Patent Publication Number: US-2015060055-A1

Title: Systems and Methods for Artificial Lift Via a Downhole Positive Displacement Pump

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     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 
     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 
     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. 
     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. 
     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. 
     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 
     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. 
     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. 
     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. 
     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. 
     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 
         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. 
         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. 
         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. 
         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. 
         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. 
         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. 
         FIG. 7  is a flowchart depicting methods according to the present disclosure of removing a wellbore liquid from a wellbore. 
         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 
       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. 
     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. 
       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 . 
     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 . 
     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. 
     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 . 
     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 . 
     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. 
     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. 
     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. 
     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. 
     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 ). 
     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 . 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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 . 
     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. 
     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 . 
     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 . 
     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. 
     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 . 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
       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. 
     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. 
       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 . 
     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 . 
     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 . 
       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 . 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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%. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
       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. 
     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). 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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. 
     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 
     The systems and methods disclosed herein are applicable to the oil and gas industry. 
     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.