Note: Descriptions are shown in the official language in which they were submitted.
DOVVNHOLE SOLID STATE PUMPS
[0001] (This paragraph is intentionally left blank.)
BACKGROUND
[0002] In the oil and gas industry, wellbores are drilled for the
purpose of producing
hydrocarbons from subterranean formations. Some wellbores produce liquid
hydrocarbons,
while others primarily produce gaseous hydrocarbons. Over time, gas production
wells can fill
io with wellbore liquids, such as water, condensate, and/or liquid
hydrocarbons. These wellbore
liquids create an impediment to gas flow and, in more severe cases, can
entirely stop gas
production.
[0003] One way to deal with accumulating wellbore liquids in gas wells
is to install an
artificial lift system to remove the wellbore liquids. Artificial lift systems
take advantage of a
is forced pressure differential between the casing that lines the wellbore
and production tubing
extended into the casing to extract the liquids. The pressure differential is
created by sealing
the well and subsequently actuating a surface valve to systematically remove
liquids from the
well.
[0004] Plunger lift and pumping systems are examples of common
artificial lift systems
20 used to remove wellbore liquids from gas wells. While effective under
certain circumstances,
these systems may not be capable of efficiently removing wellbore liquids from
long and/or
deep gas wells, from wells that are deviated, or from wells in which the
gaseous hydrocarbons
do not generate at least a threshold pressure. Moreover, pumping systems
suffer from
reliability issues and/or considerable installation/deployment costs since a
workover rig is
25 typically required for intervention.
[0005] Plunger lift systems are dependent on reservoir pressure and can
only remove a
limited amount of liquid per day. Pumping systems are typically employed when
water
volumes are high or reservoir pressure is too low for a plunger application.
Common pump
types used include sucker rod pumps, electric submersible pumps (ESPs),
progressive cavity
30 pumps (PCPs), and hydraulic pumps. Conventional sucker rod pumps and
PCPs are positive
displacement pumps that can produce high head at various volumetric
throughputs, and do not
require a multitude of stages/sections to achieve a desired head. Rod pumps
are typically
powered by reciprocating rods, and the theoretical production volume is
limited by the
maximum number of rod strokes per minute that can be achieved without failing
the surface
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Date Recue/Date Received 2020-11-26
pumping unit or the downhole equipment. PCPs are typically powered with
rotating rods, and
the theoretical production volume is limited by the maximum rpm at which the
rods can be
rotated without failing the surface driver(s) or downhole equipment.
[0006] The mechanical connection from the pumps to surface can also
limit the application
depth of a rod pump or PCP system. Additionally, rods can wear and create
holes in the
production tubing in which they are installed, particularly in deviated or
horizontal wells.
Electric submersible PCPs have been developed, but are still depth limited by
the maximum
head that can be generated from the rotor-in-stator design.
[0007] Significant gas and oil reserves are at stake if liquids cannot
be economically
113 produced from gas wells, and the foregoing issues with plunger lift and
pumping systems can
make economical hydrocarbon production impracticable. What is needed is a
pumping system
that can be implemented in deep wells, that is less expensive to
deploy/replace, and is more
resistant to deviated/tortuous trajectories.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] The following figures are included to illustrate certain aspects of
the present
disclosure, and should not be viewed as exclusive embodiments. The subject
matter disclosed
is capable of considerable modifications, alterations, combinations, and
equivalents in form
and function, without departing from the scope of this disclosure.
[0009] FIG. 1 is a schematic diagram of an example well system that may
incorporate one
or more principles of the present disclosure.
[0010] FIG. 2 is an enlarged partial cross-sectional view of a portion
of the well system of
FIG. 1, including the positive-displacement solid state pump, according to one
or more
embodiments of the present disclosure.
[0011] FIG. 3 is an enlarged schematic view of another example
embodiment of the
positive-displacement solid state pump as included in the well system of FIG.
I.
[0012] FIG. 4 is a schematic diagram of an example positive-displacement
solid state
pump, according to embodiments of the present disclosure.
[0013] FIGS. 5A and 5B depict example operation of the solid state pump
of FIG. 4.
[0014] FIG. 6 is an enlarged schematic view of another example pump that
may be used in
the well system of FIG. 1.
[0015] FIG. 7 is an enlarged schematic view of another example pump that
may be used in
the well system of FIG. 1.
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DETAILED DESCRIPTION
100161 The present disclosure is generally related to systems and
methods for artificial lift
in a wellbore and, more specifically, to systems and methods that utilize a
downhole solid state
pump to remove wellbore liquids from the wellbore.
100171 The embodiments disclosed herein describe a pump that may be used in
a well
system to extract wellbore liquids from a wellbore. The pump may be conveyable
into
production tubing extended within the wellbore, and the pump may include a
solid state pump
and a secondary pump in fluid communication with the solid state pump via a
fluid circuit. The
solid state pump may include a solid state actuator actuatable to pressurize a
hydraulic fluid,
to and the secondary pump may be actuatable with the hydraulic fluid
received from the solid
state pump. A control system may be communicably coupled to the pump to
control its
operation. Actuating the secondary pump may draw in a wellbore liquid into the
secondary
pump, pressurize the wellbore liquid within the secondary pump, and discharge
a pressurized
wellbore liquid into the production tubing for production to a surface
location.
[0018] FIG, 1 is a schematic diagram of an example well system 100 that may
incorporate
one or more principles of the present disclosure. As illustrated, the well
system 100 includes
a wellhead 102 arranged at a surface location 104 and a wellbore 106 that
extends from the
wellhead 102 and through one or more subterranean formations 108. In some
embodiments,
the wellhead 102 may be replaced with a surface rig (e.g., a derrick or the
like), a service truck,
or other types of surface intervention systems. The wellbore 106 may be lined
with one or
more strings of casing 110, and a production tubing 112 may be arranged or
otherwise extended
within the casing 110. In some applications, the casing 110 and the production
tubing 112 may
both extend from and otherwise be "hung off' the wellhead 102.
[0019] As used herein, the term "production tubing" can refer to any
pipe or pipe string
known to those skilled in the art, such as casing, liner, drill string,
injection tubing, coiled
tubing, a pup joint, a buried pipeline, underwater piping, or aboveground
piping.
[0020] In some applications, as illustrated, the wellbore 106 may
deviate from vertical at
some point and terminate at a toe 114 in a slanted or horizontal portion of
the wellbore 106.
Those skilled in the art will readily appreciate that the principles of the
present disclosure are
applicable to wells having a variety of wellbore directional configurations
including vertical
wellbores, deviated wellbores, horizontal wellbores, slanted wellbores,
multilateral wells,
combinations thereof, and the like.
[0021] As illustrated, the well system 100 may include a pump 116
conveyable into the
production tubing 112 and operable as an artificial lift system to remove
wellbore liquids from
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the wellbore 106. In some embodiments, the pump 116 may comprise a positive-
displacement
solid state pump. Accordingly, the pump 116 may be referred to herein as "the
solid state pump
116." In some embodiments, the well system 100 may include a lubricator 118
(shown in
dashed lines) arranged at the surface location 104 in conjunction with the
wellhead 102. The
lubricator 118 may be used to receive and inject the solid state pump 116 into
the wellbore 106
and, more particularly, within the production tubing 112. The lubricator 118
may also be used
to remove the solid state pump 116 from the wellbore 106 as needed.
[0022] As compared to traditional artificial lift systems, the solid
state pump 116 may be
small enough to be introduced into the wellbore 106 via the lubricator 118.
This may prove
advantageous in allowing the solid state pump 116 to be located within the
wellbore 106
without depressurizing or killing the well system 100, and/or while containing
wellbore fluids
within the wellbore 106. Moreover, this may increase efficiency of operations
by decreasing
the time required to introduce or remove the solid state pump 116 into/from
the wellbore 106.
The solid state pump 116 may also be short enough to be conveyed past
deviations in most
wellbores. Such deviated regions might obstruct or retain longer or larger-
diameter traditional
pumping systems, but the presently disclosed solid state pump 116 may be
operable in well
systems that are otherwise inaccessible to more traditional artificial lift
systems.
[0023] The solid state pump 116 may be conveyed downhole on a conveyance
120, which
may comprise, but is not limited to, a wire, a cable, wireline, coiled tubing,
drill pipe, slickline,
or any combination thereof. In at least one embodiment, the conveyance 120 may
include a
seven cable logging cable that provides electrical communication with the
surface location 104
to provide telecommunication and electrical power downhole to operate the
solid state pump
116. In such embodiments, the solid state pump 116 may be powered by a surface
power
source 122 that may comprise, but is not limited to, a generator (e.g., an AC
generator, a DC
generator, etc.), a genset, a turbine, solar-power, wind-power, one or more
batteries, one or
more fuel cells, or any combination thereof In other embodiments, however, the
solid state
pump 116 may be powered downhole (locally) by an onboard power source 124
included in
the solid state pump 116. In such embodiments, the onboard power source 124
may comprise,
but is not limited to, a battery pack, one or more fuel cells, a downhole
power generator, or any
combination thereof. When batteries are used in the surface or onboard power
sources 122,
124, such batteries may be rechargeable.
[0024] In some embodiments, the solid state pump 116 may be conveyed
downhole with
the production tubing 112. In such embodiments, the solid state pump 116 may
be installed
within and otherwise coupled to the production tubing 112 at the surface
location 104 and
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extended into the wellbore 106 concurrently with the production tubing 112.
Moreover, in
such embodiments the solid state pump 116 may be referred to as a "tubing
pump."
100251 In some embodiments, the well system 100 may further include a
sealing assembly
126 configured to secure or seat the solid state pump 116 within the
production tubing 112 at
a predetermined location (e.g., at or near the end of the production tubing
112). In some
embodiments, the sealing assembly 126 may comprise a profile or radial
shoulder defined on
the inner radial surface of the production tubing 112 and configured to
receive a corresponding
profile or outer radial shoulder provided by the solid state pump 116. In
other embodiments,
the sealing assembly 126 may comprise an expandable packer element that
provides a sealed
interface between the production tubing 112 and the solid state pump 116. In
at least one
embodiment, the radial sealing assembly 126 may help isolate and otherwise
separate the intake
and discharge points of the solid state pump 116.
[00261 In example operation, the solid state pump 116 may be deployed
downhole and at
least partially immersed in wellbore liquids 127 present within the wellbore
106. The wellbore
.. liquid 127 may include, but is not limited to, water, condensate, liquid
hydrocarbons, or any
combination thereof. Unless they are removed from the wellbore 106, the
wellbore liquid 127
can obstruct gas production to the surface location 104. Accordingly, the
solid state pump 116
may be configured to draw in and pressurize the wellbore liquid 127, and
subsequently
discharge a pressurized wellbore liquid 128 into the production tubing 112 for
production to
the surface location 104. Wellbore gas 130 may simultaneously be produced to
the surface
location 104 via an annulus 132 defined between the production tubing 112 and
the inner wall
of the casing 106.
[0027] In some embodiments, the well system 100 may include a control
system 134
configured to control operation of all or a portion of the well system 100,
such as the solid state
pump 116. In some embodiments, the control system 134 may be located at or
adjacent the
wellhead 102. In such embodiments, the control system 134 may include a
display or terminal
viewable by an operator to evaluate the status of the well system 100. In
other embodiments,
however, the control system 134 may be remotely located and accessible by an
operator via
wired or wireless communication. In yet other embodiments, the control system
134 may be
located downhole, such as forming part of the solid state pump 106. In such
embodiments, the
control system 134 may comprise an autonomous or automatic controller
programmed to
control operation of the solid state pump 116 without requiring data or
command signals sent
from the surface location 104.
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[0028] The well system 100 may further include one or more sensors
configured to detect
a variety of downhole parameters and communicate with the control system 134.
It is
contemplated herein that one or more sensors may be present within the
wellbore 106 at any
suitable location. In at least one embodiment, for example, a first sensor
136a may be
operatively coupled to or form an integral part of the solid state pump 116.
The first sensor
136a may be configured to detect process parameters relating to operation of
the solid state
pump 116 and communicate with the control system 134. When the control system
134 is
located at the surface location, the first sensor 136a may communicate with
the control system
134 via the conveyance 120, but may otherwise communicate wirelessly with the
control
system 134. The control system 134 may include computer hardware and a
processor (e.g.,
microprocessor) configured to execute one or more sequences of instructions,
programming
stances, or code stored on a non-transitory, computer-readable medium. Based
on signals
received from the first sensor 136a, the control system 134 may be configured
to alter or control
operation of the solid state pump 116.
[0029] Moreover, in at least one embodiment, a second sensor 136b may be
positioned at
or near the surface location 104, such as at or near the wellhead 102. The
second sensor 136b
may also be configured to monitor downhole parameters, but at or near the
wellhead 102, and
communicate data and signals to the control system 134. While the second
sensor 136b is
depicted as being arranged outside the wellbore 106, it is contemplated herein
that the second
sensor 136b (or an additional third sensor) may be arranged within the
wellbore 106 at or near
the wellhead 102, without departing from the scope of the disclosure.
[0030] The first and second sensors 136a,b may comprise any suitable
instrument
configured to detect one or more downhole parameters. Example downhole
parameters
include, but are not limited to, downhole temperature, downhole pressure,
pressure and
temperature at an inlet to the solid state pump 116, inlet flow rate into the
solid state pump 116,
pressure and temperature at an outlet of the solid state pump 116, the
temperature of the solid
state pump 116, internal pressure(s) of the solid state pump 116, discharge
flow rate from the
solid state pump 116, system vibration, other pump system
electrical/mechanical
characteristics, downhole flow rate, pressure and temperature at or near the
wellhead 102,
flowrate of gases or liquids out of the wellbore 106, or any combination
thereof.
[0031] Data obtained from the sensors 136a,b allows the control system
134 to report
and/or display operating conditions of the well system 100 and, more
particularly, the solid
state pump 116. Based on data obtained by the sensors 136a,b, the control
system 134 may be
programmed to maintain a target liquid level within the wellbore 106 above the
solid state
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pump 116. This may include increasing a discharge flow rate of pressurized
wellbore liquid
128 generated by the solid state pump 116 to decrease the liquid level within
the wellbore 106
and/or decreasing the discharge flow rate to increase the liquid level. In
other embodiments,
the control system 134 may be programmed to regulate the discharge flow rate
to control the
discharge pressure from the solid state pump 116 and thereby prevent
deadheading against a
closed valve at the wellhead 102. This may include increasing the discharge
flow rate to
increase the discharge pressure and/or decreasing the discharge flow rate to
decrease the
discharge pressure. In other embodiments, the control system 134 may be
programmed to shut
off the solid state pump 116 when a certain system parameter (such as
temperature) exceeds or
drops below a programmed window (threshold).
[0032] Unlike traditional rod pump systems, the solid state pump 116 may
operate without
utilizing a reciprocating mechanical linkage extending to the surface location
104. This may
allow the solid state pump 116 to be utilized in long, deep, and/or deviated
wellbores where
traditional rod pump systems may be ineffective, inefficient, or otherwise
unable to generate
the pressurized wellbore liquid 128. Moreover, the solid state pump 116 may
generate
pressurized wellbore liquid 128 without requiring a threshold minimum pressure
of wellbore
gas 130. This may allow the solid state pump 116 to be utilized in hydrocarbon
wells that do
not develop sufficient gas pressure to permit utilization of traditional
plunger lift systems.
[0033] Furthermore, the solid state pump 116 may operate as a positive
displacement pump
and thus may be sized, designed, and/or configured to generate pressurized
wellbore liquid 128
at a pressure that is sufficient to convey the pressurized wellbore liquid 128
to the surface
location 104 without utilizing a large number of pumping stages. Reducing the
number of
pumping stages correspondingly decreases the length of solid state pump 116.
In some
embodiments, for example, the solid state pump 116 may include fewer than five
stages or a
.. single stage.
[0034] FIG. 2 is an enlarged partial cross-sectional view of a portion
of the well system
100 of FIG. 1. FIG. 2 also depicts an enlarged schematic view of one example
embodiment of
the solid state pump 116. As illustrated, the solid state pump 116 is
positioned within the
production tubing 112, and the production tubing 112 is extended within the
casing 110. In the
illustrated embodiment, the sealing assembly 126 comprises an expandable
packer used to
receive and secure the solid state pump 116 within the production tubing 112.
The casing 110
includes a plurality of perforations 202 that provide fluid communication
between the wellbore
106 and the surrounding subterranean formation 108.
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[0035] The solid state pump 116 may include a housing 204 and a solid
state actuator 206
may be positioned at least partially within the housing 204. The housing 204
may at least
partially define a pressure chamber 208, and the solid state actuator 206 may
be actuatable to
extend at least partially into the pressure chamber 208, as shown by the
dashed lines. The
housing 204 may provide or otherwise define one or more inlet ports 210a (one
shown) that
places the pressure chamber 208 in fluid communication with the wellbore
liquid 127 that may
be present within the wellbore 106. The housing 204 may also provide or
otherwise define one
or more outlet ports 210b (two shown) that place the pressure chamber 208 in
fluid
communication with the interior of the production tubing 112.
It) [0036] The solid state actuator 206 may include, but is not
limited to a piezoelectric
actuator, an eleetrostrictive actuator, a magnetorestrictive actuator, or any
combination thereof.
In some embodiments, the solid state actuator 206 may be made of a ceramic
perovskite
material, where the ceramic perovskite material may comprise lead zirconate
titanate or lead
magnesium niobate, In other embodiments, the solid state actuator 206 may
alternatively be
made of terbium dysprosium iron.
[0037] During an intake stroke of the solid state pump 116, the solid
state actuator 206 may
selectively transition from an extended state (shown in dashed lines) to a
contracted state. In
contrast, during an exhaust stroke, the solid state actuator 206 may
transition from the
contracted state to the extended state. During the intake stroke, the wellbore
liquid 127 may
be drawn into the pressure chamber 208 from the wellbore 106 via the inlet
port 210a. In
contrast, during the exhaust stroke, the pressurized wellbore liquid 128 may
be discharged from
the pressure chamber 208 via the outlet ports 210b.
[0038] In some embodiments, actuating the solid state actuator 206
between the extended
and contracted states may result from receipt of an electric current, such as
an AC (or DC)
electric current. In such embodiments, the discharge flow rate of the
pressurized wellbore
liquid 128 generated by the solid state pump 116 may be controlled, regulated,
and/or varied
by controlling, regulating, and/or varying the frequency of an AC (or DC)
electric current
provided to the solid state actuator 206. In some embodiments, the control
system 134 (FIG.
1) may be programmed to control the frequency of the AC (or DC) electric
current provided to
the solid state actuator 206, thus controlling the discharge flow rate. This
may include
increasing the frequency of the AC (or DC) electric current to increase the
discharge flow rate
and/or decreasing the frequency of the AC (or DC) electric current to decrease
the discharge
flow rate.
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[0039] In some embodiments, the solid state actuator 206 may be
configured to operate at
or near its resonant frequency. Illustrative, non-exclusive examples of the
frequency of the AC
(or DC) electric current include frequencies of at least 0.01 Hertz (Hz), at
least 0.05 Hz, at least
0.1 Hz, at least 0.5 Hz, at least 1 Hz, at least 5 Hz, at least 10 Hz, at
least 20 Hz, at least 30 Hz,
at least 40 Hz, at least 60 Hz, at least 80 Hz, and/or at least 100 Hz.
Additional illustrative,
non-exclusive examples of the frequency of the AC (or DC) electric current
include frequencies
of less than 4000 Hz, less than 3500 Hz, less than 3000 Hz, less than 2500 Hz,
less than 2000
Hz, less than 1500 I lz, less than 1000 Hz, less than 750 Hz, less than 500
Hz, less than 250 Hz,
less than 200 Hz, less than 150 Hz, and/or less than 100 Hz. Further
illustrative, non-exclusive
to examples of the frequency of the AC (or DC) electric current include
frequencies in any range
of the preceding minimum and maximum frequencies.
[0040] The solid state pump 116 may include one or more check valves to
help regulate
fluid flow through the pressure chamber 208 and thereby facilitate the
creation and pumping
of the pressurized wellbore liquid 128 from the wellbore 106 via the
production tubing 112.
is More particularly, one or more first check valves 214a (one shown) may
be arranged between
the inlet port 210a and the pressure chamber 208, and one or more second check
valves 214b
(two shown) may be arranged between the pressure chamber 208 and the outlet
ports 210b.
The first and second check valves 214a,b may comprise any suitable structure
that allows fluid
flow in one direction, but prevents the fluid from flowing in the opposite
direction.
20 Accordingly, the first check valve 214a may permit the wellbore liquid
127 to enter the pressure
chamber 208, but resist, restrict, and/or block the pressurized wellbore
liquid 128 from
reversing back into the wellbore 106. Moreover, the second check valves 214b
may permit the
pressurized wellbore liquid 128 to exit the pressure chamber 208 via the
outlet ports 210b, but
resist, restrict, and/or block the pressurized wellbore liquid 128 from
reversing back into the
25 pressure chamber 208.
[0041] In some embodiments, the first and second check valves 214a,b may
be passive
devices that are mechanically actuated based on fluid flow. In such
embodiments, the first and
second check valves 214a,b may comprise passive one-way disc valves. In other
embodiments,
however, the first and second check valves 214a,b may be active devices that
are electrically
30 actuated and/or electrically controlled. In such embodiments, the first
and second check valves
214a,b may comprise any type of electrically controlled check valve such as,
but not limited
to, an active mierovalve array, an active micro electromechanical system
(MEMS) valve array
or a combination thereof. The control system 134 (FIG. 1) may be in
communication with the
first and second check valves 214a,b to control operation thereof. As the
first and second check
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valves 214a,b operate, the wellbore gas 130 may flow within the annulus 132
defined between
the casing 110 and the production tubing 112.
[0042] In the illustrated embodiment, the first sensor 136a is arranged
at or near the inlet
port 210a to detect a plurality of downhole parameters at that location. A
third sensor 136c
may be arranged at or near the outlet ports 210b to likewise detect downhole
parameters at that
location. Data obtained by the first and third sensors 136a,c may be
communicated to the
control system 134 (FIG. 1) to help regulate operation of the solid state pump
116.
[0043] FIG. 3 is an enlarged schematic view of another example
embodiment of the solid
state pump 116 that may be used in the well system 100. Like numerals used in
both FIG. 2
to and FIG. 3 refer to like components not described again. As illustrated,
the solid state pump
116 is extended into the production tubing 112 on the conveyance 120, and the
production
tubing 112 is extended within the casing 110. In the illustrated embodiment,
the sealing
assembly 126 comprises a profile seat 302 positioned within the production
tubing 112 and
configured to engage a corresponding radial extension 304 coupled to or
forming part of the
solid state pump 116. In some embodiments, the profile seat 302 may comprise a
locking
groove structured and arranged to matingly engage the radial extension 304.
[0044] The solid state actuator 206 may be positioned within the housing
204 and
actuatable to draw the wellbore liquid 127 into the pressure chamber 208, and
discharge
pressurized wellbore liquid 128. The inlet port 210a is provided on the
housing 204 to place
the pressure chamber 208 in fluid communication with the wellbore liquid 127,
and the outlet
ports 210b (one shown) are provided on the housing 204 to place the pressure
chamber 208 in
fluid communication with the interior of the production tubing 112. The first
check valve 214a
is arranged between the inlet port 210a and the pressure chamber 208, and the
second check
valves 214b (one shown) are arranged between the pressure chamber 208 and the
outlet ports
210b.
[0045] In some embodiments, the solid state pump 116 may include a
barrier 306
configured to isolate the solid state actuator 206 from the pressure chamber
208 and thereby
isolate the wellbore liquid 127 from the solid state actuator 206. This may
prove advantageous
in preventing wellbore liquids containing particulates from directly
contacting the solid state
actuator 206. In some embodiments, the barrier 306 may comprise a piston
movable into and
out of the pressure chamber 208 based on actuation of the solid state actuator
206. In such
embodiments, the solid state pump 116 may be characterized as a piston pump or
the like. In
other embodiments, however, the barrier 306 may comprise a flexible isolation
structure that
is movable into and out of the pressure chamber 208 based on actuation of the
solid state
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actuator 206. In such embodiments, the flexible isolation structure may
comprise, for example,
a diaphragm, an isolation coating, or a combination thereof, and the solid
state pump 116 may
be characterized as a diaphragm pump. In yet other embodiments, the barrier
306 may
comprise a sealing structure, such as an 0-ring or the like.
[0046] In some embodiments, the system 100 may further include a well
screen or filter
308 in fluid communication with the inlet port 210a of the solid state pump
116. As illustrated,
the filter 308 may include a screen 310 through which the wellbore liquid 127
may pass, but
sand and debris (e.g., fluid particulates) of a predetermined size may be
prevented from passing
therethrough. Accordingly, the screen 310 may operate as a sand screen.
Moreover, however,
.. the screen 310 may also be configured to restrict flow of the wellbore gas
130 therethrough and
into the solid state pump 116.
[0047] In at least one embodiment, the filter 308 may further include a
standing valve 312
designed to allow the wellbore liquid 127 to pass uphole, but prevent the
wellbore liquid 127
from reversing back into the wellbore 106 below the filter 308. Accordingly,
the standing valve
312 may operate as a one-way check valve. In at least one embodiment, the
standing valve
312 may comprise a velocity fuse structured and arranged to back-flush the
filter 308 and
maintain a column of fluid within the production tubing 112 in response to an
increase in
pressure drop across the filter 308.
[0048] FIG. 4 is a schematic diagram of an example positive-displacement
solid state pump
.. 402, according to embodiments of the present disclosure. The positive-
displacement solid state
pump 402 (hereafter "the solid state pump 402") may be the same as or similar
to the solid state
pump 116 of FIGS. 1-3 and, therefore, may be best understood therewith. In
some
embodiments, the solid state pump 402 may replace the solid state pump 116 (or
any other
solid state pump described herein) in any of the embodiments discussed herein.
100491 As illustrated, the solid state pump 402 may include a housing 404
and a solid state
actuator 406 may be positioned at least partially within the housing 404. The
solid state
actuator 406 may be similar to the solid state actuator 206 of FIGS. 2-3 and,
in the illustrated
embodiment, may comprise a piezoelectric actuator stack. A power source 408
may be
communicably coupled to the solid state actuator 406 to provide power thereto,
such as AC (or
DC) current. In some embodiments, the power source 408 may comprise a surface
power
source, such as the surface power source 122 of FIG. 1. In other embodiments,
however, the
power source 408 may comprise a downhole power source, such as the onboard
power source
124 of FIG. 1, without departing from the scope of the disclosure. In either
scenario, the power
source 408 may be in communication with the control system 134 (FIG. 1), which
may control
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operation of the solid state pump 402. A frequency modulator 410 and an
amplitude modulator
412 may be connected in series, and can be adjusted to vary the frequency and
amplitude of
the signal conveyed to the solid state actuator 406.
[0050] The housing 404 may at least partially define a pressure chamber
414 and a barrier
416 may be arranged to isolate the solid state actuator 406 from the pressure
chamber 414. In
the illustrated embodiment, the barrier 416 comprises a flexible diaphragm,
but could
alternatively comprise any of the other example barriers mentioned herein. The
housing 404
may also provide or otherwise define an inlet port 418a and an outlet port
418b. A first check
valve 420a interposes the inlet port 41 8a and the pressure chamber 414 and
controls fluid flow
a into the pressure chamber 414. Similarly, a second check valve 420b
interposes the outlet port
418b and the pressure chamber 414 and controls fluid flow out of the pressure
chamber 414.
[0051] Similar to the first and second check valves 214a,b of FIGS. 2-3,
the first and second
check valves 420a,b may be passive or active devices. More specifically, the
first and second
check valves 420a,b may be mechanically actuated based on fluid flow or may be
electrically
actuated and/or electrically controlled. In embodiments where the first and
second check
valves 420a,b are mechanically actuated (passive), the first and second check
valves 420a,b
may comprise passive one-way disc valves. In embodiments where the first and
second check
valves 420a,b are electrically controlled (active), the first and second check
valves 420a,b may
be communicably coupled to the power source 408 and the control system 134 to
power and
operate (e.g., open or close) the first and second check valves 420a,b.
Moreover, in such
embodiments, the first and second check valves 420a,b may comprise any type of
electrically
controlled check valve such as, but not limited to, an active microvalve
array, an active micro
electromechanical system (MEMS) valve array or a combination thereof.
[0052] Referring now to FIGS. 5A and 5B, with continued reference to
FIG. 4, example
operation of the solid state pump 402 is depicted, according to one or more
embodiments. As
voltage (or current) is applied to the solid state actuator 406 via the power
source 408 (FIG. 4),
the solid state actuator 406 will expand and contract in response to the
supplied signal, which
causes the barrier 416 to flex (bend) up and down in a piston-like fashion.
[0053] In FIG. 5A, when the barrier 416 flexes downward, the pressure
chamber 414
experiences a pressure drop, which causes the first check valve 420a to open
and permit the
flow of fluid into the pressure chamber 414. The pressure drop correspondingly
urges the
second check valve 420b to close and thereby prevent a back flow of fluid from
the outlet port
418b into the pressure chamber 414. In embodiments where the first and second
check valves
420a,b are electrically controlled, however, the control system 134 may
operate (open and
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close) the first and second check valves 420a,b based on a predetermined
operational program
or otherwise based on detected pressures within the pressure chamber 414.
[0054] In FIG. 5B, when the barrier 416 flexes upward, the pressure
chamber 414
experiences an increase in pressure, which causes the second check valve 420b
to open and
permit fluid flow out of the pressure chamber 414. The pressure increase
correspondingly
urges the first check valve 420a to close and thereby prevent a back flow of
fluid from the
pressure chamber 414 into the inlet port 418a. In embodiments where the first
and second
check valves 420a,b are electrically controlled, the control system 134 may
operate (open and
close) the first and second check valves 420a,b based on a predetermined
operational program
io .. or otherwise based on detected pressures within the pressure chamber
414. This process may
be repeated to enable to solid state pump 402 to continuously pump fluid from
the inlet port
418a to the outlet port 418b.
[0055] FIG. 6 is an enlarged schematic view of another example pump 602
that may be
used in the well system 100 of FIG. 1, according to one or more embodiments of
the present
disclosure. The pump 602 may be similar in some respects to the pump 116 of
FIGS. 1-3 and
thus may be best understood with reference thereto. In some embodiments, the
pump 602 may
replace the pump 116. Accordingly, the pump 602 may be conveyed into the
wellbore 106 via
the conveyance 120, and the pump 602 may be communicably coupled to the
control system
134, which may control the pump 602. The control system 134 may be arranged
either at the
surface location 104 (FIG. 1) or otherwise included in the pump 602.
100561 As illustrated, the pump 602 may include a housing 604 that
contains or otherwise
houses a first pump 606 and a second pump 608. In at least one embodiment,
however, at least
one of the pumps 606, 608 may be positioned outside of the housing 604, such
as forming part
of another downhole tool or component operatively coupled to the housing 604
or the
conveyance 120. The first pump 606 may comprise a positive-displacement solid
state pump,
similar to or the same as the solid state pump 116 of FIGS. 1-3 or the solid
state pump 402 of
FIGS. 4 and 5A-5B. Accordingly, the first pump 606 may be referred to herein
as the solid
state pump 606, and may include a solid state actuator 611 actuatable to
extend at least partially
into a pressure chamber 612 defined in the housing 604, as shown by the dashed
lines. The
.. solid state actuator 611 may be the same as or similar to the solid state
actuators 206 and 406
discussed herein, and thus may include, but is not limited to a piezoelectric
actuator, an
electrostrictive actuator, a magnetorestrictive actuator, or any combination
thereof.
[0057] The solid state pump 606 may be in fluid communication with the
second or
"secondary" pump 608 via a fluid circuit 610. In some embodiments, as
illustrated, the fluid
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circuit 610 may be arranged or otherwise contained within the housing 604. In
other
embodiments, however, a portion of the fluid circuit 610 may be positioned
external to the
housing 604. As described herein, the solid state pump 606 and the secondary
pump 608 may
cooperatively operate to draw the wellbore liquid 127 into the pump 602,
pressurize the
wellbore liquid 127, and discharge the pressurized wellbore liquid 128 from
the pump 602 into
the production tubing 112 for production to the surface location 104 (FIG. 1).
In at least one
embodiment, the solid state pump 606 may operate as the "power end" to the
pump 602, while
the secondary pump 608 may operate as the "fluid end" to the pump 602.
[0058] In the illustrated embodiment, the secondary pump 608 comprises
one or more
lo expansion pumps, shown as a first expansion pump 614a and a second
expansion pump 614b.
While two expansion pumps 614a,b are depicted, it is contemplated herein that
a single
expansion pump (or more than two) may be employed, without departing from the
scope of the
disclosure.
[0059] In the illustrated embodiment, the expansion pumps 614a,b are
configured to
is .. operate in parallel within the fluid circuit 610. Each expansion pump
614a,b includes an
expandable member 616 positioned within a corresponding expansion tank 618. In
some
embodiments, the expandable member 616 may comprise an elastomer bladder, but
in other
embodiments, the expandable member 616 may comprise a metal bellows. In yet
other
embodiments, the expandable member 616 may comprise a combination of an
elastomer
20 bladder and a metal bellows.
[0060] In some embodiments, the housing 604 may provide or otherwise
define one or
more inlet ports, shown as a first inlet port 620a and a second inlet port
620b. The first
expansion pump 614a may be in fluid communication with the wellbore liquid 127
via the first
inlet port 620a, and the second expansion pump 614b may be in fluid
communication with the
25 .. wellbore liquid 127 via the second inlet port 620b. In the illustrated
embodiment, the expansion
tanks 618 of the first and second expansion pumps 614a,b are fluidly coupled
to the first and
second inlet ports 620a,b, respectively. In other embodiments, however, the
expandable
member 616 of the first and second expansion pumps 614a,b may alternatively be
fluidly
coupled to the first and second inlet ports 620a,b, respectively, without
departing from the
30 scope of the disclosure.
[0061] In some embodiments, the housing 604 may further provide or
otherwise define one
or more outlet ports, shown as a first outlet port 622a, and a second outlet
port 622b. The first
expansion pump 614a may be in fluid communication with the interior of the
production tubing
112 via the first outlet port 622a, and the second expansion pump 614b may be
in fluid
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communication with the interior of the production tubing 112 via the second
outlet port 622b.
In the illustrated embodiment, the expansion tanks 618 of the first and second
expansion pumps
614a,b are fluidly coupled to the first and second outlet ports 622a,b,
respectively. In other
embodiments, however, the expandable members 616 of the first and second
expansion pumps
614a,b may alternatively be fluidly coupled to the first and second outlet
ports 622a,b,
respectively, without departing from the scope of the disclosure.
[0062] While the inlet ports 620a,b and the outlet ports 622a,b are each
depicted as being
provided or otherwise defined by the housing 604, it is contemplated herein
that some or all of
the inlet ports 620a,b and the outlet ports 622a,b may be provided or
otherwise defined by
another downhole tool or component operatively coupled to the housing 604 or
the conveyance
120.
[0063] Actuation of the expansion pumps 614a,b may cause the wellbore
liquid 127 to be
drawn into the pump 602 and subsequently discharged as pressurized wellbore
liquid 128 into
the production tubing 112. The expansion pumps 614a,b may be actuated by
repeatedly
expanding and contracting the expandable member 616 of each expansion pump
614a,b. In
the illustrated embodiment, actuation of the expansion pumps 614a,b causes the
wellbore liquid
127 to be drawn into the respective expansion tank 618 and subsequently
discharged as
pressurized wellbore liquid 128. In other embodiments, however, actuating the
expansion
pumps 614a,b may draw the wellbore liquid 127 into the respective expandable
member 616,
which may subsequently discharge the pressurized wellbore liquid 128.
[0064] In the illustrated embodiment, the expandable members 616 may be
actuated
(expanded and contracted) by circulating a hydraulic fluid through the fluid
circuit 610 and,
more particularly, through each expandable member 616. In other embodiments,
however, the
expandable members 616 may be actuated (expanded and contracted) by
circulating a hydraulic
fluid through the respective expansion chambers 618. In such embodiments, the
circulating
hydraulic fluid within the expansion chambers 618 acts on and causes the
expandable members
616 to expand and contract. The hydraulic fluid may be made of, but is not
limited to, a mineral
oil, a dielectric oil, water, a fluid with specific additives to promote
system reliability, or any
combination thereof.
[0065] The solid state pump 606 may be operable to circulate the hydraulic
fluid through
the fluid circuit 610, and thereby actuate the expansion pumps 614a,b. More
particularly, the
solid state pump 606 may include an inlet 624a that receives the hydraulic
fluid into the
pressure chamber 612, and an outlet 624b that discharges pressurized hydraulic
fluid from the
pressure chamber 612. Actuating the solid state actuator 611 may draw the
hydraulic fluid into
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the pressure chamber 612 and subsequently discharge the pressurized hydraulic
fluid toward
the expansion pumps 614a,b. In some embodiments, the fluid circuit 610 may be
a closed loop
system, which may prove advantageous in mitigating damage to the solid state
pump 606 that
might ensue from circulating a fluid with foreign particulate matter (e.g.,
the wellbore liquid
127) therethrough.
[0066] In some embodiments, the pump 602 may further include a switching
valve 626
arranged in the fluid circuit 610 and interposing the solid state pump 606 and
the secondary
pump 608. The switching valve 626 may be configured to coordinate hydraulic
fluid flow
within the fluid circuit 610 and, more particularly, between the first and
second expansion
if) pumps 614a,b as needed. In some embodiments, the switching valve 626
may be
communicably coupled to the control system 134, which may be programmed to
operate the
switching valve 626.
[0067] In example operation, the switching valve 626 may be in a first
state where
hydraulic fluid flow is provided to actuate the first expansion pump 614a and
thereby discharge
pressurized wellbore liquid 128 via the first outlet 622a. In the illustrated
embodiment, the
hydraulic fluid may be conveyed into the expandable member 616 of the first
expansion pump
614a, which progressively compresses the wellbore liquid 127 present within
the expansion
tank 618 and eventually urges the pressurized wellbore liquid 128 out of the
expansion tank
618. In other embodiments, however, the hydraulic fluid may alternatively be
conveyed into
the expansion tank 618 of the first expansion pump 614a, which progressively
acts on the
wellbore liquid 127 that may be present within the expandable member 616 and
eventually
urges the pressurized wellbore liquid 128 out of the expandable member 616.
[0068] With the switching valve 626 in the first state, hydraulic fluid
may be also be
received from the second expansion pump 614b. More specifically, in the
illustrated
embodiment, as the expandable member 616 of the second expansion pump 614b
contracts
toward its natural state, hydraulic fluid within the expandable member 616 may
be conveyed
to the switching valve 626, which conveys the hydraulic fluid to the pressure
chamber 612 to
be pressurized. As the expandable member 616 contracts, additional wellbore
liquid 127 may
be drawn into the expansion chamber 618 of the second expansion pump 614b.
[0069] The switching valve 626 may then be actuated or "switched" to a
second state where
hydraulic fluid flow is provided to actuate the second expansion pump 614b and
thereby
discharge pressurized wellbore liquid 128 via the second outlet 622b. In the
illustrated
embodiment, the hydraulic fluid may be conveyed into the expandable member 616
of the
second expansion pump 614b, which progressively compresses the wellbore liquid
127 present
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CA 3047561 2019-06-21
within the expansion tank 618 and eventually urges the pressurized wellbore
liquid 128 out of
the expansion tank 618. In other embodiments, however, the hydraulic fluid may
alternatively
be conveyed into the expansion tank 618 of the second expansion pump 614b,
which
progressively acts on the wellbore liquid 127 that may be present within the
expandable
member 616 and eventually urges the pressurized wellbore liquid 128 out of the
expandable
member 616.
[0070] With the switching valve 626 in the second state, hydraulic fluid
may be also be
received from the first expansion pump 614a. More specifically, in the
illustrated embodiment,
as the expandable member 616 of the first expansion pump 614a contracts toward
its natural
io state, hydraulic fluid within the expandable member 616 may be conveyed
to the switching
valve 626, which conveys the hydraulic fluid to the pressure chamber 612 to be
pressurized.
As the expandable member 616 contracts, additional wellbore liquid 127 may be
drawn into
the expansion chamber 618 of the first expansion pump 614a.
[0071] The switching valve 626 may be repeatedly operated as described
above to
continuously discharge the pressurized wellbore liquid 128 into the production
tubing 112 for
production to the surface location 104 (FIG. 1).
[0072] One or more check valves may be included in the pump 602 to help
regulate fluid
flow through each expansion pump 614a,b and thereby help facilitate the
creation and pumping
of the pressurized wellbore liquid 128. More particularly, one or more first
check valves 628a
may be arranged between the first and second inlet ports 620a,b and the
expansion pumps
614a,b, respectively, and one or more second check valves 628b may be arranged
between each
expansion pump 614a,b and the first and second outlet ports 622a,b,
respectively. The first and
second check valves 628a,b may be passive or active devices similar to the
first and second
check valves 214a,b of FIGS. 2 and 3, and, therefore, may comprise any
suitable structure that
allows fluid flow in one direction, but prevents the fluid from flowing in the
opposite direction.
The first check valves 628a may permit the wellbore liquid 127 to enter each
expansion pump
614a,b, but resist, restrict, and/or block the wellbore liquid 127 from
reversing back into the
wellbore 106. Moreover, the second check valves 628b may permit the
pressurized wellbore
liquid 128 to exit each expansion pump 614a,b, but resist, restrict, and/or
block the pressurized
wellbore liquid 128 from reversing back into the respective expansion pump
614a,b.
[0073] Moreover, one or more additional check valves 630 may be included
in the fluid
circuit 610 to help regulate hydraulic fluid flow between the solid state pump
606 and the
secondary pump 608 and through the switching valve 626. As illustrated, one or
more check
valves 630 may interpose the pressure chamber 612 and the switching valve 626.
One or more
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CA 3047561 2019-06-21
check valves 630 may also interpose the switching valve 626 and each expansion
pump 614a,b.
The check valves 630 may be passive or active devices that help regulate
hydraulic fluid flow
through the hydraulic circuit 610. In some embodiments, some or all of the
check valves 630
may comprise electrically controlled check valves in communication with the
control system
134. In such embodiments, the control system 134 may operate the check valves
630 to ensure
proper fluid flow to generate the pressurized wellbore liquid 128.
[0074] In some embodiments, the pump 602 may further include one or more
sensors used
to monitor operation of the secondary pump 608. In the illustrated embodiment,
for example,
a first sensor 632a may be included in or otherwise associated with the first
expansion pump
to 614a, and a second sensor 632b may be included in or otherwise
associated with the second
expansion pump 614b. In some embodiments, the first and second sensors 632a,b
may be in
communication with the control system 134 and used to determine when an
expandable
member 616 has reached an expansion/contraction limit and thereby help trigger
a change in
the flow path of the pumped hydraulic fluid so that the other expandable
member 616 might be
.. filled/emptied. The sensors 632a,b may comprise mechanical and/or
electrical sensors such as,
but not limited to, a position sensor, a volumetric sensor, a pressure sensor,
a tensile sensor, or
any combination thereof. In at least one embodiment, outputs from the sensors
632a,b may be
conveyed to the control system 134 to trigger actuation of the switching valve
626 and thereby
alter the hydraulic fluid flow path. Alternatively, the switching valve 626
may be actuated
.. based on a pre-programmed timer that determines switch activation and
frequency.
[0075] FIG. 7 is an enlarged schematic view of another example pump 702
that may be
used in the well system 100 of FIG. 1, according to one or more embodiments of
the present
disclosure. The pump 702 may be similar in some respects to the pump 602 of
FIG. 6 and
therefore may be best understood with reference thereto, where like numerals
will represent
like components not described again in detail. Similar to the pump 602 of FIG.
6, the pump
702 may replace the pump 116 of FIGS. 1-3. Accordingly, the pump 702 may be
conveyed
into the wellbore 106 via the conveyance 120, and the pump 702 may be
communicably
coupled to the control system 134, which may control operation of the pump
702. The control
system 134 may be arranged either at the surface location 104 (FIG. 1) or
otherwise included
in the pump 702.
[0076] As illustrated, the pump 702 includes the solid state pump 606
positioned within
the housing 604. The pump 702 further includes a secondary pump 704 that may
also be
positioned within the housing 604 or alternatively form part of another
downhole tool or
component operatively coupled to the housing 604 or the conveyance 120. The
solid state
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CA 3047561 2019-06-21
pump 606 may be in fluid communication with the secondary pump 704 via a fluid
circuit 706.
In some embodiments, as illustrated, the fluid circuit 706 may be arranged or
otherwise
contained within the housing 604. In other embodiments, however, a portion of
the fluid circuit
706 may be positioned external to the housing 604.
[0077] The solid state pump 606 and the secondary pump 704 may
cooperatively operate
to draw the wellbore liquid 127 into the pump 702, pressurize the wellbore
liquid 127, and
discharge the pressurized wellbore liquid 128 from the pump 702 into the
production tubing
112 for production to the surface location 104 (FIG. 1). In at least one
embodiment, the solid
state pump 606 may operate as the "power end" to the pump 702, while the
secondary pump
704 may operate as the "fluid end" to the pump 702.
[0078] In the illustrated embodiment, the secondary pump 704 comprises a
hydraulic motor
708 operatively coupled to a fluid pump 710 with a drive shaft 712. The
hydraulic motor 708
may be configured to convert hydraulic pressure and flow into torque and
angular displacement
(rotation) of the drive shaft 712, which causes actuation of the fluid pump
710. The fluid pump
710 may comprise any type of pump configured to pressurize and discharge a
pressurized fluid.
The fluid pump 710 may include, but is not limited to, a centrifugal pump, a
rotary screw pump,
a rotary lobe pump, a gerotor pump, a progressive cavity pump, or any
combination thereof.
[0079] In some embodiments, the housing 604 may provide or otherwise
define one or
more inlet ports 714 (one shown). The fluid pump 710 may be in fluid
communication with
the wellbore liquid 127 via the inlet port 714. The housing 604 may further
provide or
otherwise define one or more outlet ports 716 (two shown). The fluid pump 710
may be in
fluid communication with the interior of the production tubing 112 via the
outlet ports 716.
While the inlet and outlet ports 714, 716 are depicted as being provided or
otherwise defined
by the housing 604, it is contemplated herein that some or all of the inlet
and outlet ports 714,
716 may be provided or otherwise defined by another downhole tool or component
operatively
coupled to the housing 604 or the conveyance 120.
[0080] Actuation of the fluid pump 710 may cause the wellbore liquid 127
to be drawn into
the pump 702 and subsequently discharged as pressurized wellbore liquid 128
into the
production tubing 112. The fluid pump 710 may be actuated by rotating the
drive shaft 712,
and actuating the fluid pump 710 causes the wellbore liquid 127 to be drawn
into the fluid
pump 710 and subsequently discharged as pressurized wellbore liquid 128. The
drive shaft
712 may be rotated by circulating a hydraulic fluid through the fluid circuit
706 and, more
particularly, through the hydraulic motor 708. As with the embodiment of FIG.
6, the hydraulic
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CA 3047561 2019-06-21
fluid may be made of, but is not limited to, a mineral oil, a dielectric oil,
water, or any
combination thereof.
[0081] The solid state pump 606 may be operable to circulate the
hydraulic fluid through
the fluid circuit 706, and thereby actuate the hydraulic motor 708. More
particularly, actuating
the solid state actuator 611 may draw the hydraulic fluid into the pressure
chamber 612 via the
inlet 624a and subsequently discharge the pressurized hydraulic fluid toward
the hydraulic
motor 708 via the outlet 624b. Accordingly, the pump 702 may be configured to
convert the
reciprocating motion of the solid state actuator 611 into a rotating motion of
the drive shaft 712
at the hydraulic pump 708, which drives (actuates) the fluid pump 710.
[0082] One or more check valves may be included in the pump 702 to help
regulate fluid
flow through the fluid pump 710 and thereby help facilitate the creation and
pumping of the
pressurized wellbore liquid 128. More particularly, one or more first check
valves 718a (one
shown) may be arranged between the inlet port 714 and the fluid pump 710, and
one or more
second check valves 718b (two shown) may be arranged between the fluid pump
710 and the
outlet ports 716. The first and second check valves 718a,b may be passive or
active devices
similar to the first and second check valves 214a,b of FIGS. 2 and 3, and,
therefore, may
comprise any suitable structure that allows fluid flow in one direction, but
prevents the fluid
from flowing in the opposite direction. The first check valve 718a may permit
the wellbore
liquid 127 to the fluid pump 710, but resist, restrict, and/or block the
wellbore liquid 127 from
reversing back into the wellbore 106. Moreover, the second check valves 7I8b
may permit the
pressurized wellbore liquid 128 to exit the fluid pump 710, but resist,
restrict, and/or block the
pressurized wellbore liquid 128 from reversing back into the fluid pump 710.
[0083] Moreover, one or more additional check valves 720 may be included
in the fluid
circuit 706 to help regulate hydraulic fluid flow between the solid state pump
606 and the
secondary pump 704. As illustrated, one or more check valves 720 may interpose
the pressure
chamber 612 and the hydraulic pump 708. The check valves 720 may be passive or
active
devices that help regulate hydraulic fluid flow through the hydraulic circuit
706. In some
embodiments, some or all of the check valves 720 may be electrically
controlled and in
communication with the control system 134. In such embodiments, the control
system 134
may operate the check valves 720 to ensure proper fluid flow to generate the
pressurized
wellbore liquid 128.
[0084] Consistent with any of the embodiments described herein, it is
contemplated to
include multiple pumps (e.g., solid state pump) installed in the well system
100, without
departing from the scope of the disclosure. As will be appreciated, this would
increase the
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CA 3047561 2019-06-21
maximum volume flow possible. Each independent pump would need to have an
independent
inlet, but their outlets may be combined to reduce the total number of flow
conduits necessary.
[0085] Embodiments disclosed herein include:
[0086] A. A pump that includes a solid state pump including a solid
state actuator
actuatable to pressurize a hydraulic fluid, and a secondary pump in fluid
communication with
the solid state pump via a fluid circuit, wherein the secondary pump is
actuatable with the
hydraulic fluid received from the solid state pump, and wherein actuating the
secondary pump
draws in an external fluid into the secondary pump, pressurizes the external
fluid within the
secondary pump, and discharges a pressurized external fluid.
to [0087] B. A well system that includes a pump arrangeable within
production tubing
extended within a wellbore, the pump including a solid state pump including a
solid state
actuator actuatable to pressurize a hydraulic fluid, and a secondary pump in
fluid
communication with the solid state pump via a fluid circuit, wherein the
secondary pump is
actuatable with the hydraulic fluid received from the solid state pump. The
well system further
including a control system communicably coupled to the pump to control
operation of the
pump, wherein actuating the secondary pump draws a wellbore liquid into the
secondary pump,
pressurizes the wellbore liquid within the secondary pump, and discharges a
pressurized
wellbore liquid into the production tubing for production to a surface
location.
[0088] C. A method that includes positioning a pump within production
tubing extended
within a wellbore, the pump including a solid state pump having a solid state
actuator, and a
secondary pump in fluid communication with the solid state pump via a fluid
circuit, actuating
the solid state actuator and thereby conveying a hydraulic fluid to the
secondary pump via the
fluid circuit, actuating the secondary pump with the hydraulic fluid received
from the solid
state pump and thereby drawing a wellbore liquid into the secondary pump and
pressurizing
the wellbore liquid within the secondary pump, discharging a pressurized
wellbore liquid from
the secondary pump and into the production tubing for production to a surface
location, and
controlling operation of the pump with a control system communicably coupled
to the pump.
[0089] Each of embodiments A, B, and C may have one or more of the
following additional
elements in any combination: Element 1: wherein the solid state actuator is
selected from the
group consisting of a piezoelectric actuator, an electrostrictive actuator, a
magnetorestrictive
actuator, and any combination thereof. Element 2: further comprising one or
more check valves
that control flow of the hydraulic fluid and the external fluid. Element 3:
wherein the secondary
pump comprises one or more expansion pumps, and each expansion pump includes
an
expansion tank and an expandable member positioned within the expansion tank.
Element 4:
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CA 3047561 2019-06-21
wherein the expandable member comprises at least one of an elastomer bladder
and a metal
bellows. Element 5: wherein the one or more expansion pumps comprise a first
expansion
pump and a second expansion pump, and wherein the pump further comprises a
switching valve
arranged in the fluid circuit to coordinate hydraulic fluid flow between the
solid state pump
and the first and second expansion pumps. Element 6: wherein the secondary
pump comprises
a hydraulic motor in fluid communication with the solid state pump to receive
the hydraulic
fluid and thereby rotate a drive shaft, and a fluid pump operatively coupled
to the hydraulic
motor via the drive shaft, wherein the external fluid is drawn into the fluid
pump and
pressurized upon rotating the drive shaft. Element 7: wherein the fluid pump
is selected from
the group consisting of a centrifugal pump, a rotary screw pump, a rotary lobe
pump, a gerotor
pump, a progressive cavity pump, and any combination thereof.
[0090] Element 8: further comprising one or more sensors in
communication with the
control system and operable to detect one or more downhole parameters, wherein
operation of
the pump is based on one or more signals received from the one or more
sensors. Element 9:
wherein the solid state actuator is selected from the group consisting of a
piezoelectric actuator,
an electrostrictive actuator, a magnetorestrictive actuator, and any
combination thereof.
Element 10: wherein the secondary pump comprises one or more expansion pumps,
and each
expansion pump includes an expansion tank and an expandable member positioned
within the
expansion tank. Element 11: wherein the expandable member comprises at least
one of an
elastomer bladder and a metal bellows. Element 12: wherein the one or more
expansion pumps
comprise a first expansion pump and a second expansion pump, the well system
further
comprising a switching valve arranged in the fluid circuit to coordinate
hydraulic fluid flow
between the solid state pump and the first and second expansion pumps. Element
13: wherein
the secondary pump comprises a hydraulic motor in fluid communication with the
solid state
pump to receive the hydraulic fluid and thereby rotate a drive shaft, and a
fluid pump
operatively coupled to the hydraulic motor via the drive shaft, wherein the
wellbore liquid is
drawn into the fluid pump and pressurized upon rotation of the drive shaft.
Element 14:
wherein the fluid pump comprises a pump selected from the group consisting of
a centrifugal
pump, a rotary screw pump, a rotary lobe pump, a gerotor pump, a progressive
cavity pump,
and any combination thereof.
[0091] Element 15: further comprising detecting one or more downhole
parameters with
one or more sensors in communication with the control system, and controlling
operation of
the pump based at least partially on one or more signals received from the one
or more sensors.
Element 16: wherein the secondary pump comprises a first expansion pump and a
second
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CA 3047561 2019-06-21
expansion pump, and wherein a switching valve is arranged in the fluid
circuit, the method
further comprising operating the switching valve to coordinate hydraulic fluid
flow between
the solid state pump and the first and second expansion pumps. Element 17:
wherein the
secondary pump comprises a hydraulic motor in fluid communication with the
solid state
pump, and a fluid pump operatively coupled to the hydraulic motor at a drive
shaft extended
from the hydraulic motor, the method further comprising receiving the
hydraulic fluid from the
solid state pump at the hydraulic motor and thereby rotating the drive shaft,
and drawing the
wellbore liquid into the fluid pump upon rotation of the drive shaft, and
thereby pressurizing
the wellbore liquid.
[0092] By way of non-limiting example, exemplary combinations applicable to
A, B, and
C include: Element 3 with Element 4; Element 3 with Element 5; Element 6 with
Element 7;
Element 10 with Element 11; Element 10 with Element 12; and Element 13 with
Element 14.
[0093] Therefore, the disclosed systems and methods are well adapted to
attain the ends
and advantages mentioned as well as those that are inherent therein. The
particular
embodiments disclosed above are illustrative only, as the teachings of the
present disclosure
may be modified and practiced in different but equivalent manners apparent to
those skilled in
the art having the benefit of the teachings herein. Furthermore, no
limitations are intended to
the details of construction or design herein shown, other than as described in
the claims below.
It is therefore evident that the particular illustrative embodiments disclosed
above may be
altered, combined, or modified and all such variations are considered within
the scope of the
present disclosure. The systems and methods illustratively disclosed herein
may suitably be
practiced in the absence of any element that is not specifically disclosed
herein and/or any
optional clement disclosed herein. While compositions and methods are
described in terms of
"comprising," "containing," or "including" various components or steps, the
compositions and
methods can also "consist essentially of" or "consist of' the various
components and steps. All
numbers and ranges disclosed above may vary by some amount. Whenever a
numerical range
with a lower limit and an upper limit is disclosed, any number and any
included range falling
within the range is specifically disclosed. In particular, every range of
values (of the form,
"from about a to about b," or, equivalently, "from approximately a to b," or,
equivalently, "from
approximately a-b") disclosed herein is to be understood to set forth every
number and range
encompassed within the broader range of values. Also, the terms in the claims
have their plain,
ordinary meaning unless otherwise explicitly and clearly defined by the
patentee. Moreover,
the indefinite articles "a" or "an," as used in the claims, are defined herein
to mean one or more
than one of the elements that it introduces. If there is any conflict in the
usages of a word or
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CA 3047561 2019-06-21
term in this specification
the definitions that are consistent with this specification should be adopted.
[0094] As used herein, the phrase "at least one of' preceding a series of
items, with the
terms "and" or "or" to separate any of the items, modifies the list as a
whole, rather than each
member of the list (i.e., each item). The phrase "at least one of" allows a
meaning that includes
at least one of any one of the items, and/or at least one of any combination
of the items, and/or
at least one of each of the items. By way of example, the phrases "at least
one of A, B, and C"
or "at least one of A, B, or C" each refer to only A, only B, or only C; any
combination of A,
B, and C; and/or at least one of each of A, B, and C.
[0095] The use of directional terms such as above, below, upper, lower,
upward,
downward, left, right, uphole, downhole and the like are used in relation to
the illustrative
embodiments as they are depicted in the figures, the upward direction being
toward the top of
the corresponding figure and the downward direction being toward the bottom of
the
corresponding figure, the uphole direction being toward the surface of the
well and the
downhole direction being toward the toe of the well.
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Date Recue/Date Received 2020-11-26
