12, wherein the controller is operably
coupled to the second electric motor, and wherein the controller is operable to control both
the first and second electric motors in response to the telemetry signal.
14. A method of setting a packer in a wellbore, the method comprising:
(a) interconnecting a mandrel into a work string wherein the mandrel has coupled
thereto, a communication unit, a controller, an actuator, a setting piston and a sealing
element;
(b) running the work string into a wellbore to dispose the mandrel at a desired
location within the wellbore;
(c) sending a SET telemetry signal from a surface location to the communication unit
coupled to the mandrel; and
(d) executing, with the controller and in response to the SET telemetry signal, a
predetermined sequence of instructions to cause the actuator to generate a force between the
mandrel and the setting piston to thereby longitudinally move the setting piston to compress
the sealing element.
15. The method of claim 14, further comprising energizing, with a power source coupled
to the mandrel, at least one of the actuator, the communication unit and the controller.
16. The method of claim 14, further comprising sending, with the communication unit, a
confirmation signal to the surface location responsive to completing the predetermined
sequence of instructions.
17. The method of claim 14, further comprising sending, with the communication unit, an
error signal to the surface location responsive to detecting an error condition.
18. The method of claim 14, wherein controlling the actuator comprises operating a
plurality of electric motors to impart parallel longitudinal forces to the setting piston through
a hydraulic fluid extending longitudinally between plurality of electric motors and the setting
piston.
19. The method of claim 14, further comprising sending an UNSET telemetry signal from
the surface location to the communication unit, and executing, in response to the UNSET
telemetry signal, a predetermined sequence of instructions to cause the actuator to relieve the
force generated between the mandrel and the setting piston to thereby longitudinally move
the setting piston to longitudinally relax the sealing element.
20. The method of claim 19, further comprising moving the mandrel to an additional
location in the wellbore and repeating steps (c) and (d) to reset the sealing element at the
additional location.