U.S. patent application number 14/321597 was filed with the patent office on 2015-03-05 for systems and methods for artificial lift via a downhole positive displacement pump.
The applicant listed for this patent is Michael C. Romer, Randy C. Tolman. Invention is credited to Michael C. Romer, Randy C. Tolman.
Application Number | 20150060055 14/321597 |
Document ID | / |
Family ID | 51293130 |
Filed Date | 2015-03-05 |
United States Patent
Application |
20150060055 |
Kind Code |
A1 |
Tolman; Randy C. ; et
al. |
March 5, 2015 |
Systems and Methods for Artificial Lift Via a Downhole Positive
Displacement Pump
Abstract
Systems and methods for artificial lift via a downhole positive
displacement pump are disclosed herein. The methods include methods
of removing a wellbore liquid from a wellbore that extends within a
subterranean formation and/or methods of locating the downhole
positive displacement pump within the wellbore. The systems include
hydrocarbon wells that include the wellbore, a casing, a rotary
electric motor, the downhole positive displacement pump, and a
liquid discharge conduit, and the systems may be utilized with
and/or configured to perform the methods.
Inventors: |
Tolman; Randy C.; (Spring,
TX) ; Romer; Michael C.; (The Woodlands, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Tolman; Randy C.
Romer; Michael C. |
Spring
The Woodlands |
TX
TX |
US
US |
|
|
Family ID: |
51293130 |
Appl. No.: |
14/321597 |
Filed: |
July 1, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61870662 |
Aug 27, 2013 |
|
|
|
Current U.S.
Class: |
166/250.01 ;
166/369; 166/381; 166/64 |
Current CPC
Class: |
F04B 47/06 20130101;
E21B 43/126 20130101; E21B 43/128 20130101; E21B 43/305
20130101 |
Class at
Publication: |
166/250.01 ;
166/369; 166/381; 166/64 |
International
Class: |
E21B 43/12 20060101
E21B043/12 |
Claims
1. A method of removing a wellbore liquid from a wellbore that
extends within a subterranean formation, the method comprising:
electrically powering a downhole positive displacement pump; and
pumping the wellbore liquid from the wellbore with the downhole
positive displacement pump, wherein the pumping includes: (i)
pressurizing the wellbore liquid with the downhole positive
displacement pump to generate a pressurized wellbore liquid at a
discharge pressure; and (ii) flowing the pressurized wellbore
liquid at least a threshold vertical distance to a surface region
at a discharge flow rate of at least 0.75 cubic meters per day and
less than 16 cubic meters per day.
2. The method of claim 1, wherein the discharge pressure is at
least 25 MPa.
3. The method of claim 1, wherein the pumping includes continuously
pumping the wellbore liquid from the wellbore.
4. The method of claim 1, wherein the method further includes
producing a hydrocarbon gas from the subterranean formation at
least partially concurrently with the pumping.
5. The method of claim 1, wherein the pumping includes pumping with
at least a threshold pumping efficiency of at least 50%.
6. The method of claim 1, wherein the pumping includes pumping with
an axial piston pump.
7. The method of claim 1, wherein the pumping includes pumping with
a radial piston pump.
8. The method of claim 1, wherein the electrically powering
includes electrically powering with a rotary electric motor.
9. The method of claim 8, wherein the electrically powering
includes generating an electric current within the wellbore and
conveying the electric current to the rotary electric motor.
10. The method of claim 1, wherein the method further includes
detecting a downhole process parameter.
11. The method of claim 10, wherein the downhole process parameter
includes at least one of a downhole temperature, a downhole
pressure, the discharge pressure, a downhole flow rate, and the
discharge flow rate.
12. The method of claim 1, wherein the method further includes
controlling at least one of the discharge flow rate and the
discharge pressure.
13. The method of claim 12, wherein the controlling includes
regulating a rotational frequency of a rotary electric motor.
14. The method of claim 12, wherein the method includes monitoring
the discharge pressure, wherein the controlling includes regulating
the discharge flow rate to control the discharge pressure, and
further wherein the controlling includes at least one of: (i)
increasing the discharge flow rate to increase the discharge
pressure; and (ii) decreasing the discharge flow rate to decrease
the discharge pressure.
15. The method of claim 1, wherein the downhole positive
displacement pump includes a liquid inlet valve that is configured
to selectively introduce the wellbore liquid into a compression
chamber of the downhole positive displacement pump, wherein the
method includes detecting a gas lock condition of the downhole
positive displacement pump, and further wherein the method includes
opening the liquid inlet valve responsive to detecting the gas lock
condition.
16. The method of claim 1, wherein the threshold vertical distance
is at least 1000 meters.
17. The method of claim 1, wherein the downhole positive
displacement pump and a rotary electric motor together define a
downhole assembly, and further wherein a length of the downhole
assembly is less than 10 meters.
18. The method of claim 1, wherein the downhole positive
displacement pump includes fewer than three stages.
19. A method of locating a downhole positive displacement pump
within a wellbore that extends within a subterranean formation, the
method comprising: locating the downhole positive displacement pump
within a casing conduit of a casing that extends within the
wellbore, wherein the locating includes placing the downhole
positive displacement pump within a lubricator that is in selective
fluid communication with the casing conduit; and conveying the
downhole positive displacement pump through the casing conduit
until the downhole positive displacement pump is at least a
threshold vertical distance from a surface region, wherein the
casing conduit defines a nonlinear region, and further wherein the
conveying includes conveying through the nonlinear region.
20. The method of claim 19, wherein the nonlinear region includes
at least one of a tortuous region, a curvilinear region, a deviated
region, an L-shaped region, an S-shaped region, and a transition
region between a horizontal region and a vertical region.
21. The method of claim 19, wherein the conveying includes at least
one of conveying without first supplying a kill weight fluid to the
wellbore and conveying while containing wellbore fluids within the
wellbore.
22. The method of claim 19, wherein the conveying includes
establishing a fluid flow from the surface region, through the
casing conduit, and into the subterranean formation, and flowing
the downhole positive displacement pump through the casing conduit
with the fluid flow.
23. The method of claim 19, wherein the threshold vertical distance
is at least 1000 meters.
24. The method of claim 19, wherein the downhole positive
displacement pump and a rotary electric motor together define a
downhole assembly, and further wherein a length of the downhole
assembly is less than 10 meters.
25. The method of claim 19, wherein the downhole positive
displacement pump includes fewer than three stages.
26. A hydrocarbon well, comprising: a wellbore that extends between
a surface region and a subterranean formation; a casing that
extends within the wellbore and defines a casing conduit; a rotary
electric motor that is located within the casing conduit; a
downhole positive displacement pump that is configured to be
powered by the rotary electric motor, wherein the downhole positive
displacement pump is located within the wellbore at least a
threshold vertical distance from the surface region, wherein the
downhole positive displacement pump and the rotary electric motor
together define a downhole assembly, and further wherein a length
of the downhole assembly is less than 10 meters; and a liquid
discharge conduit that extends between the downhole positive
displacement pump and the surface region and is in fluid
communication with the casing conduit via the downhole positive
displacement pump, wherein the downhole positive displacement pump
is configured to convey a wellbore liquid from the casing conduit
via the liquid discharge conduit; and wherein at least one of: (i)
the threshold vertical distance is at least 1000 meters; and (ii)
the casing conduit defines a nonlinear region and the downhole
assembly is located downhole from the nonlinear region.
27. The well of claim 26, wherein the nonlinear region includes at
least one of a tortuous region, a curvilinear region, a deviated
region, an L-shaped region, an S-shaped region, and a transition
region between a horizontal region and a vertical region.
28. The well of claim 26, wherein the well further includes a
controller that is programmed to control the operation of at least
one of the rotary electric motor and the downhole positive
displacement pump.
29. The well of claim 28, wherein the controller is programmed to
maintain a target wellbore liquid level within the wellbore above
the downhole positive displacement pump.
30. The well of claim 28, wherein the well further includes a
sensor that is configured to detect a downhole process
parameter.
31. The well of claim 30, wherein the downhole process parameter
includes at least one of a discharge flow rate from the downhole
positive displacement pump and a discharge pressure from the
downhole positive displacement pump.
32. The well of claim 30, wherein the controller is programmed to
control a rotational frequency of the rotary electric motor based,
at least in part, on the downhole process parameter.
33. The well of claim 30, wherein the downhole positive
displacement pump includes an axial piston pump, and further
wherein the controller is programmed to regulate a plate angle of a
wobble plate of the axial piston pump based, at least in part, on
the downhole process parameter.
34. The well of claim 30, wherein the downhole positive
displacement pump includes a liquid inlet valve that is configured
to selectively introduce the wellbore liquid into a compression
chamber of the downhole positive displacement pump, wherein the
downhole process parameter is indicative of a gas lock condition of
the downhole positive displacement pump, and further wherein the
controller is programmed to open the liquid inlet valve responsive
to the downhole process parameter indicating the gas lock
condition.
35. The well of claim 28, wherein the controller is programmed to
regulate a discharge flow rate from the downhole positive
displacement pump to control a discharge pressure from the downhole
positive displacement pump, and further wherein the controller is
programmed to at least one of: (i) increase the discharge flow rate
to increase the discharge pressure; and (ii) decrease the discharge
flow rate to decrease the discharge pressure.
36. The well of claim 26, wherein the well further includes a
lubricator that is in fluid communication with the casing conduit,
wherein the downhole positive displacement pump and the rotary
electric motor together define a downhole assembly, and further
wherein the downhole assembly is sized to be located within the
lubricator.
37. The well of claim 26, wherein the downhole positive
displacement pump includes fewer than three stages.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional No.
61/870,662, filed Aug. 27, 2013, the entirety of which is
incorporated herein by reference for all purposes.
FIELD OF THE DISCLOSURE
[0002] The present disclosure is directed generally to systems and
methods for artificial lift in a wellbore and more specifically to
systems and methods that utilize a downhole positive displacement
pump to remove a wellbore liquid from the wellbore.
BACKGROUND OF THE DISCLOSURE
[0003] A hydrocarbon well may be utilized to produce gaseous
hydrocarbons from a subterranean formation. Often, a wellbore
liquid may build up within one or more portions of the hydrocarbon
well. This wellbore liquid, which may include water, condensate,
and/or liquid hydrocarbons, may impede flow of the gaseous
hydrocarbons from the subterranean formation to a surface region
via the hydrocarbon well, thereby reducing and/or completely
blocking gaseous hydrocarbon production from the hydrocarbon
well.
[0004] Traditionally, plunger lift and/or rod pump systems have
been utilized to provide artificial lift and to remove this
wellbore liquid from the hydrocarbon well. While these systems may
be effective under certain circumstances, they may not be capable
of efficiently removing the wellbore liquid from long and/or deep
hydrocarbon wells, from hydrocarbon wells that include one or more
deviated (or nonlinear) portions (or regions), and/or from
hydrocarbon wells in which the gaseous hydrocarbons do not generate
at least a threshold pressure.
[0005] As an illustrative, non-exclusive example, plunger lift
systems require that the gaseous hydrocarbons develop at least the
threshold pressure to provide a motive force to convey a plunger
between the subterranean formation and the surface region. As
another illustrative, non-exclusive example, rod pump systems
utilize a mechanical linkage (i.e., a rod) that extends between the
surface region and the subterranean formation; and, as the depth of
the well (or length of the mechanical linkage) is increased, the
mechanical linkage becomes more prone to failure and/or more prone
to damage the casing. As yet another illustrative, non-exclusive
example, neither plunger lift systems nor rod pump systems may be
utilized effectively in wellbores that include deviated and/or
nonlinear regions.
[0006] Improved hydrocarbon well drilling technologies permit an
operator to drill a hydrocarbon well that extends for many
thousands of meters within the subterranean formation, has a
vertical depth of hundreds, or even thousands, of meters, and/or
that has a highly deviated wellbore. These improved drilling
technologies are routinely utilized to drill long and/or deep
hydrocarbon wells that permit production of gaseous hydrocarbons
from previously inaccessible subterranean formations. However,
wellbore liquids cannot be removed efficiently from these
hydrocarbon wells using traditional artificial lift systems. Thus,
there exists a need for improved systems and methods for artificial
lift to remove wellbore liquids from a hydrocarbon well.
SUMMARY OF THE DISCLOSURE
[0007] Systems and methods for artificial lift via a downhole
positive displacement pump are disclosed herein. The methods may
include methods of removing a wellbore liquid from a wellbore that
extends within a subterranean formation. These methods include
electrically powering the downhole positive displacement pump and
pumping the wellbore liquid from the wellbore with the downhole
positive displacement pump. The pumping may include pressurizing
the wellbore liquid with the downhole positive displacement pump to
generate a pressurized wellbore liquid at a discharge pressure and
flowing the pressurized wellbore liquid at least a threshold
vertical distance to a surface region at a discharge flow rate of
at least 0.75, and less than 16, cubic meters (approximately 5 to
approximately 100 barrels) per day.
[0008] In some embodiments, the pressurizing may include
pressurizing to a discharge pressure of at least 25 MPa,
continuously pumping the wellbore liquid from the wellbore, and/or
pumping with at least a threshold pumping efficiency of at least
50%. In some embodiments, the pumping may include pumping with an
axial piston pump and/or pumping with a radial piston pump. In some
embodiments, the electrically powering may include electrically
powering with a rotary electric motor. In some embodiments, these
methods further may include detecting a downhole process parameter.
In some embodiments, these methods further may include controlling
the discharge flow rate and/or the discharge pressure, such as
responsive at least in part to the detected process parameter. In
some embodiments, these methods further may include detecting a gas
lock condition of the downhole positive displacement pump and
opening a liquid inlet valve of the downhole positive displacement
pump responsive to detecting the gas lock condition.
[0009] The methods also may include methods of locating (i.e.,
inserting and/or positioning) the downhole positive displacement
pump within the wellbore. These methods may include locating the
downhole positive displacement pump within a casing conduit of a
casing that extends within the wellbore by locating the downhole
positive displacement pump within a lubricator that is in selective
fluid communication with the casing conduit. These methods further
may include conveying the downhole positive displacement pump
through a nonlinear region of the casing conduit until the downhole
positive displacement pump is located at least a threshold vertical
distance from the surface region.
[0010] In some embodiments, the conveying may include flowing the
downhole positive displacement pump through the casing conduit with
a fluid flow. In some embodiments, the downhole positive
displacement pump and a rotary electric motor together define a
downhole assembly with a length of less than 10 meters. In some
embodiments, the downhole positive displacement pump includes fewer
than three stages.
[0011] The systems include hydrocarbon wells that include the
wellbore, a casing, a rotary electric motor, the downhole positive
displacement pump, and a liquid discharge conduit and may be
utilized with and/or configured to perform the methods. In some
embodiments, the downhole positive displacement pump may be located
at least 1000 meters from a surface region and/or may be located
downhole from a nonlinear region of the casing conduit. In some
embodiments, the hydrocarbon well further includes a controller
that is programmed to control the operation of the rotary electric
motor and/or of the downhole positive displacement pump. In some
embodiments, the hydrocarbon well includes a sensor that is
configured to detect a downhole process parameter. In some
embodiments, the controller is programmed or otherwise configured
to control the operation of the downhole positive displacement pump
responsive, at least in part, to the detected downhole process
parameter.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] FIG. 1 is a schematic representation of illustrative,
non-exclusive examples of a hydrocarbon well that may be utilized
with and/or may include the systems and methods according to the
present disclosure.
[0013] FIG. 2 is a schematic block diagram of illustrative,
non-exclusive examples of a downhole assembly according to the
present disclosure that includes a rotary electric motor and a
downhole positive displacement pump.
[0014] FIG. 3 is a schematic cross-sectional view of an
illustrative, non-exclusive example of an axial piston pump that
may be utilized with the systems and methods according to the
present disclosure.
[0015] FIG. 4 is a schematic cross-sectional view of an
illustrative, non-exclusive example of a radial piston pump that
may be utilized with the systems and methods according to the
present disclosure.
[0016] FIG. 5 is a fragmentary partial cross-sectional view of less
schematic but still illustrative, non-exclusive examples of a
hydrocarbon well that includes a downhole assembly according to the
present disclosure.
[0017] FIG. 6 is a fragmentary partial cross-sectional view of less
schematic but still illustrative, non-exclusive examples of another
hydrocarbon well that includes a downhole assembly according to the
present disclosure.
[0018] FIG. 7 is a flowchart depicting methods according to the
present disclosure of removing a wellbore liquid from a
wellbore.
[0019] FIG. 8 is a flowchart depicting methods according to the
present disclosure of locating a downhole positive displacement
pump within a wellbore.
DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE
[0020] FIGS. 1-6 provide illustrative, non-exclusive examples of
hydrocarbon wells 10 according to the present disclosure and of
downhole assemblies 40 according to the present disclosure that may
be utilized in and/or with hydrocarbon wells 10. All elements may
not be labeled in each of FIGS. 1-6, but reference numerals
associated therewith may be utilized herein for consistency.
Elements, components, and/or features that are discussed herein
with reference to one or more of FIGS. 1-6 may be included in
and/or utilized with any of FIGS. 1-6 without departing from the
scope of the present disclosure.
[0021] In general, elements that are likely to be included in a
given (i.e., a particular) embodiment are illustrated in solid
lines, while elements that are optional to a given embodiment are
illustrated in dashed lines. However, elements that are shown in
solid lines are not essential to all embodiments, and an element
shown in solid lines may be omitted from a particular embodiment
without departing from the scope of the present disclosure.
[0022] FIG. 1 is a schematic representation of illustrative,
non-exclusive examples of a hydrocarbon well 10 that may be
utilized with and/or include the systems and methods according to
the present disclosure, while FIG. 2 is a schematic block diagram
of illustrative, non-exclusive examples of a downhole assembly 40
according to the present disclosure that includes a rotary electric
motor 50 and a downhole positive displacement pump 60.
[0023] Hydrocarbon well 10 includes a wellbore 20 that extends
between a surface region 12 and a subterranean formation 16 that is
present within a subsurface region 14. The hydrocarbon well further
includes a casing 30 that extends within the wellbore and defines a
casing conduit 32. A downhole assembly 40, which includes a rotary
electric motor 50 and a downhole positive displacement pump 60, is
located within the casing conduit at least a threshold vertical
distance 48 from surface region 12. Threshold vertical distance 48
additionally or alternatively may be referred to as threshold
vertical depth 48. The downhole positive displacement pump is
configured to be powered by the rotary electric motor, such as to
receive a wellbore liquid 22 and to pressurize the wellbore liquid
to generate a pressurized wellbore liquid 24. A liquid discharge
conduit 80 extends between downhole positive displacement pump 60
and surface region 12. The liquid discharge conduit is in fluid
communication with casing conduit 32 via downhole positive
displacement pump 60 and is configured to convey pressurized
wellbore liquid 24 from the casing conduit, such as to surface
region 12.
[0024] As illustrated in dashed lines in FIG. 1, hydrocarbon well
10 may include a lubricator 28 that may be utilized to locate
(i.e., insert and/or position) downhole assembly 40 within casing
conduit 32 and/or to remove the downhole assembly from the casing
conduit. In addition, and as illustrated in FIGS. 1-2, an injection
conduit 38 may extend between surface region 12 and downhole
assembly 40 and may be configured to inject a corrosion inhibitor
and/or a scale inhibitor into casing conduit 32 and/or into fluid
contact with downhole positive displacement pump 60, such as to
decrease a potential for corrosion of and/or scale build-up within
the downhole positive displacement pump.
[0025] As also illustrated in dashed lines, hydrocarbon well 10
and/or downhole assembly 40 further may include a sand control
structure 44, which may be configured to limit flow of sand into an
inlet of positive displacement pump 60, and/or a gas control
structure 46, which may limit flow of a wellbore gas 26 (as
illustrated in FIG. 1) into downhole positive displacement pump 60.
As further illustrated in dashed lines in FIG. 1, casing 30 may
have a seat 34 attached thereto, with seat 34 being configured to
receive downhole assembly 40 and/or to retain downhole assembly 40
at, or within, a desired region and/or location within casing 30.
Additionally or alternatively, downhole assembly 40 may include
and/or be operatively attached to a packer 42. Packer 42 may be
configured to swell or otherwise be expanded within casing conduit
32 and to thereby retain downhole assembly 40 at, or within, the
desired region and/or location within casing 30.
[0026] Returning to FIGS. 1-2, hydrocarbon well 10 and/or downhole
assembly 40 thereof further may include a power source 54 that is
configured to provide an electric current to rotary electric motor
50. In addition, a sensor 92 may be configured to detect a downhole
process parameter and may be located within wellbore 20, may be
operatively attached to downhole assembly 40, and/or may form a
portion of the downhole assembly. The sensor may be configured to
convey a data signal that is indicative of the process parameter to
surface region 12 and/or may be in communication with a controller
90 that is configured to control the operation of at least a
portion of downhole assembly 40, such as by controlling rotary
electric motor 50 and/or downhole positive displacement pump
60.
[0027] As discussed, downhole assembly 40 includes rotary electric
motor 50 and downhole positive displacement pump 60. Downhole
assembly 40 further may include a coupling 52 that is configured to
transfer a mechanical power output from rotary electric motor 50 to
downhole positive displacement pump 60. Illustrative, non-exclusive
examples of coupling 52 include any suitable mechanical coupling,
direct coupling, direct mechanical coupling, shaft, magnetic
coupling, and/or flexible vibration dampener. As also discussed,
rotary electric motor 50 may be powered by (or receive electric
current from) power source 54, which may be operatively attached to
downhole assembly 40, may form a portion of downhole assembly 40,
and/or may be in electrical communication with downhole assembly 40
via an electrical conduit 56. Thus, downhole assembly 40 according
to the present disclosure may be configured to generate pressurized
wellbore liquid 24 without utilizing a reciprocating mechanical
linkage that extends between surface region 12 and the downhole
assembly (such as might be utilized with traditional rod pump
systems) to provide a motive force for operation of downhole
positive displacement pump 60. This may permit downhole assembly 40
to be utilized in long, deep, and/or deviated wellbores where
traditional rod pump systems may be ineffective, inefficient,
and/or unable to generate the pressurized wellbore liquid.
[0028] Similarly, and since downhole positive displacement pump 60
is powered by rotary electric motor 50, downhole assembly 40 may be
configured to generate pressurized wellbore liquid 24 (and/or to
remove the pressurized wellbore liquid from casing conduit 32 via
liquid discharge conduit 80) without requiring a threshold minimum
pressure of wellbore gas 26. This may permit downhole assembly 40
to be utilized in hydrocarbon wells 10 that do not develop
sufficient gas pressure to permit utilization of traditional
plunger lift systems and/or that define long and/or deviated casing
conduits 32 that preclude the efficient operation of traditional
plunger lift systems.
[0029] Furthermore, and since downhole assembly 40 includes
positive displacement pump 60, the downhole assembly may be sized,
designed, and/or configured to generate pressurized wellbore liquid
24 at a pressure that is sufficient to permit the pressurized
wellbore liquid to be conveyed via liquid discharge conduit 80 to
surface region 12 without utilizing a large number of pumping
stages. It follows that reducing the number of pumping stages may
decrease a length 41 of the downhole assembly (as illustrated in
FIG. 1). As illustrative, non-exclusive examples, downhole assembly
40 may include fewer than five stages, fewer than four stages,
fewer than three stages, or a single stage.
[0030] As additional illustrative, non-exclusive examples, the
length of the downhole assembly may be less than 30 meters (m),
less than 28 m, less than 26 m, less than 24 m, less than 22 m,
less than 20 m, less than 18 m, less than 16 m, less than 14 m,
less than 12 m, less than 10 m, less than 8 m, less than 6 m, or
less than 4 m. Additionally or alternatively, an outer diameter of
the downhole assembly may be less than 20 centimeters (cm), less
than 18 cm, less than 16 cm, less than 14 cm, less than 12 cm, less
than 10 cm, less than 9 cm, less than 8 cm, less than 7 cm, less
than 6 cm, or less than 5 cm.
[0031] This (relatively) small length and/or (relatively) small
diameter of downhole assemblies 40 according to the present
disclosure may permit the downhole assemblies to be located within
and/or to flow through and/or past deviated regions 33 within
wellbore 20 and/or casing conduit 32 that might obstruct and/or
retain longer and/or larger-diameter downhole assemblies that do
not include rotary electric motor 50 and downhole positive
displacement pump 60 and/or that utilize a larger number (such as
more than 5, more than 6, more than 8, more than 10, more than 15,
or more than 20) of stages to generate pressurized wellbore liquid
24. Thus, downhole assemblies 40 according to the present
disclosure may be operable in hydrocarbon wells 10 that are
otherwise inaccessible to more traditional pumping technologies.
This may include locating downhole assembly 40 uphole from deviated
regions 33, as schematically illustrated in dashed lines in FIG. 1,
and/or locating downhole assembly 40 downhole from deviated regions
33, such as in a horizontal portion of wellbore 20 and/or near a
toe end 21 of wellbore 20 (as schematically illustrated in dash-dot
lines in FIG. 1).
[0032] Additionally or alternatively, the (relatively) small length
and/or the (relatively) small diameter of downhole assemblies 40
according to the present disclosure may permit the downhole
assemblies to be located within casing conduit 32 and/or be removed
from casing conduit 32 via lubricator 28. This may permit the
downhole assemblies to be located within the casing conduit without
depressurizing hydrocarbon well 10, without killing well 10,
without first supplying a kill weight fluid to wellbore 20, and/or
while containing wellbore fluids within the wellbore. This may
increase an overall efficiency of downhole assemblies 40 being
inserted into and/or removed from wellbore 20, may decrease a time
required to permit downhole assemblies 40 to be inserted into
and/or removed from wellbore 20, and/or may decrease a potential
for damage to hydrocarbon well 10 when downhole assemblies 40 are
inserted into and/or removed from wellbore 20.
[0033] Furthermore, and as discussed in more detail herein,
downhole assemblies 40 according to the present disclosure may be
configured to generate pressurized wellbore liquid 24 at relatively
low discharge flow rates and/or at selectively variable discharge
flow rates. This may permit downhole assembly 40 to efficiently
operate in low production rate hydrocarbon wells and/or in
hydrocarbon wells that generate low volumes of wellbore liquid 22,
in contrast to more traditional artificial lift systems.
[0034] Downhole positive displacement pump 60 may include any
suitable positive displacement pump that may be powered by rotary
electric motor 50, may receive wellbore liquid 22, and/or may
pressurize the wellbore liquid to generate pressurized wellbore
liquid 24. As illustrative, non-exclusive examples, downhole
positive displacement pump 60 may include and/or be a gear pump, a
gerotor positive displacement pump, an internal gear positive
displacement pump, an external gear positive displacement pump, a
screw pump, a triple screw positive displacement pump, a
progressing cavity pump, a roots pump, a plunger pump, a piston
pump, an axial piston positive displacement pump, a linear angle
plate positive displacement pump, a rotary vane positive
displacement pump, and a radial piston positive displacement
pump.
[0035] As a more specific but still illustrative, non-exclusive
example, and as schematically illustrated in FIG. 3, downhole
positive displacement pump 60 may include an axial piston pump 100.
The axial piston pump may include a wobble plate 102 and a
plurality of pistons 104 that are operatively attached to and/or in
mechanical communication with the wobble plate. The plurality of
pistons may reciprocate along a plurality of (substantially)
parallel reciprocation axes 106. When downhole positive
displacement pump 60 is located within wellbore 20, the plurality
of parallel reciprocation axes may be (substantially) parallel to a
longitudinal axis of wellbore 20. The wobble plate may be an
adjustable angle wobble plate that is configured to change, vary,
and/or regulate a distance that each of the plurality of pistons
reciprocates through changes in an angle 108 of the wobble plate
relative to the plurality of reciprocation axes, thereby
(selectively) changing a discharge flow rate of the downhole
positive displacement pump. A plurality of check valves 110 may
regulate and/or restrict flow of wellbore fluid 22 into the axial
piston pump and/or flow of pressurized wellbore fluid 24 out of the
axial piston pump.
[0036] As another more specific but still illustrative,
non-exclusive example, and as schematically illustrated in FIG. 4,
downhole positive displacement pump 60 may include a radial piston
pump 120. The radial piston pump may include an eccentric shaft 122
and a plurality of pistons 104 that are operatively attached to
and/or in mechanical communication with the eccentric shaft. The
plurality of pistons may define a plurality of nonparallel
reciprocation axes 124. When downhole positive displacement pump 60
is located within wellbore 20, the plurality of nonparallel
reciprocation axes may be (substantially) perpendicular to the
longitudinal axis of the wellbore. Similar to axial piston pump
100, a plurality of check valves 110 may regulate and/or restrict
flow of wellbore fluid 22 into the axial piston pump and/or flow of
pressurized wellbore fluid 24 out of the axial piston pump.
[0037] Returning to FIGS. 1-2, downhole positive displacement pump
60 further may include a liquid inlet valve 62. Liquid inlet valve
62 may be configured to selectively introduce wellbore liquid 22
into a compression chamber 64 of downhole positive displacement
pump 60, as discussed in more detail herein.
[0038] Rotary electric motor 50 may include any suitable structure
that is configured to power downhole positive displacement pump 60.
As illustrative, non-exclusive examples, rotary electric motor 50
may include and/or be an AC rotary electric motor, a DC rotary
electric motor, and/or a variable speed rotary electric motor.
[0039] As discussed, wellbore 20 may define a deviated region 33,
which also may be referred to herein as a nonlinear region 33, that
may have a deviated (i.e., nonvertical) and/or nonlinear trajectory
within subsurface region 14 and/or subterranean formation 16
thereof (as schematically illustrated in FIG. 1). In addition, and
as also discussed, downhole assembly 40, including rotary electric
motor 50 and/or downhole positive displacement pump 60, may be
located downhole from deviated region 33. As illustrative,
non-exclusive examples, nonlinear region 33 may include and/or be a
tortuous region, a curvilinear region, an L-shaped region, an
S-shaped region, and/or a transition region between a
(substantially) horizontal region and a (substantially) vertical
region that may define a tortuous trajectory, a curvilinear
trajectory, a deviated trajectory, an L-shaped trajectory, an
S-shaped trajectory, and/or a transitional, or changing,
trajectory.
[0040] Power source 54 may include any suitable structure that may
be configured to provide the electric current to rotary electric
motor 50 and may be present in any suitable location. As an
illustrative, non-exclusive example, power source 54 may be located
in surface region 12, and electrical conduit 56 may extend between
the power source and the rotary electric motor. Illustrative,
non-exclusive examples of electrical conduit 56 include any
suitable wire, cable, wireline, and/or working line, and electrical
conduit 56 may connect to rotary electric motor 50 via any suitable
electrical connection and/or wet-mate connection.
[0041] As another illustrative, non-exclusive example, power source
54 may include and/or be a battery pack. The battery pack may be
located within surface region 12, may be located within wellbore
20, and/or may be operatively and/or directly attached to downhole
assembly 40 and/or to rotary electric motor 50 thereof.
[0042] As additional illustrative, non-exclusive examples, power
source 54 may include and/or be a generator, an AC generator, a DC
generator, a turbine, a solar-powered power source, a wind-powered
power source, and/or a hydrocarbon-powered power source that may be
located within surface region 12 and/or within wellbore 20. When
power source 54 is located within wellbore 20, the power source
also may be referred to herein as a downhole power generation
assembly 54.
[0043] Sensor 92 may include any suitable structure that is
configured to detect the downhole process parameter. Illustrative,
non-exclusive examples of the downhole process parameter include a
downhole temperature, a downhole pressure, a discharge pressure
from the downhole positive displacement pump, a downhole flow rate,
and/or a discharge flow rate from the downhole positive
displacement pump.
[0044] It is within the scope of the present disclosure that sensor
92 may be configured to detect the downhole process parameter at
any suitable location within wellbore 20. As an illustrative,
non-exclusive example, the sensor may be located such that the
downhole process parameter is indicative of a condition at an inlet
to downhole positive displacement pump 60. As another illustrative,
non-exclusive example, the sensor may be located such that the
downhole process parameter is indicative of a condition at an
outlet from downhole positive displacement pump 60.
[0045] When hydrocarbon well 10 includes sensor 92, the hydrocarbon
well also may include a data communication conduit 94 (as
illustrated in FIG. 1) that may be configured to convey a signal
that is indicative of the downhole process parameter between sensor
92 and surface region 12. As an illustrative, non-exclusive
example, controller 90 may be located within surface region 12, and
data communication conduit 94 may convey the signal to the
controller. As another illustrative, non-exclusive example, the
data communication conduit may convey the signal to a display
and/or to a terminal that is located within surface region 12.
[0046] Controller 90 may include any suitable structure that may be
configured to control the operation of any suitable portion of
hydrocarbon well 10, such as downhole assembly 40, rotary electric
motor 50, and/or downhole positive displacement pump 60. This may
include controlling using methods 200 and/or methods 300, which are
discussed in more detail herein.
[0047] As illustrated in FIG. 1, controller 90 may be located in
any suitable portion of hydrocarbon well 10. As an illustrative,
non-exclusive example, the controller may include and/or be an
autonomous and/or automatic controller that is located within
wellbore 20 and/or that is directly and/or operatively attached to
downhole assembly 40, to rotary electric motor 50, and/or to
downhole positive displacement pump 60. Thus, controller 90 may be
configured to control the operation of downhole assembly 40 without
requiring that a data signal be conveyed to surface region 12 via
data communication conduit 94. Additionally or alternatively,
controller 90 may be located within surface region 12 and may
communicate with downhole assembly 40 via data communication
conduit 94.
[0048] As an illustrative, non-exclusive example, controller 90 may
be programmed to maintain a target wellbore liquid level within
wellbore 20 above downhole positive displacement pump 60. This may
include increasing a discharge flow rate of pressurized wellbore
liquid 24 that is generated by the downhole positive displacement
pump to decrease the wellbore liquid level and/or decreasing the
discharge flow rate to increase the wellbore liquid level.
[0049] As another illustrative, non-exclusive example, controller
90 may be programmed to regulate the discharge flow rate to control
the discharge pressure from the downhole positive displacement
pump. 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.
[0050] As a more specific but still illustrative, non-exclusive
example, and when hydrocarbon well 10 includes sensor 92,
controller 90 may be programmed to control a rotational frequency
of rotary electric motor 50 based, at least in part, on the
downhole process parameter. This may include increasing the
rotational frequency to increase the discharge flow rate and/or
decreasing the rotational frequency to decrease the discharge flow
rate.
[0051] As another more specific but still illustrative,
non-exclusive example, and when downhole positive displacement pump
60 includes the axial piston pump, controller 90 may be programmed
to control the angle of the wobble plate based, at least in part,
on the downhole process parameter. This may include changing the
angle to increase and/or decrease the discharge flow rate.
[0052] As yet another more specific but still illustrative,
non-exclusive example and when downhole positive displacement pump
60 includes a gear pump, controller 90 may be programmed to control
a spacing between gears of the gear pump based, at least in part,
on the downhole process parameter. This may include increasing the
spacing to decrease the discharge flow rate and/or decreasing the
spacing to increase the discharge flow rate.
[0053] As another more specific but still illustrative,
non-exclusive example, and when downhole positive displacement pump
60 includes liquid inlet valve 62, controller 90 may be programmed
to control the operation of the liquid inlet valve. This may
include opening the liquid inlet valve to permit wellbore fluid to
enter compression chamber 64 of the downhole positive displacement
pump responsive to the downhole process parameter indicating a gas
lock condition of the downhole positive displacement pump.
[0054] As discussed, downhole assembly 40 according to the present
disclosure may be utilized to provide artificial lift in wellbores
that define a large vertical distance, or depth, 48, in wellbores
that define a large overall length, and/or in wellbores in which
downhole assembly 40 is located at least a threshold vertical
distance from surface region 12. As illustrative, non-exclusive
examples, the vertical depth of wellbore 20, the overall length of
wellbore 20, and/or the threshold vertical distance of downhole
assembly 40 from surface region 12 may be at least 250 meters (m),
at least 500 m, at least 750 m, at least 1000 m, at least 1250 m,
at least 1500 m, at least 1750 m, at least 2000 m, at least 2250 m,
at least 2500 m, at least 2750 m, at least 3000 m, at least 3250 m,
and/or at least 3500 m. Additionally or alternatively, the vertical
depth of wellbore 20, the overall length of wellbore 20, and/or the
threshold vertical distance of downhole assembly 40 from surface
region 12 may be less than 8000 m, less than 7750 m, less than 7500
m, less than 7250 m, less than 7000 m, less than 6750 m, less than
6500 m, less than 6250 m, less than 6000 m, less than 5750 m, less
than 5500 m, less than 5250 m, less than 5000 m, less than 4750 m,
less than 4500 m, less than 4250 m, and/or less than 4000 m.
Further additionally or alternatively, the vertical depth of
wellbore 20, the overall length of wellbore 20, and/or the
threshold vertical distance of downhole assembly 40 from surface
region 12 may be in a range defined, or bounded, by any combination
of the preceding maximum and minimum depths.
[0055] FIG. 5 provides less schematic but still illustrative,
non-exclusive examples of a hydrocarbon well 10 that includes a
downhole assembly 40 according to the present disclosure. In FIG.
5, downhole assembly 40 is located within a casing conduit 32 that
is defined by a casing 30. Casing 30 includes a plurality of
perforations 36 that provide fluid communication between casing
conduit 32 and a subterranean formation 16. Downhole assembly 40 is
retained within a liquid discharge conduit 80 by a seat 34 and/or
by a packer 42 and is configured to receive wellbore liquid 22 from
casing conduit 32 and to generate pressurized wellbore liquid 24
therefrom.
[0056] As illustrated in FIG. 5, wellbore gas 26 may flow within an
annular space that is defined within casing conduit 32 between
casing 30 and a tubing 78 that defines liquid discharge conduit 80.
As also illustrated in FIG. 5, a plurality of sensors 92 may detect
a plurality of downhole process parameters at an inlet 66 to
downhole positive displacement pump 60 and/or at an outlet 67 from
the downhole positive displacement pump.
[0057] FIG. 6 provides less schematic but still illustrative,
non-exclusive examples of another hydrocarbon well 10 that includes
a downhole assembly 40 according to the present disclosure that
includes a downhole positive displacement pump 60 and a rotary
electric motor 50. In FIG. 6, downhole assembly 40 is retained
within a liquid discharge conduit 80 by a seat 34 and/or by a
packer 42. Downhole positive displacement pump 60 receives a
wellbore liquid 22 via an inlet 66 thereof, pressurizes the
wellbore liquid to generate a pressurized wellbore liquid 24, and
discharges the pressurized wellbore liquid from an outlet 67 in the
form of an outlet valve 68.
[0058] Downhole assembly 40 of FIG. 6 further may include and/or be
utilized with additional features and/or structures, such as those
that are discussed in more detail herein. As illustrative,
non-exclusive examples, and as illustrated in FIG. 6, downhole
assembly 40 may include a controller 90 and/or sensors 92, and
sensors 92 may be located near and/or associated with inlet 66
and/or outlet 67.
[0059] As another illustrative, non-exclusive example, a coupler 52
may operatively connect downhole positive displacement pump 60 and
rotary electric motor 50. As yet another illustrative,
non-exclusive example, a gas control structure 46 may restrict flow
of a wellbore gas into downhole positive displacement pump 60. As
another illustrative, non-exclusive example, an electrical conduit
56 and/or a data communication conduit 94 may be in electrical
communication with downhole assembly 40, may extend within casing
conduit 32, and/or may extend within liquid discharge conduit
80.
[0060] FIG. 7 is a flowchart depicting methods 200 according to the
present disclosure of removing a wellbore liquid from a wellbore
that extends within a subterranean formation. Methods 200 may
include detecting a downhole process parameter at 210 and include
electrically powering a downhole positive displacement pump at 220
and pumping the wellbore liquid from the wellbore at 230. Methods
200 further may include producing a hydrocarbon gas at 240,
controlling the operation of a downhole assembly at 250, injecting
a supplemental material into the wellbore at 260, restricting sand
flow into the downhole positive displacement pump at 270, and/or
restricting hydrocarbon gas flow into the downhole positive
displacement pump at 280.
[0061] Detecting the downhole process parameter at 210 may include
detecting any suitable downhole process parameter that is
indicative of any suitable condition within the wellbore. As
illustrative, non-exclusive examples, the downhole process
parameter may be collected at, or near, an inlet to the downhole
positive displacement pump, may be indicative of a condition at, or
near, the inlet to the downhole positive displacement pump, may be
collected at, or near, an outlet from the downhole positive
displacement pump, and/or may be indicative of a condition at, or
near, the outlet from the positive displacement pump. Illustrative,
non-exclusive examples of the downhole process parameter are
discussed herein. When methods 200 include the detecting at 210,
methods 200 further may include communicating the downhole process
parameter to a surface region and/or utilizing the downhole process
parameter to control the operation of the downhole assembly. This
may include controlling the operation of the downhole positive
displacement pump and/or of a rotary electric motor that is
configured to power the downhole positive displacement pump, as
discussed herein.
[0062] Electrically powering the downhole positive displacement
pump at 220 may include electrically powering the downhole positive
displacement pump with the rotary electric motor, such as via any
suitable coupling between the downhole positive displacement pump
and the rotary electric motor. The electrically powering at 220 may
include conveying an electric current from the surface region to
the rotary electric motor, such as via an electrical conduit, and
providing the electric current to the rotary electric motor.
Additionally or alternatively, the electrically powering at 220
also may include generating the electric current within the
wellbore and conveying the electric current to the rotary electric
motor. Illustrative, non-exclusive examples of the rotary electric
motor, the electrical conduit, and/or the coupling are discussed
herein.
[0063] Pumping the wellbore liquid from the wellbore at 230 may
include pumping the wellbore liquid from the wellbore with the
downhole positive displacement pump. This may include pressurizing,
at 232, the wellbore liquid within the downhole positive
displacement pump to generate a pressurized wellbore liquid at a
discharge pressure and/or flowing, at 234, the pressurized wellbore
liquid at least a threshold vertical distance to the surface region
at a discharge flow rate.
[0064] The pumping at 230 may include at least substantially
continuously pumping the wellbore liquid from the wellbore and/or
pumping the pressurized wellbore liquid through a liquid discharge
conduit that extends within the wellbore and/or between the
downhole positive displacement pump and the surface region.
Illustrative, non-exclusive examples of the discharge pressure
include discharge pressures of at least 20 megapascals (MPa), at
least 25 MPa, at least 30 MPa, at least 35 MPa, at least 40 MPa, at
least 45 MPa, at least 50 MPa, at least 55 MPa, at least 60 MPa, at
least 65 MPa, and/or at least 70 MPa. Additionally or
alternatively, the discharge pressure also may be less than 100
MPa, less than 95 MPa, less than 80 MPa, less than 75 MPa, less
than 70 MPa, less than 65 MPa, less than 60 MPa, less than 55 MPa,
and/or less than 50 MPa. Further additionally or alternatively, the
discharge pressure may be in a range bounded by any combination of
the preceding minimum and maximum discharge pressures.
[0065] The discharge pressure (in kilopascals) also may be at least
a threshold multiple of the threshold vertical distance (in
meters). Illustrative, non-exclusive examples of the threshold
multiple include threshold multiples of at least 5, at least 6, at
least 7, at least 8, at least 9, at least 10, at least 11, and/or
at least 12.
[0066] Illustrative, non-exclusive examples of the discharge flow
rate include discharge flow rates of at least 0.5, at least 0.75,
at least 1, at least 2, at least 3, at least 4, at least 5, at
least 6, at least 7, at least 8, at least 9, at least 10, at least
12, at least 14, at least 16, at least 18, at least 20, at least
22, at least 24, at least 26, at least 28, and/or at least 30 cubic
meters per day. Additionally or alternatively, the discharge flow
rate also may be less than 40, less than 38, less than 36, less
than 34, less than 32, less than 30, less than 28, less than 26,
less than 24, less than 22, less than 20, less than 18, less than
16, less than 14, less than 12, less than 10, less than 9, less
than 8, less than 7, less than 6, less than 5, less than 4, less
than 3, less than 2, and/or less than 1 cubic meters per day.
Further additionally or alternatively, the discharge flow rate may
be in a range bounded by any combination of the preceding minimum
and maximum discharge flow rates.
[0067] The pumping at 230 further may include pumping with at least
a threshold pumping efficiency. Illustrative, non-exclusive
examples of the threshold pumping efficiency include threshold
pumping efficiencies of at least 50%, at least 55%, at least 60%,
at least 65%, at least 70%, at least 75%, and/or at least 80%.
[0068] As a more specific but still illustrative, non-exclusive
example, the pumping at 230 also may include pumping with an axial
piston pump. This may include rotating a wobble plate to
reciprocate a plurality of pistons that is associated with the
axial piston pump. The plurality of pistons may reciprocate along a
respective plurality of (substantially) parallel reciprocation axes
that may be (substantially) parallel to a longitudinal axis of the
wellbore. Additionally or alternatively, this also may include
changing an angle of the wobble plate relative to the plurality of
pistons to change the discharge flow rate of the downhole positive
displacement pump.
[0069] As another more specific but still illustrative,
non-exclusive example, the pumping at 230 also may include pumping
with a radial piston pump. This may include rotating an eccentric
shaft to reciprocate a plurality of pistons that is associated with
the radial piston pump and/or reciprocating the plurality of
pistons along a respective plurality of nonparallel reciprocation
axes.
[0070] Producing the hydrocarbon gas at 240 may include producing
the hydrocarbon gas from the subterranean formation and may be
performed at least partially concurrently with the pumping at 230.
As an illustrative, non-exclusive example, the producing at 240 may
include producing through a gas discharge conduit that extends
within the wellbore and/or between the subterranean formation and
the surface region.
[0071] Controlling the operation of the downhole assembly at 250
may include controlling the operation of any suitable portion of
the downhole assembly, and it is within the scope of the present
disclosure that the controlling at 250 may be accomplished in any
suitable manner. As illustrative, non-exclusive examples, the
controlling at 250 may include automatically controlling,
autonomously controlling, controlling with a controller that is
located within the wellbore, controlling with a controller that is
directly attached to the downhole assembly and/or to the downhole
positive displacement pump, and/or controlling without requiring
that a data signal be conveyed between the downhole assembly and
the surface region.
[0072] As illustrative, non-exclusive examples, the controlling at
250 may include controlling the discharge flow rate and/or the
discharge pressure from the downhole positive displacement pump. As
additional illustrative, non-exclusive examples, and as discussed
herein, the controlling at 250 also may include regulating a
rotational frequency of the rotary electric motor, regulating a
spacing between gears of a gear pump that comprises the downhole
positive displacement pump, and/or regulating an angle of a wobble
plate of an axial piston pump that comprises the downhole positive
displacement pump.
[0073] As a more specific but still illustrative, non-exclusive
example, the controlling at 250 also may include maintaining a
target wellbore liquid level within the wellbore above the downhole
positive displacement pump (or an inlet thereof), such as to
prevent (or decrease a potential for) a gas lock condition within
the downhole positive displacement pump. As another more specific
but still illustrative, non-exclusive example, the detecting at 210
may include monitoring the discharge pressure from the downhole
positive displacement pump, and the controlling at 250 may include
regulating the discharge flow rate to control the discharge
pressure. 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.
[0074] As yet another more specific but still illustrative,
non-exclusive example, the downhole positive displacement pump may
include a liquid inlet valve that is configured to selectively
introduce the wellbore liquid into a compression chamber of the
downhole positive displacement pump. Under these conditions, the
detecting at 210 may include detecting a gas lock condition of the
downhole positive displacement pump, and the controlling at 250 may
include opening the liquid inlet valve responsive to detecting the
gas lock condition.
[0075] Injecting the supplemental material into the wellbore at 260
may include injecting any suitable supplemental material into any
suitable portion of the wellbore. As an illustrative, non-exclusive
example, the injecting at 260 may include injecting a corrosion
inhibitor and/or a scale inhibitor into the wellbore, such as to
decrease a potential for corrosion of and/or scale buildup within
the downhole positive displacement pump and/or to increase a
service life of the downhole positive displacement pump. As another
illustrative, non-exclusive example, the injecting at 260 also may
include injecting downhole from the downhole positive displacement
pump, injecting into the downhole positive displacement pump,
and/or injecting such that the supplemental material flows through
the downhole positive displacement pump with the wellbore
liquid.
[0076] Restricting sand flow into the downhole positive
displacement pump at 270 may include restricting using any suitable
structure. As an illustrative, non-exclusive example, the
restricting at 270 may include restricting with a sand filter.
Similarly, restricting hydrocarbon gas flow into the downhole
positive displacement pump at 280 may include restricting using any
suitable structure. As an illustrative, non-exclusive example, the
restricting at 280 may include restricting with a gas-liquid
separation assembly that is located upstream from, that is
operatively attached to, and/or that forms a portion of the
downhole positive displacement pump.
[0077] FIG. 8 is a flowchart depicting methods 300 according to the
present disclosure of locating a downhole positive displacement
pump within a wellbore that extends within a subterranean
formation. Methods 300 include locating the downhole positive
displacement pump within a casing conduit at 310 and conveying the
downhole positive displacement pump through the casing conduit at
320. Methods 300 further may include retaining the downhole
positive displacement pump at a desired location within the casing
conduit at 330, coupling the downhole positive displacement pump
with a power source at 340, and/or producing a wellbore liquid from
the wellbore at 350. The downhole positive displacement pump may
form a portion of and/or may be operatively attached to a downhole
assembly that includes the downhole positive displacement pump and
a rotary electric motor, and methods 300 may be performed with, or
on, the downhole assembly.
[0078] Locating the downhole positive displacement pump within the
casing conduit at 310 may include locating the downhole positive
displacement pump in any suitable casing conduit that may be
defined by a casing that extends within the wellbore. As an
illustrative, non-exclusive example, the locating at 310 may
include placing the downhole positive displacement pump within a
lubricator that is in selective fluid communication with the casing
conduit and/or transferring the downhole positive displacement pump
from the lubricator to the casing conduit. As another illustrative,
non-exclusive example, the locating at 310 also may include
locating without first killing a hydrocarbon well that includes the
wellbore, locating without supplying a kill weight fluid to the
wellbore, locating while containing (all) wellbore fluids within
the wellbore, and/or locating without depressurizing (or completely
depressurizing) the wellbore (or at least a portion of the wellbore
that is proximal to the surface region).
[0079] Conveying the downhole positive displacement pump through
the casing conduit at 320 may include conveying until the downhole
positive displacement pump is at least a threshold vertical
distance from the surface region. Illustrative, non-exclusive
examples of the threshold vertical distance are disclosed
herein.
[0080] It is within the scope of the present disclosure that the
casing conduit may define a nonlinear trajectory and/or a nonlinear
region and that the conveying at 320 may include conveying along
the nonlinear trajectory, through the nonlinear region, and/or past
the nonlinear region. Illustrative, non-exclusive examples of the
nonlinear region and/or the nonlinear trajectory are discussed
herein.
[0081] The conveying may be accomplished in any suitable manner. As
an illustrative, non-exclusive example, the conveying may include
establishing a fluid flow from the surface region, through the
casing conduit, and into the subterranean formation; and the
conveying at 320 may include flowing the downhole positive
displacement pump through the casing conduit with the fluid flow.
As additional illustrative, non-exclusive examples, the conveying
at 320 also may include conveying on a wireline, conveying with
coiled tubing, conveying with rods, and/or conveying with a
tractor.
[0082] Retaining the downhole positive displacement pump at the
desired location within the casing conduit at 330 may include
retaining the downhole positive displacement pump in any suitable
manner. As an illustrative, non-exclusive example, the retaining at
330 may include swelling a packer that is operatively attached to
the downhole positive displacement pump to retain the downhole
positive displacement pump at the desired location. As another
illustrative, non-exclusive example, the retaining at 330 also may
include locating the downhole positive displacement pump on a seat
that is present within the casing conduit and that is configured to
receive and/or to retain the downhole positive displacement
pump.
[0083] Coupling the downhole positive displacement pump with the
power source at 340 may include coupling the downhole positive
displacement pump with the power source subsequent to the conveying
at 320. Illustrative, non-exclusive examples of the power source
are disclosed herein.
[0084] Producing the wellbore liquid from the wellbore at 350 may
include producing the wellbore liquid with the downhole positive
displacement pump and may be accomplished in any suitable manner.
As an illustrative, non-exclusive example, the producing at 350 may
be at least substantially similar to the pumping at 230, which is
discussed in more detail herein.
[0085] In the present disclosure, several of the illustrative,
non-exclusive examples have been discussed and/or presented in the
context of flow diagrams, or flow charts, in which the methods are
shown and described as a series of blocks, or steps. Unless
specifically set forth in the accompanying description, it is
within the scope of the present disclosure that the order of the
blocks may vary from the illustrated order in the flow diagram,
including with two or more of the blocks (or steps) occurring in a
different order and/or concurrently. It is also within the scope of
the present disclosure that the blocks, or steps, may be
implemented as logic, which also may be described as implementing
the blocks, or steps, as logics. In some applications, the blocks,
or steps, may represent expressions and/or actions to be performed
by functionally equivalent circuits or other logic devices. The
illustrated blocks may, but are not required to, represent
executable instructions that cause a computer, processor, and/or
other logic device to respond, to perform an action, to change
states, to generate an output or display, and/or to make
decisions.
[0086] As used herein, the term "and/or" placed between a first
entity and a second entity means one of (1) the first entity, (2)
the second entity, and (3) the first entity and the second entity.
Multiple entities listed with "and/or" should be construed in the
same manner, i.e., "one or more" of the entities so conjoined.
Other entities may optionally be present other than the entities
specifically identified by the "and/or" clause, whether related or
unrelated to those entities specifically identified. Thus, as a
non-limiting example, a reference to "A and/or B," when used in
conjunction with open-ended language such as "comprising" may
refer, in one embodiment, to A only (optionally including entities
other than B); in another embodiment, to B only (optionally
including entities other than A); in yet another embodiment, to
both A and B (optionally including other entities). These entities
may refer to elements, actions, structures, steps, operations,
values, and the like.
[0087] As used herein, the phrase "at least one," in reference to a
list of one or more entities should be understood to mean at least
one entity selected from any one or more of the entity in the list
of entities, but not necessarily including at least one of each and
every entity specifically listed within the list of entities and
not excluding any combinations of entities in the list of entities.
This definition also allows that entities may optionally be present
other than the entities specifically identified within the list of
entities to which the phrase "at least one" refers, whether related
or unrelated to those entities specifically identified. Thus, as a
non-limiting example, "at least one of A and B" (or, equivalently,
"at least one of A or B," or, equivalently "at least one of A
and/or B") may refer, in one embodiment, to at least one,
optionally including more than one, A, with no B present (and
optionally including entities other than B); in another embodiment,
to at least one, optionally including more than one, B, with no A
present (and optionally including entities other than A); in yet
another embodiment, to at least one, optionally including more than
one, A, and at least one, optionally including more than one, B
(and optionally including other entities). In other words, the
phrases "at least one," "one or more," and "and/or" are open-ended
expressions that are both conjunctive and disjunctive in operation.
For example, each of the expressions "at least one of A, B and C,"
"at least one of A, B, or C," "one or more of A, B, and C," "one or
more of A, B, or C" and "A, B, and/or C" may mean A alone, B alone,
C alone, A and B together, A and C together, B and C together, A, B
and C together, and optionally any of the above in combination with
at least one other entity.
[0088] In the event that any patents, patent applications, or other
references are incorporated by reference herein and (1) define a
term in a manner that is inconsistent with and/or (2) are otherwise
inconsistent with, either the non-incorporated portion of the
present disclosure or any of the other incorporated references, the
non-incorporated portion of the present disclosure shall control,
and the term or incorporated disclosure therein shall only control
with respect to the reference in which the term is defined and/or
the incorporated disclosure was present originally.
[0089] As used herein the terms "adapted" and "configured" mean
that the element, component, or other subject matter is designed
and/or intended to perform a given function. Thus, the use of the
terms "adapted" and "configured" should not be construed to mean
that a given element, component, or other subject matter is simply
"capable of" performing a given function but that the element,
component, and/or other subject matter is specifically selected,
created, implemented, utilized, programmed, and/or designed for the
purpose of performing the function. It is also within the scope of
the present disclosure that elements, components, and/or other
recited subject matter that is recited as being adapted to perform
a particular function may additionally or alternatively be
described as being configured to perform that function, and vice
versa.
INDUSTRIAL APPLICABILITY
[0090] The systems and methods disclosed herein are applicable to
the oil and gas industry.
[0091] It is believed that the disclosure set forth above
encompasses multiple distinct inventions with independent utility.
While each of these inventions has been disclosed in its preferred
form, the specific embodiments thereof as disclosed and illustrated
herein are not to be considered in a limiting sense as numerous
variations are possible. The subject matter of the inventions
includes all novel and non-obvious combinations and subcombinations
of the various elements, features, functions and/or properties
disclosed herein. Similarly, where the claims recite "a" or "a
first" element or the equivalent thereof, such claims should be
understood to include incorporation of one or more such elements,
neither requiring nor excluding two or more such elements.
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