WO2025179110A1

WO2025179110A1 - Gas interference detection and control of long-stroke pumping unit speed for gas interference mitigation

Info

Publication number: WO2025179110A1
Application number: PCT/US2025/016741
Authority: WO
Inventors: Brandon FURR; Ian NICKELL; Terry Treiberg; Brett Williams
Original assignee: ChampionX LLC
Current assignee: ChampionX LLC
Priority date: 2024-02-22
Filing date: 2025-02-21
Publication date: 2025-08-28
Anticipated expiration: 2026-08-22
Also published as: US20250270919A1

Abstract

Managing gas interference in a downhole pump, such as for liquid hydrocarbon well production, is accomplished by monitoring pump operational data indicating liquid pump fillage values, determining from indicative patterns in the monitored data, possibly observed over a number of pump strokes, whether a gas interference condition exists, and in response to determining that the gas interference condition exists, increasing a normal pump speed to a higher speed. In response to determining that the gas interference condition does not exist, a normal pump speed may be resumed.

Description

GAS INTERFERENCE DETECTION AND CONTROL OF LONG-STROKE PUMPING UNIT SPEED FOR GAS INTERFERENCE MITIGATION

FIELD OF THE DISCLOSURE

[0001] The present disclosure generally relates to long-stroke pumping units. More specifically, the present disclosure relates to managing gas interference conditions in the downhole pump of the long-stroke pumping unit.

BACKGROUND

[0002] A wellbore may be drilled into a subterranean formation to produce liquid hydrocarbons (e.g., crude oil) from a producing portion of the subterranean formation. An artificial lift system may then be used to pump fluids from the subterranean formation, through the wellbore, and up to a wellhead located at the surface of the earth. Wells can use a reciprocating rod pumping unit, sometimes called a long-stroke pumping unit.

[0003] Long-stroke pumping units can include a long-stroke mechanism, a set of moving rods termed a rod string extending down through the wellbore, and a plunger connected to the rod string in the wellbore. The rod string and the plunger to which it is connected generally move together between upper and lower pump positions in an upstroke and a downstroke. The plunger includes one or more valves that open to capture fluid in the wellbore on a downstroke and then close to lift the fluid on the upstroke. The opening and closing of the valves, the filling of the plunger, and the force exerted to lower and lift the rod string at various displacement lengths vary with the downhole conditions. [0004] During production, some wells produce gas along with liquid hydrocarbons. The gas could be dissolved in the liquid hydrocarbons to some extent or could occur in distinct accumulations referred to as “slugs” or “pockets” or “gas pockets” that move from the producing portion of the subterranean formation into the wellbore. This phenomenon often occurs when wells include slanted or horizontal portions, which is an increasingly prevalent situation in the industry.

[0005] As such, there is a tendency for the gas to enter the downhole plunger with the liquid hydrocarbons, which may decrease the volume of liquid lifted during each pump cycle. That is, the gas in a well often causes the plunger to become partly filled with liquid instead of fully filled with liquid. This incomplete liquid pump fillage reduces production efficiency and may be damaging to equipment, and is thus termed “gas interference.” [0006] Some approaches to managing gas interference generally include either ignoring the problem by just continuing the usual pump operation cycles, or by slowing or stopping pump operation for a time. Maintaining existing pump cycle rates in the presence of gas interference reduces the liquid hydrocarbon production rate, which reduces revenue.

[0007] Further, production equipment is operated longer to produce a given volume of oil when liquid pump fillage values are reduced due to the presence of gas. Equipment wear and related repairs therefore exacerbate the problem of reduced revenues by increasing expenses.

[0008] Thus, an improved method for managing gas interference in downhole pumps would be advantageous.

SUMMARY

[0009] Disclosed is a method for managing a gas interference condition in a downhole pump, including: monitoring, by a controller of the downhole pump, data indicating liquid pump fillage values for the downhole pump; determining, by the controller, one or more patterns in the monitored data indicating that the gas interference condition exists; and in response to determining that the gas interference condition exists, increasing, by the controller, a normal pump operation speed of the downhole pump to a higher speed.

[0010] Also disclosed is a system for managing a gas interference condition in a downhole pump, including: a controller of the downhole pump that: monitors data indicating liquid pump fillage values for the downhole pump; determines one or more patterns in the monitored data indicating that the gas interference condition exists; and in response to determining that the gas interference condition exists, increases a normal pump operation speed of the downhole pump to a higher speed.

[0011] Also disclosed is a non-transitory computer-readable storage medium having embedded therein a set of instructions which, when executed by one or more processors of a computer, causes the computer to execute operations for managing a gas interference condition in a downhole pump, the operations including: monitoring data indicating liquid pump fillage values for the downhole pump; determining one or more patterns in the monitored data indicating that the gas interference condition exists; and in response to determining that the gas interference condition exists, increasing a normal pump operation speed of the downhole pump to a higher speed.

[0012] Also disclosed is an apparatus for managing a gas interference condition in a downhole pump, including: the downhole pump; a pump motor that actuates the downhole pump; a sensor that generates data; and a controller that performs operations including: monitoring data indicating liquid pump fillage values for the downhole pump; determining one or more patterns in the monitored data indicating that the gas interference condition exists; and in response to determining that the gas interference condition exists, increasing a normal pump operation speed of the downhole pump to a higher speed.

[0013] Also disclosed is a method including: controlling, by a controller of a long-stroke pump, a stroke speed of a plunger upwards and downwards in a wellbore to a first value to produce one or more liquid hydrocarbons from the wellbore, wherein the plunger is coupled to a surface unit of the long-stroke pumping unit via a rod string; detecting, by a sensor of the long-stroke pump, that a gas interference condition is present in the wellbore; and in response to detecting the gas interference condition, changing, by the controller, the stroke speed of the plunger upwards and downwards in the wellbore to a second value, wherein the second value is greater than the first value.

[0014] Other technical features may be readily apparent to one skilled in the art from the following figures, descriptions, and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[0015] For a more complete understanding of this disclosure, reference is now made to the following description, taken in conjunction with the accompanying drawings, in which:

[0016] FIG. 1 is a schematic view of a long-stroke pumping unit used for producing hydrocarbon fluids from a subsurface formation up to the surface at a well site.

[0017] FIG. 2 is a diagram of a controller for a long-stroke pumping unit.

[0018] FIG. 3 is a graph of a dynamometer card analyzed by the controller for a long- stroke pumping unit.

[0019] FIG 4 is a diagram of the logic operations performed by the controller for a long- stroke pumping unit. DETAILED DESCRIPTION

[0020] Various aspects of the disclosure are described more fully hereinafter with reference to the accompanying drawings. This disclosure may, however, be implemented in many different forms and should not be construed as limited to any specific structure or function presented throughout this disclosure. Rather, these aspects are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art. Based on the teachings herein one skilled in the art should appreciate that the scope of the disclosure is intended to cover any aspect of the disclosure disclosed herein, whether implemented independently of or combined with any other aspect of the disclosure. For example, a method, apparatus, system, or memory may be implemented or practiced using any number of the aspects set forth herein. In addition, the scope of the disclosure is intended to cover such an apparatus or method which is practiced using other structure, functionality, or structure and functionality in addition to or other than the various aspects of the disclosure set forth herein. It should be understood that any aspect of the disclosure disclosed herein may be embodied by one or more elements of a claim. The word “exemplary” is used herein to mean “serving as an example, instance, or illustration.” Any aspect described herein as “exemplary” is not necessarily to be construed as preferred or advantageous over other aspects. Although particular aspects are described herein, many variations and permutations of these aspects fall within the scope of the disclosure. Although some benefits and advantages of the aspects are mentioned, the scope of the disclosure is not intended to be limited to particular benefits, uses, or objectives. The detailed description and drawings are merely illustrative of the disclosure rather than limiting, the scope of the disclosure being defined by the appended claims and equivalents thereof.

[0021] Definitions:

[0022] For purposes of the present application, it will be understood that the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. The term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. Hydrocarbon fluids may include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions, or at ambient conditions. Hydrocarbon fluids may include, for example, oil, natural gas, shale oil, and other hydrocarbons that are in a gaseous or liquid state. The term “fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and solids, combinations of liquids and solids, and combinations of gases, liquids, and solids. The term “wellbore fluids” means water, hydrocarbon fluids, formation fluids, or any other fluids that may be within a string of drill pipe during a drilling operation. The term “gas” refers to a fluid that is in its vapor phase at in situ conditions. The term “subsurface” refers to geologic strata occurring below the earth’s surface. The term “formation” refers to any definable subsurface region regardless of size. The formation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any geologic formation. The term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shapes. The term “well” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.” The term “bore” refers to the opening formed in the subsurface by the drilling process.

[0023] Disclosed are techniques for managing gas interference in a downhole pump, such as for liquid hydrocarbon well production. Briefly, the techniques include increasing pump speed upon detection of a gas interference condition, to speed the removal of the gas from the well. Normal liquid pumping operations may resume upon detection that the gas interference condition has been removed.

[0024] Controllers can be designed for vertical wells, where fluid entry into the wellbore tends to be steady and not often plagued by gas interference. In a horizontal well, however, slug flow will more frequently occur, potentially causing alternating downhole pump conditions of predominantly liquid and then predominantly gas. This pattern may confuse a controller to take an action that has a non-corrective effect.

[0025] It has been found that in the case of gas interference, an increase in the cycle rate of the long-stroke pumping unit may be a corrective action for the well controller to execute. This approach to managing gas interference is counterintuitive and unexpectedly effective. An unexpected result of this counterintuitive approach is that gas interfering with liquid pump fillage is cleared out relatively quickly, thereby avoiding pump damage and production decreases or stoppages caused by longer-term gas interference. It is also evidently contrary to current industry practice.

[0026] Increasing the pump speed avoids the production reductions and/or delays caused by stopping the pump or decreasing pump speed previously described. Increasing the pump speed also clears out a gas slug faster than would be the case if normal pump speed were maintained. During the faster-pumping corrective action, the liquid pump fillage rate values can be less than optimum, but the relatively-brief pump speed increase may allow resumption of normal pump speed sooner. A temporary increase in pump speed to clear out a gas slug may actually lead to less damage to a pump that is designed to primarily handle liquids. This is because the described approach clears out a gas slug faster and more reliably than by natural outgassing in a stopped or slowed pump.

[0027] FIG. 1 illustrates a side elevational view of a long-stroke pumping unit 100. The long-stroke pumping unit 100 is positioned on a foundation 10 next to a wellhead 120 at the surface 20 of the earth. A wellbore 121 fluidly connects the wellhead 120 with a producing zone of the subterranean formation 21 in which the wellbore 121 is formed. A casing 122 may extend from the wellhead 120 into at least a portion of the wellbore 121 , for example, by being cemented to the wall of the wellbore 121 . Production tubing 123 may extend from the wellhead 120 and into the wellbore 121 within the casing 122. The production tubing 123 may be fluidly connected to a downhole pump.

[0028] The wellhead 120 may include any equipment known in the art with the aid of this disclosure, such as a production tree, stuffing box, seals, or combinations thereof. The wellhead 120 fluidly connects with a hydrocarbon production line 124, through which produced fluid flows from the wellhead 120 to another location, such as a storage vessel or pipeline. A polished rod 125 extends through the wellhead 120 (e.g., via seals to prevent leakage of produced fluid from the wellhead 120) and is connected to a rod string 126. The rod string 126 is connected to a plunger 127 that travels upward and downward in the production tubing 123 to move fluids into the hydrocarbon production line 124. The polished rod 125 is coupled to the long-stroke pumping unit 100 through a hanger assembly 119 (or called a bridle assembly).

[0029] While the long-stroke pumping unit 100 in FIG. 1 is embodied as a tower-style unit, in aspects, the long-stroke pumping unit 100 may be embodied as a beam-type long- stroke pumping unit known in the art with the aid of this disclosure.

[0030] In aspects, the long-stroke pumping unit 100 may include a base frame 101 , a tower 102 positioned on an end 103 of the base frame 101 , a prime mover 104 coupled to equipment in the tower 102 via a shaft 105 and positioned on the base frame 101 , and a control interface 106 and a controller 200 for controlling the mechanical equipment in the long-stroke pumping unit 100.

[0031] The foundation 10 may be an immovable, level structure, such as a foundation formed of concrete or cement. The foundation 10 may be a single structure formed to support the base frame 101 of the long-stroke pumping unit 100. Alternatively, for some aspects of the base frame 101 , the foundation 10 may be multiple structures that are formed to support the base frame 101. The base frame 101 is a structure that supports the tower 102, the prime mover 104, the control interface 106, and the controller 200. The base frame 101 sits or rests on the foundation 10 and is configured to be positioned on the foundation 10 proximate to the wellhead 120 (at a well site).

[0032] The tower 102 of long-stroke pumping unit 100 may include a housing 109, a drive sprocket 110, a chain 111 , a chain idler 112, a carriage 113, a counterweight assembly 114, a top 115, a drum assembly 116, a braking system 117, a load belt 118, and the hanger assembly 119. The configuration of the tower 102 is by example, and other configurations of the tower 102 are contemplated to fall within the scope of this disclosure.

[0033] The housing 109 may be a metal structure configured to house, enclose, and/or support the drive sprocket 110, the chain 111 , the chain idler 112, the carriage 113, the counterweight assembly 114, the top 115, the drum assembly 116, the braking system 117, and the load belt 118. The base of the housing 109 may include an amount of lubricant for lubricating the chain 111 as the chain 111 is rotated around the drive sprocket 110. The drive sprocket 110 is mechanically coupled to the prime mover 104 via the shaft 105, and the drive sprocket 110 is also coupled to the chain 111. The chain 111 is also coupled to the carriage 113. In aspects, the chain 111 additionally may be coupled with a chain idler 112 that may be mounted to the housing 109 and configured to maintain a tension of the chain 111 to a setpoint tension. The carriage 113 may be connected to the chain 111 and to the counterweight assembly 114. In aspects, the carriage 113 is configured to allow a transverse movement of the chain 111 relative to the counterweight assembly 114. The counterweight assembly 114 is movable up and down within the housing 109 of the tower 102. In aspects, a weight of the counterweights may correspond to the weight of the rod string 126 and the weight of the fluid produced in a single stroke of the long-stroke pumping unit 100, such as being equal to a sum of the weight of the rod string 126 and one half the weight of the fluid produced in a single stroke.

[0034] The top 115 may be a frame structure that defines the top of the tower 102. The drum assembly 116 is coupled to the top 115 and may include a drum, a shaft, one or more ribs connecting the drum to the shaft, one or more pillow blocks mounted to the top 115, and one or more bearings configured to support the shaft while facilitating rotation of the shaft relative to the pillow blocks. The braking system 117 may be hydraulically, electrically, or pneumatically operated. The load belt 118 is a wide and flat belt that has a first end connected to a top of the weight box of the counterweight assembly 114 and a second end coupled to polished rod 125 of the wellhead 120 (e.g., via the hanger assembly 119). The load belt 118 may extend from the top of the counterweight assembly 114 upward through the housing 109 of the tower 102 and upward through the top 115, over an outer surface of the drum of the drum assembly 116, and downward from the drum assembly 116 to the hanger assembly 119. The hanger assembly 119 is connected to the polished rod 125 and to the load belt 118. In aspects, the hanger assembly 119 includes a dynamometer that is configured to send signals indicating a mechanical tension of the rod string 126 and a physical displacement of the rod string 126 to the control interface 106 and the controller 200.

[0035] In some aspects, the prime mover 104 may include an electric motor powered with electricity produced from a generator (powered by diesel or other hydrocarbon) or obtained from an electrical grid. Alternatively, the prime mover 104 may include an internal combustion engine fueled by a hydrocarbon fuel such as diesel or natural gas. In aspects where the prime mover 104 includes an electric motor, associated equipment such as an AC/DC converter for converting alternating current received from a power source to direct current for a direct-current electric motor may be included.

[0036] Rotation of the drive sprocket 110 drives the chain 111 in a loop around the drive sprocket 110 and an idler sprocket of the chain idler 112. The carriage 113 converts the movement of the chain 111 into a vertical (upward or downward) movement of the counterweight assembly 114 within the housing 109 of the tower 102. Vertical movement (upward and downward) of the counterweight assembly 114 causes the load belt 118 to move upward and downward, which moves the polished rod 125, the rod string 126, and the plunger 127 upward and downward in the production tubing 123. After downward movement (also called a downstroke) moving the plunger 127 to near the bottom of the wellbore 121 , the plunger 127 is pulled upward by the rod string 126, polished rod 125, hanger assembly 119, and load belt 118 to produce fluid via the hydrocarbon production line 124 in an upstroke.

[0037] The control interface 106 may be mounted to the base frame 101 or to the tower 102. The control interface 106 may be embodied in the same housing as the controller 200 as shown; alternatively, these components may be embodied in separate housings. The controller 200 may be coupled with the prime mover 104 and may have associated logic to control the rotational speed of the prime mover 104 via actuators, and thus the operating cycle speed of the downhole pump.

[0038] FIG. 2 illustrates a diagram of a controller 200 for a long-stroke pumping unit 100. Generally, where components of the technology described are implemented in whole or in part using software in one aspect, these software elements may be implemented to operate with a computing or processing component capable of carrying out the functionality described. The controller 200 shown in Figure 2 is thus an exemplary computing component that may represent multiple such components in practice. After reading this description, it will become apparent to a person skilled in the relevant art how to implement the technology using other computing components or architectures.

[0039] In aspects, the control interface 106 may include one or more virtual or physical buttons that control mechanical operation of the long-stroke pumping unit 100. In operations for pumping hydrocarbons, the control interface 106 and the controller 200 are used to control the prime mover 104, e.g., to rotate the drive sprocket 110 via the shaft 105 at a particular speed. In practice, the controller 200 is often configured to separately adjust a speed of the upstroke and a speed of the downstroke of the long-stroke pumping unit 100. In aspects, the controller 200 may be programmed to specifically manage a gas interference condition.

[0040] The controller 200 may carry out the functionality described herein. The controller 200 may represent, for example, computing or processing capabilities found within desktop, laptop and notebook computers, hand-held computing devices (personal digital assistants (PDAs), smart phones, cell phones, palmtops, etc.), mainframes, supercomputers, workstations or servers, or any other type of special-purpose computing devices as may be desirable or appropriate for a given application or environment. The controller 200 can also represent computing capabilities embedded within or otherwise available to a given device. For example, a computing component can be found in other electronic devices such as, for example, digital cameras, navigation systems, cellular telephones, portable computing devices, modems, routers, wireless application protocols (WAPs), terminals and other electronic devices that can include some form of processing capability.

[0041] The controller 200 can include, for example, one or more processors, controllers, control components, or other processing devices, such as a processor 204. Processor 204 can be implemented using a special-purpose processing engine such as, for example, a microprocessor, controller, or other control logic. In the illustrated example, processor 204 is connected to a bus 202, although any communication medium may be used to facilitate interaction with other components of the controller 200 or to communicate externally.

[0042] The controller 200 can also include one or more memory components, referred to herein as main memory 208. For example, random access memory (RAM) or other dynamic memory, can be used for storing information and instructions to be executed by processor 204. Main memory 208 can also be used for storing temporary variables or other intermediate information during execution of instructions to be executed by processor 204. The controller 200 can likewise include a read only memory (ROM) or other static storage device coupled to bus 202 for storing static information and instructions for processor 204.

[0043] The controller 200 can also include one or more various forms of information storage mechanism 210, which can include, for example, a media drive 212 and a storage unit interface 220. The media drive 212 can include a drive or other mechanism to support fixed or removable storage media 214. For example, a hard disk drive, a floppy disk drive, a magnetic tape drive, an optical disk drive, a compact disc (CD) or digital versatile disc (DVD) drive (read-only or read/write), or other removable or fixed media drive can be provided. Accordingly, storage media 214 can include, for example, a hard disk, a floppy disk, magnetic tape, cartridge, optical disk, a CD or DVD, or other fixed or removable medium that is read by, written to, or accessed by media drive 212. As these examples illustrate, the storage media 214 may include a computer usable storage medium having stored therein computer software or data.

[0044] In alternative aspects, information storage mechanism 210 can include other similar instrumentalities for allowing computer programs or other instructions or data to be loaded into the controller 200. Such instrumentalities can include, for example, a fixed or removable storage unit 222 and a storage unit interface 220. Examples of such storage units 222 and storage unit interfaces 220 may include a program cartridge and cartridge interface, a removable memory (for example, a flash memory or other removable memory component) and memory slot, a personal computer memory card international association (PCMCIA) slot and card, and other fixed or removable storage units 222 and storage unit interfaces 220 that allow software and data to be transferred from the storage unit 222 to the controller 200.

[0045] The controller 200 can also include a communications interface 224. Communications interface 224 can be used to allow software and data to be transferred between the controller 200 and external devices. Examples of communications interface 224 can include a modem or softmodem, a network interface (such as an Ethernet, network interface card, WiMedia, IEEE 802. XX or other interface), a communications port (such as for example, a USB port, IR port, RS232 port Bluetooth® interface, or other port), or other communications interface. Software and data transferred via communications interface 224 can be carried on signals, which may be electronic, electromagnetic (which includes optical) or other signals capable of being exchanged by a given communications interface 224. These signals can be provided to communications interface 224 via a channel 228. This channel 228 can carry signals and can be implemented using a wired or wireless communication medium. Some examples of a channel can include a phone line, a cellular link, an RF link, an optical link, a network interface, a local or wide area network, and other wired or wireless communications channels.

[0046] In this document, the terms “computer program medium” and “computer usable medium” are used to generally refer to media such as, for example, memory 208, storage unit interface 220, media 214, and channel 228. These and other various forms of computer program media or computer usable media may be involved in carrying one or more sequences of one or more instructions to a processing device for execution. Such instructions embodied on the medium, are generally referred to as “computer program code” or a “computer program product” (which may be grouped in the form of computer programs or other groupings). When executed, such instructions can enable the controller 200 to perform features or functions of the disclosed technology as discussed herein.

[0047] For example, the controller 200 may include one or more processors, memory, and instructions stored on the memory that cause the one or more processors to receive and analyze specific signals from one or more sensors such as the dynamometer (e.g., located in the hanger assembly 119) associated with operation of the long-stroke pumping unit 100. The sensors (e.g., the dynamometer, or other devices such as but not limited to a tachometer, an accelerometer, downhole instruments, or combinations thereof), yield sensor signals encoding values associated with the various parameters being measured. The sensors could, for example, provide data on the torque provided by the prime mover 104, or the electric current that produces that torque when the prime mover 104 is an electric motor. The controller 200 may display and store values with an associated time stamp.

[0048] The controller 200 may additionally output control signals that, via actuators, control of one or more pieces of the equipment of the long-stroke pumping unit 100. For example, the controller 200 may be networked with any of the sensors and actuators for programmatic control of the upstroke and downstroke of the long-stroke pumping unit 100 via wireless or wired data transmission networks (e.g., Wi-Fi, Bluetooth, NFC, Ethernet cables, or combinations thereof).

[0049] FIG. 3 illustrates a dynamometer card 300 analyzed by the controller 200 for a long-stroke pumping unit 100. The dynamometer card 300 is a graphical plot of the forces exerted on the rod string 126 (positive meaning upward) versus the displacement of the rod string 126 (positive meaning upward) throughout a full pump cycle. The operation of any given well may lead to a distinctive dynamometer card 300 signature.

[0050] The dynamometer generates data denoting the force on the rod string 126 and the displacement (e.g., upward and downward movement from a center position) of the rod string 126. During a pumping cycle, forces acting on the rod string 126 cause changes in the plunger 127 potentially thousands of feet down into the wellbore. In aspects, the rod string 126 can be elastic to some extent, and that various confounding frictional and viscous forces exist between the surface and downhole portions of the long-stroke pumping unit 100. However, for purposes of this disclosure, surface data from the dynamometer depicted in the dynamometer card 300 shown is treated as representing actual downhole pump conditions with manageable accuracy. The dynamometer card 300 values of pump force versus pump displacement tend to trace out a cyclical trajectory or pattern during pump operation, and this pattern may include a great deal of useful information.

[0051] For example, the lower left point 302 of the dynamometer card 300 generally corresponds to the start of the pump upstroke. In a well without a gas interference condition present, this point would correspond with a standing valve in the wellbore 121 and a traveling valve of the fully-submerged plunger 127 both being closed. The force on the rod string 126 may be negative at this point due to the buoyancy provided by the liquid in the wellbore 121 displaced by the plunger 127.

[0052] The top left point 304 of the dynamometer card 300 may correspond to the opening of the standing valve in the wellbore 121 during the upstroke. When the standing valve opens, fluid begins being drawn into the plunger 127. However, in a gas interference condition, gas will enter into the plunger 127 instead of liquid to some extent. As a result of this phenomenon and because of gas expansion, the plunger 127 may begin moving upward at a relatively reduced rod string 126 lifting force. Also, the liquid plunger load is not at its maximum, i.e., the liquid pump fillage is incomplete because gas is interfering with the process of liquid loading into the plunger 127. The pump is thus lifting less liquid than normal, which decreases production per pump stroke. The upstroke therefore shows more displacement along the left edge 306 of the dynamometer card 300 for given applied lifting forces than it otherwise would, leading to a more right-shifted and curved trajectory.

[0053] The upstroke continues toward the maximum upward displacement of the pump, represented at the upper right point 308 of the dynamometer card 300. This point may correspond to the closing of the standing valve in the wellbore 121 at the top of the upstroke. As noted, the lifting force may be less than normal at the top of the upstroke because the volume of the plunger 127 is comprised partly of gas in a gas interference scenario. The downstroke then begins.

[0054] As the rod string 126 forces the plunger 127 back down the wellbore 121 , it compresses the gas in the wellbore 121 beneath it. The right side 316 of the dynamometer card 300 trajectory is therefore more curved than normal as the card signature proceeds toward the bottom right corner, e.g., through points 310, 312, and to point 314. That is, the presence of gas in the wellbore 121 causes more left-shifted displacement in the right side 316 of the trajectory than would be the case were the gas interference condition not present and thus no gas compression were occurring. The bottom right point 314 of the card may correspond to the opening of the traveling valve in the plunger 127 during the downstroke, completing the pump cycle.

[0055] The difference in displacement between the lower left point 302 of the dynamometer card 300 and the lower right point 314 of the dynamometer card 300 may indicate how much liquid is actually in the plunger 127. The liquid pump fillage rate is related to the displacement between points 302 and 314 relative to the maximum possible displacement between points 302 and 318 (e.g., roughly 40 percent in this arbitrary example diagram). Knowledge of the liquid pump fillage rate value for each pump stroke is useful for several reasons. First, the liquid production rate of the well may be determined from liquid pump fillage rate data. Second, during the initial setup of the long- stroke pumping unit 100 it may be necessary to stop production periodically to allow more fluid to enter the wellbore 121 , or to initially set the normal speed of the long-stroke pumping unit 100 so that it does not pump more fluid than enters the wellbore 121 . The “normal” well pump speed may therefore refer to a specific pattern of upstrokes and downstrokes that has been selected to maximize the liquid pump fillage rate values in the absence of various abnormal conditions, including gas interference.

[0056] For this disclosure however, the liquid pump fillage rate data serves to indicate the possibility of gas interference in a well, as previously described. The controller 200 may process dynamometer card 300 data, estimate liquid pump fillage rates as described, and detect specific pump conditions including gas interference based on patterns observed in such indicative data. The controller may then responsively select specific and appropriate corrective actions to apply, via actuators, for specific downhole conditions accordingly.

[0057] The controller 200 repeatedly monitors the data sent from the dynamometer and/or other sensors during long-stroke pumping unit 100 operation. The data transmission from sensors and the monitoring by the controller 200 may each be continuous, periodic, or intermittent, or any combinations thereof. The controller 200 may observe the sensor data for a span of time (e.g., minutes or hours) or for a number of pump strokes to more clearly identify significant variances in pump data that may appear and disappear. If the monitored data becomes more erratic, i.e. , if variances of relevant measured or estimated parameters increase beyond a threshold or occur in a recognizable pattern, the controller 200 may responsively determine that a particular abnormal condition exists, including gas interference. Likewise, if variances decrease, the controller 200 may determine that abnormal conditions, including gas interference, do not exist.

[0058] For example, if a pattern of increased liquid pump fillage values is followed in time by a decrease in liquid pump fillage values and then by another increase in liquid pump fillage values, this pattern may clearly indicate that gas interference is occurring. A slug of gas may push more hydrocarbon liquid into the wellbore 121 as it moves toward the wellbore 121 , leading to the initial increase in liquid pump fillage observed. The gas slug may then make its own way into the wellbore 121 , causing the observed decrease in liquid pump fillage values due to gas interference. The long-stroke pumping unit 100 may then eventually clear out the gas, causing the observed liquid pump fillage values to increase again thereafter as regular liquid production resumes.

[0059] This pattern and others may repeat as multiple slugs of gas are emitted from the hydrocarbon-containing layer and move through the long-stroke pumping unit 100, particularly in wells having non-vertical components. Patterns of force and displacement corresponding to gas compression and gas expansion in the downhole pump, e.g., for gas interference as described, may also be recognized from patterns in dynamometer card 300 data. Such observed patterns may match patterns created by physics-based simulations, for example.

[0060] In one aspect, the controller 200 may evaluate the monitored data gathered during ten pump operating cycles to make a determination regarding data indicating operating conditions in the well. Other cycle counts may also be used, such as five to one hundred cycles, to ensure clear indications may be obtained. Various time-based durations of observation or numbers of pump cycles during which data is monitored and/or analyzed may lead to improved well performance.

[0061] Different wells and different production fields may behave differently, so the controller 200 may be programmed expressly to adapt its actions to the prevailing conditions rather than being locked into specific fixed control parameter values. The controller 200 may comprise an artificial intelligence or machine learning algorithm that is expressly designed and trained to manage gas interference and other specific production conditions determined to exist (or not exist) from specific analyses of observed operational well data. Various controllers 200 on various wells in one or more production fields may transmit their data to a central controller that monitors and/or controls production conditions remotely, such as via the internet.

[0062] In another aspect, the controller 200 may monitor sensor data to determine that an abnormal condition does not exist, or no longer exists if it once did. In such a case, the controller 200 may cancel whatever corrective actions it had taken in response to any previous abnormal condition, and return to normal operation. For example, if the corrective actions ordered are risky or expensive, the controller 200 may end the corrective actions immediately upon a determination that they are no longer needed, rather than monitoring sensor data for an extended period of time or number of pump cycles while the corrective actions remain ongoing. Likewise, the controller 200 or a number of such controllers may monitor and/or control a group of wells expressly to ascertain the behavior of different hydrocarbon-producing layers.

[0063] FIG. 4 illustrates the logic operations 400 performed by the controller 200 for a long-stroke pumping unit 100. The controller 200 generally implements a repeating control loop that does not end unless expressly halted by a user or unless an error condition arises. A user can halt well operations to conduct repairs or equipment upgrades, for example.

[0064] At 402, the controller 200 monitors data indicating liquid pump fillage values for the downhole pump. The data may comprise data from dynamometer and/or additional instruments. As previously noted, the controller 200 may monitor the data for a span of time or for a number of pump cycles.

[0065] At 404, the controller 200 determines if one or more patterns in the monitored data exist that indicate that a gas interference condition may exist in the downhole pump. Such patterns can comprise a significant increase in the variance of measured or estimated parameters describing downhole conditions, particularly variance of the liquid pump fillage values. In one aspect, the pattern comprises an increase, then a decrease, then another increase in the liquid pump fillage values over time. Downhole pump behavior generally becomes more erratic when gas interferes with regular liquid hydrocarbon production, but there is often variation within an individual well’s data, so it is the systematic change in variance that may be more indicative of problems that need corrective action. Pattern recognition algorithms may selectively identify portions of data useful for further analysis by an expert system for a particular operating condition, such as gas interference.

[0066] At 406, the controller 200 determines whether a gas interference condition exists or does not exist. The controller 200 programmatically evaluates the patterns in the monitored data to reach a determination that the gas interference condition does or does not exist. The controller 200 may use a trained machine learning or artificial intelligence algorithm to perform the evaluation of recognized patterns rather than a comparison of fixed threshold values for parameter variances. Such an algorithm may be trained by exposure to data from multiple wells that are experiencing gas interference and from multiple wells that are not experiencing gas interference. An artificial neural network can be a useful tool for implementation of such adaptive algorithms, and so may be part of the controller 200 logic circuitry or programming.

[0067] At 408, in response to determining that the gas interference condition exists, the controller 200 activates actuators that increase normal pump operation speed of the downhole pump to a higher speed. For a prime mover 104 powered by a hydrocarbon fuel, that activation may comprise adjusting a throttle to spin shaft 105 faster. For a prime mover 104 powered by electricity, the controller 200 may switch a multi-speed electric motor to a higher available speed. If the prime mover is a variable-frequency-drive type motor, the controller 200 may adjust the input frequency of drive signals to the motor such that its speed is increased.

[0068] At 410, in response to determining that the gas interference does not exist (including that the condition no longer exists if it previously did), the controller 200 activates actuators that cause a normal pump operation speed of the downhole pump to be applied (or resumed). The normal pump operation speed may refer to a pattern of upstrokes and downstrokes that have been found to optimize production in the absence of the gas interference condition. That is, normal operation may not be static but could be tuned to some extent by the controller 200 apart from the corrective action taken for managing the gas interference condition as described.

[0069] At 412, the controller 200 determines if a halt request has been received or if an error condition has occurred. If either is true, then the controller 200 may halt its usually-ongoing operation of the long-stroke pumping unit 100. If neither is true, then the controller 200 may resume its ongoing operation of the long-stroke pumping unit 100, including the detection and correction of gas interference conditions as they may occur.

[0070] As used herein, the term component can describe a given unit of functionality that may be performed in accordance with one or more aspects of the technology disclosed herein. As used herein, a component can be implemented utilizing any form of hardware, software, or a combination thereof. For example, one or more processors, controllers, ASICs, programmable logic arrays (PLAs), programmable array logics (PALs), complex programmable logic devices (CPLDs), FPGAs, logical components, software routines or other mechanisms can be implemented to make up a component. Hardware logic, including programmable logic for use with a programmable logic device (PLD) implementing all or part of the functionality previously described herein, may be designed using traditional manual methods or may be designed, captured, simulated, or documented electronically using various tools, such as Computer Aided Design (CAD) programs, a hardware description language (e.g., VHDL or AHDL), or a PLD programming language. Hardware logic may also be generated by a non-transitory computer-readable medium storing instructions that, when executed by a processor, manage parameters of a semiconductor component, a cell, a library of components, or a library of cells in electronic design automation (EDA) software to generate a manufacturable design for an integrated circuit. In implementation, the various components described herein can be implemented as discrete components or the functions and features described may be shared in part or in total among one or more components. In other words, the various features and functionality described herein may be implemented in any given application and may be implemented in one or more separate or shared components in various combinations and permutations. Even though various features or elements of functionality may be individually described or claimed as separate components, these features and functionality may be shared among one or more common software and hardware elements, and such description shall not require or imply that separate hardware or software components are used to implement such features or functionality.

[0071] Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions, and alterations may be made herein without departing from the scope of the disclosure as defined by the appended claims. Moreover, the scope of the present application is not intended to be limited to the particular aspects of the process, machine, manufacture, composition of matter, means, methods, and steps described in the specification. As can be appreciated from the disclosure, processes, machines, manufacture, compositions of matter, means, methods, or steps, presently existing or later to be developed that perform substantially the same function or achieve substantially the same result as the corresponding aspects described herein may be utilized according to the present disclosure. Accordingly, the appended claims are intended to include within their scope such processes, machines, manufacture, compositions of matter, means, methods, or steps.

[0072] While various aspects of the disclosed technology have been described above, it should be understood that they have been presented by way of example only, and not of limitation. Likewise, the various diagrams may depict an example architectural or other configuration for the disclosed technology, which is done to aid in understanding the features and functionality that may be included in the disclosed technology. The disclosed technology is not restricted to the illustrated example architectures or configurations, but the desired features may be implemented using a variety of alternative architectures and configurations. Indeed, with the aid of this disclosure it will be apparent to one of skill in the art how alternative functional, logical or physical partitioning and configurations may be implemented to implement the desired features of the technology disclosed herein. Also, a multitude of different constituent component names other than those depicted herein may be applied to the various partitions. Additionally, with regard to flow diagrams, operational descriptions and method claims, the order in which the steps are presented herein shall not mandate that various aspects be implemented to perform the recited functionality in the same order unless the context dictates otherwise.

ASPECTS

[0073] Aspect 1. A method for managing a gas interference condition in a downhole pump, comprising: monitoring, by a controller of the downhole pump, data indicating liquid pump fillage values for the downhole pump; determining, by the controller, one or more patterns in the monitored data indicating that the gas interference condition exists; and in response to determining that the gas interference condition exists, increasing, by the controller, a normal pump operation speed of the downhole pump to a higher speed.

[0074] Aspect 2. The method of Aspect 1 , further comprising: determining, by the controller, that the gas interference condition is no longer present in the downhole pump; and in response to determining that the gas interference condition is no longer present, resuming the normal pump operation speed for the downhole pump.

[0075] Aspect 3. The method of Aspect 1 or 2, wherein the downhole pump comprises a long-stroke pumping unit configured for liquid hydrocarbon production.

[0076] Aspect 4. The method of any one of Aspects 1 to 3, wherein the monitored data further comprises dynamometer data indicating pump force values versus pump displacement values.

[0077] Aspect 5. The method of any one of Aspects 1 to 4, wherein the determining further comprises identifying an increase in a variance of the liquid pump fillage values.

[0078] Aspect 6. The method of any one of Aspects 1 to 5, wherein the determining further comprises identifying an increase in the liquid pump fillage values followed by a decrease in the liquid pump fillage values followed by another increase in the liquid pump fillage values.

[0079] Aspect 7. The method of any one of Aspects 1 to 6, wherein the determining further comprises evaluating the monitored data during a number of pump operating cycles.

[0080] Aspect 8. The method of Aspect 7, wherein the determining further comprises evaluating the monitored data during ten pump operating cycles.

[0081] Aspect 9. The method of any one of Aspects 1 to 8, wherein the determined patterns correspond to gas compression and gas expansion in the downhole pump.

[0082] Aspect 10. The method of any one of Aspects 1 to 9, wherein the normal pump operation speed further comprises a rate of performing upstrokes and downstrokes that maximizes the liquid pump fillage values in an absence of the gas interference condition. [0083] Aspect 11. The method of any one of Aspects 1 to 10, wherein the increasing further comprises increasing a speed of a variable-frequency-drive electric motor that drives the downhole pump.

[0084] Aspect 12. A system for managing a gas interference condition in a downhole pump, comprising: a controller of the downhole pump that: monitors data indicating liquid pump fillage values for the downhole pump; determines one or more patterns in the monitored data indicating that the gas interference condition exists; and in response to determining that the gas interference condition exists, increases a normal pump operation speed of the downhole pump to a higher speed.

[0085] Aspect 13. The system of Aspect 12, wherein the downhole pump comprises a long-stroke pumping unit.

[0086] Aspect 14. A non-transitory computer-readable storage medium having embedded therein a set of instructions which, when executed by one or more processors of a computer, causes the computer to execute operations for managing a gas interference condition in a downhole pump, the operations comprising: monitoring data indicating liquid pump fillage values for the downhole pump; determining one or more patterns in the monitored data indicating that the gas interference condition exists; and in response to determining that the gas interference condition exists, increasing a normal pump operation speed of the downhole pump to a higher speed.

[0087] Aspect 15. The non-transitory computer-readable storage medium of Aspect 14, further comprising: determining that the gas interference condition is no longer present in the downhole pump; and in response to determining that the gas interference condition is no longer present, resuming the normal pump operation speed for the downhole pump.

[0088] Aspect 16. The non-transitory computer-readable storage medium of any one of Aspects 14 to 15, wherein the monitored data further comprises dynamometer data indicating pump force values versus pump displacement values.

[0089] Aspect 17. The non-transitory computer-readable storage medium of any one of Aspects 14 to 16, wherein the determining further comprises identifying an increase in a variance of the liquid pump fillage values.

[0090] Aspect 18. The non-transitory computer-readable storage medium of any one of Aspects 14 to 17, wherein the determining further comprises identifying an increase in the liquid pump fillage values followed by a decrease in the liquid pump fillage values followed by another increase in the liquid pump fillage values.

[0091] Aspect 19. The non-transitory computer-readable storage medium of any one of Aspects 14 to 18, wherein the determining further comprises evaluating the monitored data during a number of pump operating cycles.

[0092] Aspect 20. The non-transitory computer-readable storage medium of Aspect 19, wherein the determining further comprises evaluating the monitored data during ten pump operating cycles.

[0093] Aspect 21. The non-transitory computer-readable storage medium of any one of Aspects 14 to 20, wherein the determined patterns correspond to gas compression and gas expansion in the downhole pump.

[0094] Aspect 22. The non-transitory computer-readable storage medium of any one of Aspects 14 to 21 , wherein the normal pump operation speed further comprises a rate of performing upstrokes and downstrokes that maximizes the liquid pump fillage values in an absence of the gas interference condition.

[0095] Aspect 23. The non-transitory computer-readable storage medium of any one of Aspects 14 to 22, wherein the increasing further comprises increasing a speed of a variable-frequency-drive electric motor that drives the downhole pump.

[0096] Aspect 24. An apparatus for managing a gas interference condition in a downhole pump, comprising: a controller that performs operations comprising: monitoring data indicating liquid pump fillage values for the downhole pump; determining one or more patterns in the monitored data indicating that the gas interference condition exists; and in response to determining that the gas interference condition exists, increasing a normal pump operation speed of the downhole pump to a higher speed.

[0097] Aspect 25. The apparatus of Aspect 24, wherein the controller further: determines that the gas interference condition is no longer present in the downhole pump; and in response to determining that the gas interference condition is no longer present, resumes the normal pump operation speed for the downhole pump.

[0098] Aspect 26. The apparatus of Aspect 24 or 25, wherein the downhole pump comprises a long-stroke pumping unit.

[0099] Aspect 27. The apparatus of any one of Aspects 24 to 26, wherein the monitored data further comprises dynamometer data indicating pump force values versus pump displacement values.

[00100] Aspect 28. The apparatus of any one of Aspects 24 to 27, wherein the determining further comprises identifying an increase in a variance of the liquid pump fillage values.

[00101] Aspect 29. The apparatus of any one of Aspects 24 to 28, wherein the determining further comprises identifying an increase in the liquid pump fillage values followed by a decrease in the liquid pump fillage values followed by another increase in the liquid pump fillage values.

[00102] Aspect 30. The apparatus of any one of Aspects 24 to 29, wherein the determining further comprises evaluating the monitored data during a number of pump operating cycles.

[00103] Aspect 31. The apparatus of Aspect 30, wherein the determining further comprises evaluating the monitored data during ten pump operating cycles.

[00104] Aspect 32. The apparatus of any one of Aspects 24 to 31 , wherein the determined patterns correspond to gas compression and gas expansion in the downhole pump. [00105] Aspect 33. The apparatus of any one of Aspects 24 to 32, wherein the normal pump operation speed further comprises a rate of performing upstrokes and downstrokes that maximizes the liquid pump fillage values in an absence of the gas interference condition.

[00106] Aspect 34. The apparatus of any one of Aspects 24 to 33, wherein the increasing further comprises increasing a speed of a variable-frequency-drive electric motor that drives the downhole pump.

[00107] Aspect 35. The apparatus of any one of Aspects 24 to 34, further comprising a communications network operably linked to the controller.

[00108] Aspect 36. The apparatus of any one of Aspects 24 to 34, further comprising the downhole pump; a pump motor that actuates the downhole pump; a sensor that generates the data.

[00109] Aspect 37. A method comprising: controlling, by a controller of a long-stroke pumping unit, a stroke speed of a plunger upwards and downwards in a wellbore to a first value to produce one or more liquid hydrocarbons from the wellbore, wherein the plunger is coupled to a surface unit of the long-stroke pumping unit via a rod string; detecting, by a sensor of the long-stroke pumping unit, that a gas interference condition is present in the wellbore; and in response to detecting the gas interference condition, changing, by the controller, the stroke speed of the plunger upwards and downwards in the wellbore to a second value, wherein the second value is greater than the first value.

[00110] Aspect 38. The method of Aspect 37, further comprising: detecting, by the sensor of the long-stroke pumping unit, that the gas interference condition is no longer present in the wellbore; and in response to detecting that the gas interference condition is no longer present in the wellbore, changing, by the controller, the stroke speed of the plunger to the first value.

[00111] Aspect 39. The method of Aspect 37 or 38, further comprising: determining, by the controller, that the plunger has experienced a predetermined number of strokes in the wellbore at the second value for the stroke speed; and in response to the determining, changing, by the controller, the stroke speed of the plunger to the first value.

[00112] Although the disclosed technology is described above in terms of various exemplary aspects and implementations, it should be understood that the various features, aspects and functionality described in one or more of the individual aspects are not limited in their applicability to the particular aspect with which they are described, but instead may be applied, alone or in various combinations, to one or more of the other aspects of the disclosed technology, whether or not such aspects are described and whether or not such features are presented as being a part of a described aspect. Thus, the breadth and scope of the technology disclosed herein should not be limited by any of the above-described exemplary aspects.

Claims

CLAIMS What is claimed is:

1 . A method for managing a gas interference condition in a downhole pump, comprising: monitoring, by a controller of the downhole pump, data indicating liquid pump fillage values for the downhole pump; determining, by the controller, one or more patterns in the monitored data indicating that the gas interference condition exists; and in response to determining that the gas interference condition exists, increasing, by the controller, a normal pump operation speed of the downhole pump to a higher speed.

2. The method of claim 1 , further comprising: determining, by the controller, that the gas interference condition is no longer present in the downhole pump; and in response to determining that the gas interference condition is no longer present, resuming the normal pump operation speed for the downhole pump.

3. The method of claim 1 , wherein the downhole pump comprises a long-stroke pumping unit configured for liquid hydrocarbon production.

4. The method of claim 1 , wherein the monitored data further comprises dynamometer data indicating pump force values versus pump displacement values.

5. The method of claim 1 , wherein the determining further comprises identifying an increase in a variance of the liquid pump fillage values.

6. The method of claim 1 , wherein the determining further comprises identifying an increase in the liquid pump fillage values followed by a decrease in the liquid pump fillage values followed by another increase in the liquid pump fillage values.

7. The method of claim 1 , wherein the determining further comprises evaluating the monitored data during a number of pump operating cycles.

8. The method of claim 7, wherein the determining further comprises evaluating the monitored data during ten pump operating cycles.

9. The method of claim 1 , wherein the determined patterns correspond to gas compression and gas expansion in the downhole pump.

10. The method of claim 1 , wherein the normal pump operation speed further comprises a rate of performing upstrokes and downstrokes that maximizes the liquid pump fillage values in an absence of the gas interference condition.

11 . The method of claim 1 , wherein the increasing further comprises increasing a speed of a variable-frequency-drive electric motor that drives the downhole pump.

12. A system for managing a gas interference condition in a downhole pump, comprising: a controller of the downhole pump that: monitors data indicating liquid pump fillage values for the downhole pump; determines one or more patterns in the monitored data indicating that the gas interference condition exists; and in response to determining that the gas interference condition exists, increases a normal pump operation speed of the downhole pump to a higher speed.

13. The system of claim 12, wherein the downhole pump comprises a long-stroke pumping unit.

14. A non-transitory computer-readable storage medium having embedded therein a set of instructions which, when executed by one or more processors of a computer, causes the computer to execute operations for managing a gas interference condition in a downhole pump, the operations comprising: monitoring data indicating liquid pump fillage values for the downhole pump; determining one or more patterns in the monitored data indicating that the gas interference condition exists; and in response to determining that the gas interference condition exists, increasing a normal pump operation speed of the downhole pump to a higher speed.

15. The non-transitory computer-readable storage medium of claim 14, further comprising: determining that the gas interference condition is no longer present in the downhole pump; and in response to determining that the gas interference condition is no longer present, resuming the normal pump operation speed for the downhole pump.

16. The non-transitory computer-readable storage medium of claim 14, wherein the monitored data further comprises dynamometer data indicating pump force values versus pump displacement values.

17. The non-transitory computer-readable storage medium of claim 14, wherein the determining further comprises identifying an increase in a variance of the liquid pump fillage values.

18. The non-transitory computer-readable storage medium of claim 14, wherein the determining further comprises identifying an increase in the liquid pump fillage values followed by a decrease in the liquid pump fillage values followed by another increase in the liquid pump fillage values.

19. The non-transitory computer-readable storage medium of claim 14, wherein the determining further comprises evaluating the monitored data during a number of pump operating cycles.

20. The non-transitory computer-readable storage medium of claim 19, wherein the determining further comprises evaluating the monitored data during ten pump operating cycles.

21. The non-transitory computer-readable storage medium of claim 14, wherein the determined patterns correspond to gas compression and gas expansion in the downhole pump.

22. The non-transitory computer-readable storage medium of claim 14, wherein the normal pump operation speed further comprises a rate of performing upstrokes and downstrokes that maximizes the liquid pump fillage values in an absence of the gas interference condition.

23. The non-transitory computer-readable storage medium of claim 14, wherein the increasing further comprises increasing a speed of a variable-frequency-drive electric motor that drives the downhole pump.

24. An apparatus for managing a gas interference condition in a downhole pump, comprising: a controller that performs operations comprising: monitoring data indicating liquid pump fillage values for the downhole pump; determining one or more patterns in the monitored data indicating that the gas interference condition exists; and in response to determining that the gas interference condition exists, increasing a normal pump operation speed of the downhole pump to a higher speed.

25. The apparatus of claim 24, wherein the controller further: determines that the gas interference condition is no longer present in the downhole pump; and in response to determining that the gas interference condition is no longer present, resumes the normal pump operation speed for the downhole pump.

26. The apparatus of claim 24, wherein the downhole pump comprises a long-stroke pumping unit.

27. The apparatus of claim 24, wherein the monitored data further comprises dynamometer data indicating pump force values versus pump displacement values.

28. The apparatus of claim 24, wherein the determining further comprises identifying an increase in a variance of the liquid pump fillage values.

29. The apparatus of claim 24, wherein the determining further comprises identifying an increase in the liquid pump fillage values followed by a decrease in the liquid pump fillage values followed by another increase in the liquid pump fillage values.

30. The apparatus of claim 24, wherein the determining further comprises evaluating the monitored data during a number of pump operating cycles.

31 . The apparatus of claim 30, wherein the determining further comprises evaluating the monitored data during ten pump operating cycles.

32. The apparatus of claim 24, wherein the determined patterns correspond to gas compression and gas expansion in the downhole pump.

33. The apparatus of claim 24, wherein the normal pump operation speed further comprises a rate of performing upstrokes and downstrokes that maximizes the liquid pump fillage values in an absence of the gas interference condition.

34. The apparatus of claim 24, wherein the increasing further comprises increasing a speed of a variable-frequency-drive electric motor that drives the downhole pump.

35. The apparatus of claim 24, further comprising a communications network operably linked to the controller.

36. The apparatus of claim 24, further comprising: the downhole pump; a pump motor that actuates the downhole pump; and a sensor that generates the data.

37. A method comprising: controlling, by a controller of a long-stroke pumping unit, a stroke speed of a plunger upwards and downwards in a wellbore to a first value to produce one or more liquid hydrocarbons from the wellbore, wherein the plunger is coupled to a surface unit of the long-stroke pumping unit via a rod string; detecting, by a sensor of the long-stroke pumping unit, that a gas interference condition is present in the wellbore; and in response to detecting the gas interference condition, changing, by the controller, the stroke speed of the plunger upwards and downwards in the wellbore to a second value, wherein the second value is greater than the first value.

38. The method of claim 37, further comprising: detecting, by the sensor of the long-stroke pumping unit, that the gas interference condition is no longer present in the wellbore; and in response to detecting that the gas interference condition is no longer present in the wellbore, changing, by the controller, the stroke speed of the plunger to the first value.

39. The method of claim 37, further comprising: determining, by the controller, that the plunger has experienced a predetermined number of strokes in the wellbore at the second value for the stroke speed; and in response to the determining, changing, by the controller, the stroke speed of the plunger to the first value.