CONTROLLER AND METHODS FOR CONTROLLING RECIPROCATING DOWNHOLE PUMP

Description

CROSS-REFERENCE TO RELATED APPLICATION(S)

This application claims the priority benefit of Canadian Application No. 3,251,539, filed Oct. 31, 2024, which is incorporated herein by reference in its entirety for all purposes.

FIELD OF THE DISCLOSURE

The present disclosure relates to artificial lift systems such as reciprocating pumps for lifting fluids from a wellbore. More particularly, the present disclosure relates to methods and systems for controlling operation of a reciprocating pump.

BACKGROUND

In hydrocarbon recovery operations, an artificial lift system is typically used to recover fluids from a well in a subterranean earth formation. Common artificial lift systems include reciprocating pumps such as sucker rod pumps. The pump may generally comprise a plunger disposed within a barrel and a valve system. The plunger is moved up and down within the barrel in order to draw fluids to the surface. More particularly, the plunger may be coupled to a lower end of a reciprocating rod or rod string.

Various factors may affect efficiency and production rate of an artificial lift system. In addition to mechanical characteristics of the artificial lift system, characteristics of the fluids within the wellbore affect pumping efficiency. Incomplete pump fillage, due to excess gas in the fluid and/or low liquid level may reduce pumping efficiency, for example. Too much gas entering the pump can result in pump gas lock, pump damage or other loss of efficiency issues. It may be desirable to pump at a rate at that is similar to the rate of liquid inflow of fluid into the wellbore. Although, pumping at a rate similar to the rate of liquid inflow into the wellbore can be challenging. Challenges arise when the liquid inflow or the liquid rate encountered at the pump may be variable and constantly changing due to multiphase flow conditions and in particular slug flow conditions of liquid and gas emanating from the wellbore below the pump's depth.

Since gas in a pump affects the pump's fillage and efficiency, rod pump controllers are commonly used to adjust the speed or stroke rate of the pump to compensation for gas in the pump. The control logic used for changing speed can be complex due to the complexities of multiphase flows emanating from the wellbore below a pump.

In a typical well fluid recovery operation, an artificial lift system may pump fluids from the well to the surface using a reciprocating downhole pump. This type of fluid recovery operation may be referred to as a “pumping operation” herein. The pumping speed may be controlled by an operator during the pumping operation. For example, if pumping efficiency drops, pumping speed may be reduced. In a typical operation, speed may be reduced at a rate of 10% or more per stroke. If well conditions improve, speed may be increased by the operator at a similar rate. However, typical rates of speed adjustment may cause pump operation instability. Additionally, an operator controlling a well pumping operation may misinterpret sensor measurements or other well condition indicators and unnecessarily reduce pumping speed. There is a need for improved methods of controlling artificial lift systems.

SUMMARY

According to an aspect, there if provided a method of operating an artificial lift system producing fluid from a wellbore, the artificial lift system comprising a reciprocating downhole pump, the method comprising: controlling a pumping speed of the reciprocating downhole pump as a function of a set of operational parameters, the set of operational parameters comprising a pumping speed setpoint and a pumping speed rate of change, wherein controlling the pumping speed comprises: setting the pumping speed setpoint; and adjusting the pumping speed toward the pumping speed setpoint at the pumping speed rate of change, wherein the pumping speed rate of change comprises less than 1% per stroke.

In some embodiments, the pumping speed rate of change is between 0.1% and 0.5% per stroke, such as between 0.1% and 0.3%.

In some embodiments, the pumping speed rate of change is less that 0.1% per stroke.

According to another aspect, there is provided a method of operating an artificial lift system producing fluid from a wellbore, the artificial lift system comprising a reciprocating downhole pump, the method comprising: monitoring one or more properties indicative of a fluid level characteristic of the wellbore; selecting a set of operational parameters for the pump at least partly based on the monitored one or more properties indicative of the fluid level characteristic, wherein the set of operational parameters comprises pump operation setpoints and rules for automatically adjusting one or more of the pump operation setpoints, the pump operation setpoints comprising: a respective upper pumping speed limit; a respective lower pumping speed limit; and a respective pumping speed rate of change; and controlling operation of the pump as a function of the set of operational parameters.

In some embodiments, the set of operational parameters further comprises rules for adjusting one or more of the setpoints.

In some embodiments, the set of operational parameters further comprises one or more setpoints controlling a shutdown cycle and rules for adjusting at least one of the one or more setpoints controlling the shutdown cycle.

In some embodiments, the method further comprises determining that a fluid level in the wellbore is above a threshold and, responsive to a drop in production rate while the fluid level is above the threshold, raising the lower speed limit or the upper speed limit.

In some embodiments, after raising the lower or upper speed limit, the lower pumping speed limit is at least 70% of the upper pumping speed limit.

In some embodiments, the method further comprises detecting a pumping condition, wherein controlling the pumping speed comprises setting the pumping speed setpoint to the lower pumping speed limit responsive to the detecting the pumping condition.

In some embodiments, the pumping condition comprises at least one of: a pump production rate drop; or pump instability.

In some embodiments, the method further comprises: monitoring pump operation after setting the pumping speed setpoint to the lower pumping speed limit; if a pump efficiency exceeds an efficiency threshold for a predetermined period, increasing the pumping speed setpoint; and if the pump efficiency does not exceed the efficiency threshold for the predetermined period, maintaining the pumping speed setpoint or lowering the lower pumping speed limit.

In some embodiments, the method further comprises, after setting the pumping speed setpoint to the lower pumping speed limit, increasing casing pressure.

According to another aspect, there is provided a method of operating an artificial lift system producing fluid from a wellbore, the artificial lift system comprising a reciprocating downhole pump, the method comprising: obtaining sensor measurements and determining, from the sensor measurements, at least one property indicative of a fluid level characteristic of the wellbore; selecting, as a function of the at least one property, one of a plurality of modes of operation, each mode of operation comprising a respective set of operational parameters for controlling operation of the reciprocating downhole pump, wherein each set of operational parameters comprises pump operation setpoints and rules for automatically adjusting one or more of the pump operation setpoints, pump operation setpoints comprising: a respective upper pumping speed limit; a respective lower pumping speed limit; a respective pumping speed rate of change.

In some embodiments, the respective pumping speed rate change is less than 1% per stroke.

In some embodiments, the sensor measurements include rod weight measurements and the one or more properties comprises one or more of: pump fillage; fluid load; pump intake pressure; and production rate.

In some embodiments, the fluid level characteristic comprises an estimated Gas Free Liquid Above Pump (GFLAP) level.

In some embodiments, the plurality of modes of operation comprises at least: a first mode of operation associated with a first estimated fluid level range; and a second mode of operation associated with a second estimated fluid level range lower than the first estimated fluid level range.

In some embodiments, for the second mode of operation, the rules for automatically adjusting one or more of the pump operation setpoints comprise a number of shut down cycles triggered over a time period.

In some embodiments, the plurality of modes of operation further comprises a third mode of operation associated with a third estimated fluid level range lower than the second estimated fluid level range.

According to another aspect, there is provided a controller for an artificial lift system that produces fluid from a wellbore, the artificial lift system comprising a reciprocating pump, the controller comprising: a processor; memory having processor-executable instructions stored thereon that, when executed cause the processor to implement one or more of the methods described herein.

Other aspects and features of the present disclosure will become apparent, to those ordinarily skilled in the art, upon review of the following description of the specific embodiments of the disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure will be better understood having regard to the drawings in which:

FIG. 1 is an illustration of a system according to some embodiments;

FIG. 2 is an enlarged partial view of the system of FIG. 1 showing a pump assembly in a wellbore;

FIG. 3 is a flowchart of an example method of operating a reciprocating downhole pump for producing fluid from a wellbore according to some embodiments;

FIG. 4 is a flowchart of another example method of operating a reciprocating downhole pump for producing fluid from a wellbore according to some embodiments;

FIG. 5 is a flowchart of another example method of operating a reciprocating downhole pump for producing fluid from a wellbore according to some embodiments;

FIG. 6 is a functional block diagram of a controller, pump drive and

sensors of FIG. 1 according to some embodiments; and

FIGS. 7A and 7B show examples of potential monitored properties and operational parameters for a hypothetical well pumping operation.

DETAILED DESCRIPTION

Operators in conventional reciprocating pump operations may increase and/or decrease pumping speed at a rate of 10% per stroke or more in response to various measured properties of the pump and/or detected conditions. However, these typical rates of changing speed may cause unnecessary pump instability, worsen multiphase flow instabilities within a wellbore below the pump and/or overcompensate for a detected condition. Thus, according to some embodiments described herein, the rate of changing pumping speed is slower than conventional methods, which may be beneficial to pump stability, reduction of multiphase flow in the wellbore instabilities and pump efficiency. For example, the rate of change may be 1-3% per stroke or more, or less than 1%. For a speed decrease rate of 1% per stroke, the speed decreases by 1% for each stroke of the pump. The rate of change may be less than 1% per stroke. For example, the rate may be 0.1% to 0.9%. The rate of change may be less than 0.1% per stroke. Other examples are described herein. Rates of change of pumping speed that are slower than conventional rates may improve production and/or stability of the reciprocating pump and the pumping operation. Rates of change may also be provided as an amount of SPM change per stroke (e.g. 0.1 SPM change per stroke). The setpoints for speed rate of change need not be set as an actual percentage and may be set as an amount of SPM change per stroke. The approximate percentages provided herein are examples.

Furthermore, one or more properties or conditions that may traditionally cause an operator or controller to slow pumping speed may potentially be ignored without negatively impacting pumping efficiency when the well still has sufficient fluid therein (e.g. gas free liquid above pump (GFLAP) is above a threshold). According to some embodiments of the present disclosure, higher production levels may be maintained until sensor measurements indicate that the GFLAP level has fallen below a threshold. In some embodiments, the operational parameters (e.g. setpoints) utilized by a controller may be selected as a function of estimated GFLAP and/or other measured properties that are indicative of a fluid level characteristic in the well. In some embodiments, a pumping operation may have multiple “stages” or “phases”, each corresponding to a respective estimated annular fluid level range (e.g. GFLAP range). Each stage may have a respective set of operational parameters for the reciprocating pump. These and other principles discussed below may be implemented by a computerized controller that may automatically or semi-automatically control operation of the pump.

FIG. 1 is an illustration of a system 100 according to some embodiments. The system 100 includes a reciprocating pump 102 for producing fluids from a wellbore 101 in an earth formation 111. The reciprocating pump 102 comprises a pump drive 103 connected to a downhole pump assembly 104 by a sucker rod string 114. The pump drive 103 may comprise a “pumpjack” as shown in FIG. 1A, but other types of pump drives for reciprocating pumps may be used in other embodiments.

FIG. 2 is an enlarged partial view of the system 100 showing the tubing 105 and downhole pump assembly 104 within the wellbore 101. Elements in FIGS. 1 and 2 are not shown to scale or are shown as simplified representations for illustrative purposes. The pump assembly 104 includes a barrel 106 positioned in or below the tubing 105, and a plunger 107 within the barrel 106. A standing valve 108 is positioned at the bottom of the barrel 106, and a travelling valve 110 is positioned at the bottom of the plunger 107. The travelling valve 110 reciprocates with the plunger 107, while the standing valve 110 is essentially stationary.

On the “downstroke”, pressure differentials may close the standing valve 108 and open the travelling valve 110. Fluids in the barrel 106 may thereby pass upward through the travelling valve 110 and plunger 107 during the downstroke. On the “upstroke”, reversed pressure differentials may close the travelling valve 110 and open the standing valve 108. Fluids above the travelling valve 108 may be moved upward by motion of the plunger 107, and fluids from the earth formation 111 or reservoir may enter the barrel 106 via the standing valve 108. The plunger 107 is coupled to the sucker rod string 114, which is in turn coupled to the pump drive 103 at the surface.

Fluid within the wellbore may have a liquid level 112 (with gas “G” above and liquid “L” or a mix or liquid and gas below). The liquid level 112 may be measured as a distance from the well to the liquid level 112 above. Since gas typically forms within the liquid, particularly as pressure decreases with decreasing pressure, an amount of gas 113 will be mixed with the liquid below the liquid level 112 (gas/liquid interface level). The term Gas Free Liquid Above Pump (GFLAP) refers to the distance from the pump to where the liquid level would be if all gas 113 within the liquid was removed.

To help mitigate or prevent stretching of the tubing 105 during the downstroke, a tubing anchor (or “TAC”) 116 may be installed proximate the pump or bottom of the tubing 105. The TAC 116 may, thereby, improve pump efficiency.

Turning again to FIG. 1, the system 100 further includes a controller 120 and one or more sensors 122. The controller 120 is operable to control operation of the reciprocating pump drive 103. More particularly, the controller 120 is operable to control pumping speed (e.g. strokes per minute). The controller 120 may also control shut down cycles of reciprocating pump drive 103. Controlling the pump drive 103 may comprise generating control signaling or other output, by the controller 120, that controls the speed or other operation of the pump 102. The controller 120 may also be operable to control other surface equipment (not shown), such as valves for controlling casing pressure, tubing pressure, equipment, computer devices for user interface functions, database(s) storing data about the present or other well operations, equipment for fluid injection and/or other equipment, to name a few examples.

The controller 120 may receive, as input, output from the one or more sensors 122. The sensor(s) 122 may be coupled to the reciprocating pump 102 (e.g. to the drive 103) and/or to other surface equipment and are operable to take measurements of one or more properties that may be indicative of a fluid level characteristic of the wellbore 101. The sensor(s) 122 may measure one or more characteristics of the pump 102 and/or operation thereof. The sensor(s) 122 may include one or more of the following: one or more weight sensors arranged to detect weight of the sucker rod at surface; one or more pressure sensors arranged to measure pump intake pressure, casing pressure and/or tubing pressure; one or more fluid level sensors; and/or other type(s) of sensor. The sensor(s) 122 may also measure production of fluids (gas and liquid). The controller 120 may also calculate “inferred” production rates of liquid based on sensor measurements, such as estimated pump fillage based on rod weight measurements, and pumping speed. The controller 120 may implement one or more of the methods described herein for controlling operation of the pump 102.

FIG. 3 is a flowchart of an example method 300 of operating a reciprocating downhole pump for producing fluid from a wellbore according to some embodiments. The method may be performed by the controller 120 of FIG. 1. For example, the controller 120 may control the pump 102 of FIG. 1 using the method 300.

At step 302, the controller 120 controls a pumping speed of the reciprocating downhole pump as a function of a set of operational parameters. The operational parameters may comprise settings or “setpoints” for operation of the pump 102 and may also include rules or conditions for adjusting one or more of the setpoints. The setpoints may include operational settings (e.g. pumping speed) and/or one or more thresholds or other factors considered by the rules. In this embodiment, the set of operational parameters comprises a pumping speed setpoint and a pumping speed rate of change. The set of operational parameters may further comprise an upper pumping speed limit and/or a lower pumping speed limit. The set of operational parameters may further include rules for automatically increasing and/or decreasing pumping speed. In this example, step 302 comprises: (a) at substep 302a, setting the pumping speed setpoint; and (b) at substep 302b, adjusting the pumping speed toward the pumping speed setpoint at the pumping speed rate of change.

The pumping speed may be defined as Strokes per Minute (SPM). The pumping speed rate of change may be from 1-3% or more change in speed per stroke. The rate of change may be less than 1% per stroke. For example, the rate of change may be between 0.1% and 0.9% per stroke. The rate of change may be between 0.1% and 0.5% per stroke. The rate of change may be between 0.1% and 0.3% per stroke. The rate of change may also be less than 0.1% or more than 3%. In these ranges, the speed rate of change may be significantly slower than rates utilized in conventional well operations. As noted above, these slower rates of change may improve stability in a well. Slower rates of change of pump speed may allow for the multiphase flow condition in the wellbore below the pump to respond. The capacity of the wellbore below the pump may act as an accumulator of gas and liquid. Gas is highly compressible and therefore the multiphase flow response from a pump speed change may be highly dampened or muted for a period of time. Slowing down the rate of speed change may allow for the multiphase flow in the wellbore below the pump to respond to the change, and may allow for the change to become observable at the pump and therefore next rate of speed changes can be more effectively made or controlled with the feedback received from such a response. If the rate of change of speed to too rapid, the response may become an unstable feedback response and therefore results in a unstable feedback control system, which may be incontrollable by a controller.

As noted above, the set of operational parameters may include one or more rules for automatically increasing and automatically decreasing pumping speed (i.e. changing the pumping speed setpoint). For example, the rules may include one or more thresholds for raising and/or lowering pumping speed. The set of operational parameters may also include rules for adjusting the upper and/or lower speed limits and/or adjusting the speed rate of change. One or more of measured properties may be compared to the one or more thresholds to determine whether the pumping speed setpoint should be increased or decreased, and the speed may then be adjusted toward the new pumping speed setpoint as a function of the speed rate of change. The set of operational parameters may further include rules for automatically adjusting the upper and lower speed limits. Some specific rules for automatically adjusting pumping speed are described below.

The set of operational parameters may further include shutdown cycle parameters, including but not limited to: shutdown cycle triggering condition(s); shutdown time, etc. An example shutdown cycle condition includes incomplete pump fillage percentage below a shutdown threshold over a predetermined number of consecutive strokes. A shutdown cycle may allow the well to refill with fluids so that pumping may be resumed with more stable efficiency.

The rules for adjusting the pumping speed setpoint, upper and lower speed limits, and/or the shutdown cycle parameters may include one or more pump fillage or pump efficiency thresholds. For example, the set of operational parameters may include one or more of: a first pump fillage threshold; a second pump fillage threshold, lower than the first pump fillage threshold. Each pump fillage threshold may have an associated “consecutive stroke” setpoint, which defines the number of strokes that the threshold condition must be met to trigger an action such as a speed adjustment or shutdown cycle. Another minimum period, such as a time period, may be used rather than number of strokes in other embodiments.

The first pump fillage threshold may be used for adjusting the pumping speed. If pump fillage falls below the first pump fillage threshold for the associated number of consecutive strokes, the pumping speed setpoint may be decreased. When pump fillage is above the first pump fillage threshold, the pumping speed setpoint may be increased.

The second pump fillage threshold (lower than the first threshold) may function as a shutdown trigger. The second second pump fillage threshold may be referred to as a “shutdown threshold”. If pump fillage falls below the second pump fillage threshold for the associated number of consecutive strokes, for example, then the pump may automatically initiate a shutdown cycle.

As discussed above, the set of operational parameters may further comprise an upper pumping speed limit; and a lower pumping speed limit. The method may further include adjusting one or both of the upper and lower speed limits. For example, the controller 120 may determine that the allowable pumping speed range should be reduced or increased. For example, when the well fluid level (e.g. GFLAP level) is sufficiently high, speed may be increased and/or the range between upper and lower speed limits may be decreased to help pump off gas and potentially stabilize the well. When the well fluid level (e.g. GFLAP level) is lower, speed and/or the lower speed limit may be decreased to allow the well to recover.

FIG. 4 is a flowchart of an example method 400 of operating a reciprocating downhole pump for producing fluid from a wellbore according to some embodiments. The method may be performed by the controller 120 of FIG. 1. For example, the controller 120 may control the pump 102 of FIG. 1 using the method 400.

At step 402, one or more properties of operation of the pump are monitored by the controller 120. Monitoring the one or more properties may include obtaining measurements from the one or more sensors 122. The one or more properties may include, but are not limited to: pump fillage; fluid load; pump intake pressure; inferred production; casing pressure; and/or tubing pressure. Monitoring the one or more properties may also include receiving data indicating one or more of the one or more properties from another device, such as other surface equipment.

At step 404, a pumping condition is detected based at least partly on the one or more properties monitored in step 402. The pumping condition may be a pump production drop or pump instability. For example, the pump production drop may comprise low inferred production (e.g., reduced pumping efficiency/fillage being under a threshold) over a given period such as a number of strokes. The pump instability may comprise erratic pump fillage or production (e.g. rapid changes in efficiency or inferred production) over time. By way of example only, an average production reduction of 20% to 30% or more may be considered a sufficient drop for step 404. Embodiments are not limited to a particular percentage production drop, as the amount or production drop or swing that triggers step 406 below may vary depending on well characteristics, equipment characteristics, and other factors. Other examples of conditions that indicate a reduced production condition and/or instable pump condition include: number of shutdown cycles triggered over a time period exceeding a threshold; or peak load on the pump exceeding a threshold. Excessive peak load, for example, could indicate that fluid levels in the well have dropped and are negatively impacting pump operation. In such cases, slowing or pausing pumping may allow the well to recover may lower the peak load and/or be otherwise beneficial to well operation and stability.

In step 406, the controller 120 controls a pumping speed as a function of a set of operational parameters and the monitored one or more properties of the downhole pumping operation. In this example, the pumping speed is controlled at least partly based on the detected well or pumping condition. More specifically, in this example, at step 406, the controller 120 lowers the pumping speed setpoint responsive to the condition detected in step 404. For example, the pumping speed may be set to the lower pumping speed limit responsive to the detecting the pumping condition. The lower pumping speed limit may also be reduced. For example, if the upper and lower pumping limits had previously been 8 SPM and 6 SPM respectively, the lower pumping speed limit may be reduced to 5 SPM, 4 SPM, 3 SPM or lower. The upper pumping speed limit may likewise be reduced (e.g. 7 SPM, 6 SPM, 5 SPM or lower). The range between the upper and lower SPM limits may also be reduced. The pumping speed may decrease to the new setpoint at a rate of change of 3% or less (e.g. 1% or less, such as 0.1 to 1%).

The difference between the upper and lower speed limits may, for example, be between 25% and 75% of the upper SPM limit. For example, the lower speed limit may be at least 30% of the upper speed limit. The lower speed limit may be at least 50% or at least 70% of the upper speed limit. By way of example, in the case of an upper limit of 8 SPM, the lower limit may be 3 PM, 4 SPM, 5 SPM or 6 SPM. Embodiments are not limited to these ranges between the upper and lower speed limits.

Optionally, at block 408, casing pressure may be increased. Casing pressure may increased from the facilities line pressure (e.g. 120 psi) to 300 psi for example. Casing pressure may be controlled at surface by closing one or more valves, by injecting fluid into the well, and/or any other suitable means. Increasing casing pressure may help stabilize the well. Increased casing pressure may push the annular fluid level down deeper while increasing the gas column above the annular fluid level. This increased gas column in the anulus may provide a greater dampening of multiphase flow and therefore stabilization of the well.

At step 410, the lower speed, and possibly the increased casing pressure, may be maintained for at least a designated period of time and/or until a pump stability condition is achieved. Determining whether a pump stability condition has been achieved may include monitoring output from the one or more sensors 122. For example, the stability condition may comprise pump efficiency (e.g. pump fillage) meeting or exceeding an efficiency threshold for a predetermined period. As another example, the stability condition may comprise inferred production meeting or exceeding a threshold for the predetermined period. One or more different indicators of pump stability may also be monitored to determine whether the stability condition has been met. By way of example, the efficiency threshold may be a pump fillage of at least 50%, at least 55%, at least 60%, at least 65% or at least 70%. In one embodiment, the threshold is at least 60% pump fillage over the predetermined period. The predetermined period may be a minimum number of strokes, such as at least 5 strokes, at least 10 strokes, at least 15 strokes, or more. The specific efficiency threshold and number of strokes may vary. The pump efficiency and predetermined period threshold may be selected to allow the well to settle and for additional fluid to enter the well from the surrounding earth formation. Other indicators of pump stability may also be monitored and used to determine whether the pump stability condition has been met. The time required to meet the pump stability condition may vary, but as an example may be days or weeks.

At step 412, in response to the stability condition being met or casing pressure maintained for the predetermined period in step 410, the controller 120 may begin to slowly increase pumping speed. Increasing the pump speed may comprise the controller 120 setting a new (higher) pumping speed setpoint and adjusting the speed toward the new setpoint at the speed rate(s) of change described above (e.g. less than 1% per stroke).

The casing pressure increased in step 408 may also be released in step 412. Casing pressure may be returned to normal operating conditions over a time period. The time period may be relatively long so that pressure is slowly returned, for example over one to several days, because slowly releasing pressure may reduce the likelihood or severity of well instability. In other embodiments, casing pressure may begin to be reduced during step 410, prior to the stability condition being met.

At step 414, optionally, the controller 120 continues to monitor the one or more properties of the pump operation and controls the pumping operation accordingly.

The method 400 of FIG. 4 may be useful for remediating pump instability and/or pumping conditions such as (but not limited to) breaking up solids, gas slugging, and other issues that may impact well efficiency.

As also discussed above, the controller may implement different modes of operations (e.g. “stages” or “phases”) as a function of fluid level characteristics of the well, such as GFLAP level ranges. FIG. 5 is a flowchart of another example method 500 of operating a reciprocating downhole pump for producing fluid from a wellbore according to some embodiments. The method may be performed by the controller 120 of FIG. 1. For example, the controller 120 may control the pump 102 of FIG. 1 using the method 500.

At step 502, the controller 120 obtains measurements of at least one property indicative of a fluid level characteristic of the wellbore 101. The sensor measurements may include but is not limited to sucker rod weight measured at the surface. The one or more properties may include the rod weight and/or be calculated or estimated based at least partially on the rod weight measurements and casing pressure. The one or more properties may include, but are not limited to: pump fillage; fluid load; pump intake pressure; and/or inferred production. The fluid level characteristic may be a GFLAP level. By way of example, rod weight may be measured at the surface, and changes in measured rod weight may be indicative of changes in a GFLAP level. Generally, the rod weight measured at the surface may be affected by buoyancy of the rod within the fluid and/or the hydrostatic pressure differential from fluid within the tubing. As the GFLAP level in the wellbore decreases, rod weight measured at the surface may increase (and vice versa). An estimated GFLAP level may be calculated or known from a given rod weight measurement, without requiring a calculation of the estimated GFLAP level to be performed.

At step 504, the controller 120 selects, as a function of the at least one measured property, one of a plurality of modes of operation. Each mode of operation may correspond to a “stage” of the well pumping process, with a first stage corresponding to the highest estimated GFLAP range, and each subsequent stage corresponding to a progressively lower estimated GFLAP range. By way of example, a two-stage embodiment may comprise: a first stage corresponding to a GFLAP level at or above a threshold; and a second stage corresponding to a GFLAP level below the threshold. As another example, a three-stage embodiment may comprise: a first stage corresponding to a GFLAP level at or above a first threshold; a second stage corresponding to a GFLAP level below the first threshold and at or above a second threshold; and a third stage corresponding to a GFLAP level below the second threshold. The number of stages and the associates threshold(s) and GFLAP ranges may vary.

Each mode of operation (or “stage”) comprises a respective set of operational parameters such as setpoints, rules or conditions for adjusting setpoints, and/or other parameters for controlling operation of the reciprocating downhole pump. In this embodiment, the set of operational parameters comprises a pumping speed setpoint and a pumping speed rate of change. The set of operational parameters may further comprise an upper pumping speed limit and/or a lower pumping speed limit.

The pumping speed rate of change may be less than 3% change in speed per stroke. The rate of change may be less than 1% per stroke. For example, the rate of change may be between 0.1% and 0.9% per stroke. The rate of change may be between 0.1% and 0.5% per stroke. The rate of change may be between 0.1% and 0.3% per stroke. The rate of change may also be less than 0.1% or more than 3%. In these ranges, the speed rate of change may be significantly slower than rates utilized in conventional well operations. As noted above, these slower rates of change may improve stability in a well.

The set of operational parameters may include one or more rules for automatically increasing and automatically decreasing pumping speed (i.e. changing the pumping speed setpoint). The rules may prioritize inferred production over pump efficiency. That is, pumping at a lower efficiency but higher SPM may yield higher production than a higher efficiency at a lower SPM.

The set of operational parameters for each mode of operation may also include setpoints controlling shut down cycles of the pump, such as shutdown thresholds and downtime per shutdown cycle. The set of operational parameters may further include rules for adjusting one or more setpoints, such as the setpoints controlling speed and/or shutdown cycles.

The respective sets of operational parameters for each mode of operation (or “stage”) may have a goal of maintaining fillage of the pump 102 above a target percentage. The sets of operational parameters may be designed to prioritize or optimize inferred production may be prioritized over pump fillage percentage in some embodiments. When inferred production drops the operational parameters may respond to changed wellbore behavior and make adjustments to setpoints to help prevent premature shut down due to gas interference. For example, it may be desirable to control the pump 102 to attempt to maintain fillage above a target fillage percentage or 50%, 55%, 60%, 70%, or higher to name a few examples. The operational parameters for each mode of operation may be configured to optimize or improve production for the liquid level conditions of the wellbore. For example, when the GFLAP liquid level is relatively high (in a first stage), pump speed may be maintained or even increased despite the presence of indicators that would dictate lowering pump speed if the GFLAP liquid level was lower (i.e. in another stage). Some specific examples of the stages and associated sets of operational parameters are described below.

At step 506, the controller 120 controls operation of the pump 102 in accordance with the selected mode of operation. Controlling operation of the artificial lift system 100 may comprise obtaining additional measurements data from the one or more sensors 122 and calculating or estimating one or more of the properties discussed in step 502. Controlling operation may also include obtaining additional operational data from other equipment (such as additional sensors). For example, a variety of properties of the system 100 may be monitored in step 506, including one or more of: casing and/or tubing pressure, minimum and maximum polish rod loads measured at surface, etc. Controlling operation of the pump 102 in step 506 may further include automatically changing the pumping speed as a function of the rules for that mode of operation, the monitored operational properties and/or the additional data from other equipment. Changing the pumping speed may include setting a new pumping speed setpoint, and adjusting the speed toward the new net point at the pumping speed rate of change.

One or more of steps 502 to 506 may be repeated throughout at least a portion of the pumping operation. For example, step 502 may be repeated periodically. Upon determining that the fluid level characteristic now corresponds to a different stage than the current mode of operation (i.e. GFLAP level corresponds to a new mode of operation), the new mode of operation may be selected (step 504) accordingly. The pumping operation may then be performed in accordance with the newly selected mode of operation. The method may continue in this manner until the pumping operation has been completed. Optionally, steps 504 and 506 may be repeated, with step 506 additionally including selecting a new mode of operation if the monitored operational properties indicate the fluid level condition of the well now corresponds to a different mode of operation (“stage” or “phase”).

Example modes of operation for a three-stage control scheme will now be described.

Example Stage 1 Mode of Operation

A first mode of operation, referred to as “Stage 1” may be designated for a well with a relatively high GFLAP level (e.g. a range that extends to maximum GFLAP for the well). The Stage 1 mode of operation may be selected when one or more properties indicates the fluid level (e.g. GFLAP level) is at or above a first threshold and/or the pump has a high intake pressure. This determination may be made on one or more of: a GFLAP estimation by direct fluid level measurements; rod weight measurement(s); pump intake pressure measurements; and/or any other measurable property that may indicate a fluid level characteristic. As one non-limiting example, the first threshold may be a GFLAP of 3000 feet for a particular wellbore. The threshold may be a pump intake pressure threshold, such as above 1400 psi for that particular wellbore. The determination may be made based on the measured rod weight, where rod weight below a buoyed weight threshold indicates GFLAP above a GFLAP threshold. The exact property measurements for estimating liquid level characteristic(s) and the associated thresholds may vary.

In wells with the relatively high GFLAP and/or pump intake pressure of Stage 1, gas may be more compressed than Stage 2 or 3 described below (as liquid levels fall), and the gas may behave differently in a multi-phase fluid.

The set of operational parameters for the Stage 1 mode of operation may, as an example, include one or more of the initial parameters in Table 1 below. However, these are merely examples for illustrative purposes, and embodiments are not limited to these examples.

	TABLE 1
	Upper Speed Limit	8 SPM
	Lower Speed Limit	6 SPM
	Speed Rate of Change	<1% per stroke
	First Pump Fillage	60% (5 consecutive strokes)
	Threshold (Speed adjust)
	Second Pump Fillage	50% (5 consecutive strokes)
	Threshold (Shutdown)

Rules for automatically adjusting the pumping speed may include: if pump fillage is above the first pump fillage threshold, then set the speed setpoint to the upper speed limit. If pump fillage falls below the first pump fillage threshold for a set number of consecutive strokes (e.g. 5 strokes), then change the speed setpoint to the lower speed limit.

Additional setpoints or rules may also be provided, such as for adjusting the upper and/or lower speed limits or other setpoints discussed above. The operational parameters may include shutdown cycle settings, such as shutdown duration. These are only example parameters, and the specific parameters.

One or more properties of the pump operation may be ignored or not considered in the rules for increasing/decreasing speed during the Stage 1 operation, while these one or more properties maybe considered during Stage 2, as described below.

Example Stage 2 Mode of Operation

A mode of operation, referred to as “Stage 2” may be designated for a well with an estimated GFLAP in a second range below the first range for Stage 1, but with enough fluid in the well that production may be maintained even if the presence of gas is beginning to affect production. The estimated GFLAP may be less than the first threshold but higher than a second threshold. As one non-limiting example, the second threshold may be a GFLAP of 600 feet. The threshold may be a pump intake pressure threshold, such as above 400 psi. The determination may be made based on the measured rod weight. The exact property measurements for estimating liquid level characteristic(s) and the associated thresholds may vary.

In Stage 2, the well may still have sufficient fluid to support higher pumping speeds (e.g. 6 to 8 SPM or more). The upper and lower speed limits and one or more rules for automatically adjusting speed may initially be similar to Stage 1. However, at State 2, it may be desirable to begin taking steps responsive to one or more operational properties or characteristics. In Stage 2, rules for adjusting speed or speed limits may be based at least in part on one or more properties that were not considered or given priority in the operational parameters for Stage 1. These additional properties may include potential indicators that gas levels in the multi-phase liquid in the well are at or approaching levels that may negatively impact pump performance. Thus, additional rules for lowering pump speed and/or initiating a shutdown cycle may also be added.

For example, the one or more properties that are monitored in Stage 2, but not Stage 1 may include (but are not limited to): a cycle count, which may be a number of shutdown cycles occurring within a predetermined time frame. One or more of the speed setpoint, upper/lower speed limit, and/or pump fillage thresholds may be adjusted based on the cycle count.

In this stage, if production drops due to increased amounts of gas in the pump, the speed may be increased to maintain, rather than rather than lowering pumping speed and dropping production. In the by maintaining or even increasing speed, while allowing for lower pump fillage than Stage 1, the system may pump through gas in the well and production may actually increase. This approach may also reduce downtime compared to conventional pumping control methods.

For example, operational parameters may be adjusted from the initial values in Table 1 to the updated values in Table 2A below.

	TABLE 2
	Upper Speed Limit	8 SPM
	Lower Speed Limit	7 SPM
	Speed Rate of Change	<1% per stroke
	First Pump Fillage	60% (10 consecutive strokes)
	Threshold (Speed adjust)
	Second Pump Fillage	50% (10 consecutive strokes)
	Threshold (Shutdown)

As shown above, the lower speed limit is increased to 7 SPM in this example, and the first and second pump fillage thresholds have been lowered to 60% and 50% respectively. If production stabilizes or improves, then these parameters may be utilized until production again drops or other factors indicate reduced efficiency. Optionally, to the upper speed limit may also be increased to 9 SPM, for example, to compensate for pump fillage drops while pump fillage remains above the first threshold. The speed limits may continue to be adjusted responsive to further monitoring of the pumping conditions to help optimize production, which may include reducing one or both of the upper and lower speed limits.

Example Stage 3 Mode of Operation

Stage 3 mode of operation may be selected when measured properties of the pump operation indicate that the GFLAP level is below the second threshold. In this state, the pump may lose efficiency due to further increased amounts of gas in the fluids entering the pump. For example, the buoyed weight of the sucker rod or peak load may exceed a threshold (higher than the weight or load threshold of Stage 2). Pump efficiency loss and/or instability, or a number of shutdown cycles triggered in a period may also be indicative of low fluid levels for which Stage 3 should be enacted by the controller 120.

As noted above, the monitored properties indicative of GFLAP level may include fluid load, pump intake pressure, rod weight and others. In Stage 3, fluid load may be less than in Stage 2, pump intake pressure may be less than Stage 2, and rod weight may be more than Stage 2.

In Stage 3, additional steps may be taken to stabilize pump operation. For example, the method 400 of FIG. 4 may be followed responsive to a loss of pump efficiency or too many shutdown cycles being triggered over a period.

A set of operational parameters for the Stage 3 mode of operation may, as a non-limiting example, include one or more of the following parameters shown in Table 3 below.

	TABLE 3
	Upper Speed Limit	8 SPM
	Lower Speed Limit	3 SPM
	Speed Rate of Change	<1% per stroke
	First Pump Fillage	60% (10 consecutive strokes)
	Threshold (Speed adjust)
	Second Pump Fillage	50% (10 consecutive strokes)
	Threshold (Shutdown)

The downtime period for a shutdown cycle in Stage 3 may be greater than in Stage 1 or Stage 2, to allow more time for the well to recover.

Similar to the method 400 described with reference to FIG. 4, in Stage 3, pumping speed may be initially slowed down to a relatively low speed (e.g. 3 SPM), and then slowly sped up when monitored properties of the pump operation indicate that pump fillage has recovered. The controller 120 may optimize the speed and shutdown cycles for maximum lift potential.

FIG. 6 is a functional block diagram of an implementation of the controller 120, pump drive 103 and sensors 122 of FIG. 1 according to some embodiments. The controller 120 may comprise one or more processors 602 and memory 604. The memory 604 may have processor executable instructions stored thereon that, when executed, cause the controller to implement one or more of the methods 300, 400, 500 of FIGS. 3 to 5. Any suitable combination of hardware (e.g. circuitry) and/or software may be used to implement the controller 120.

In this example, the sensors 122 include one or more of: pressure sensors 122a arranged to measure pump intake pressure, casing pressure, and/or tubing pressure; and one or more weight sensors 122b arranged to measure sucker rod weight. The sensors 122 may also include one or more additional sensors, and/or one or more of the sensors 122a and 122b may be omitted. The controller 120 may also perform other control functions described herein. The controller 120 is coupled to the pump drive 103 and the sensors 122a and 122b. The sensors 122 may be coupled to the pump drive 103 and positioned to measure the properties of the reciprocating pump operation described herein. The sensors 122 may be components of the pump drive 103 in some embodiments.

The controller 120 may be coupled to a computer device 606 (e.g. computer terminal) comprising a user interface to allow a user to interact with the controller 120. The controller 120 and/or the computer device 606 may also be connected to a network via wired or wireless communication. The controller 120 may also include or be coupled to one or more databases to store data obtained from the sensors 122. The database may also be implemented in the computer device 606.

FIGS. 7A and 7B collectively show a chart illustrating examples of potential monitored properties and operational parameters for a hypothetical well pumping operation. The controller 120 shown in FIGS. 1 and 6 may monitor these properties and control the pump by setting and changing the operational parameters shown and described below.

In FIGS. 7A and 7B, the horizontal axis (x-axis) is time.

FIGS. 7A and 7B show the following example monitored properties: production in Barrels of Fluid Per Day (BFPD) 102; Pump Fillage (PF) 104; Shutdown Cycles (or “Cycles On/Off”) 106; Peak Load 108; Minimum Load 110; and Fluid Load and/or Pump Intake Pressure 112. FIGS. 7A and 7B also show pumping speed in SPM 114. The controller 120 may also monitor casing and/or tubing pressure.

The controller 120 controls at least the following operational parameters in this example: pumping speed (SPM) setpoint; upper pumping speed limit; lower pumping speed limit; pumping speed rate of change; first pump fillage threshold (and consecutive strokes); second pump fillage threshold (and consecutive strokes); shutdown cycle duration. The controller may adjust thoses parameters as a function of rules selected based at least in part on the monitored properties that are indicative of fluid level characteristic (e.g. GFLAP level).

The peak load 108, minimum load 110, pump intake pressure 112 may be indicative of the GFLAP level in the well. As the well is pumped down, the average load may increase. These properties (and possibly other properties) may be monitored as an indication of GFLAP level, and the pumping operation shown in FIGS. 7A and 7B shows a first transition indicated by a dotted line 120a between Stage 1 and Stage 2 modes of operation, and a second transition indicated by a dotted line 120b between Stage 2 and Stage 3 operation.

With reference to FIG. 7A, in Stage 1, for the time period labeled “A”, the well is relatively full well, and the controller has the following settings for pump operation in Table 4A:

	TABLE 4A
	Upper Speed Limit	8 SPM
	Lower Speed Limit	4 SPM
	Speed Rate of Change	10% to 15% per stroke
	First Pump Fillage	80% (3 consecutive strokes)
	Threshold (Speed adjust)
	Second Pump Fillage	70% (3 consecutive strokes)
	Threshold (Shutdown)

Moving into Stage 2, the well is showing signs of increased gas, with production swinging up and down and cycle count increasing. The typical rate of speed change (10% to 15%) can lead to the production and fillage swings shown prior to time “B”. At this stage, there is estimated to be sufficient GFLAP level to maintain production by adjusting the operational parameters. Around time “B”, the controller may respond by implementing the following operational parameters in Table 4B, in which the speed lower limit has been increased and the rate of change substantially decreased. Optionally, the process may start in Stage 1 with the lower rate of change of Table 4B (or lower) rather than the higher rate of Table 4A.

	TABLE 4B
	Upper Speed Limit	8 SPM
	Lower Speed Limit	7 SPM
	Speed Rate of Change	<1% per stroke for speed increase;
		<3% per stroke for speed decrease
	First Pump Fillage	60% (10 consecutive strokes)
	Threshold (Speed adjust)
	Second Pump Fillage	50% (10 consecutive strokes)
	Threshold (Shutdown)

As shown, increasing the pumping speed lower limit and decreasing the pump fillage threshold limits may improve and/or stabilize well production, while pumping off gas in the well. The lower second (shutdown) pump fillage threshold may increase runtime of the pump between shutdown cycles.

Still in stage 2, at time “C”, the well is showing additional signs of increased gas as production and average pump fillage has been decreasing. In this example, the controller implements the following operational parameters in Table 4C:

	TABLE 4C
	Upper Speed Limit	9 SPM
	Lower Speed Limit	7 SPM
	Speed Rate of Change	<1% per stroke for speed increase;
		<3% per stroke for speed decrease
	First Pump Fillage	60% (10 consecutive strokes)
	Threshold (Speed adjust)
	Second Pump Fillage	50% (10 consecutive strokes)
	Threshold (Shutdown)

At time “D”, still in Stage 2, production has again slowed and the controller may begin to slow the pumping speed, for example by returning the upper and lower speed limits to 8 and 6 SPM respectively. The controller may continue to adapt in Stage 2 responsive to changing well and pump conditions. For example, around time “E” in FIG. 7A, the first and second pump fillage thresholds may be raised to 70% and 60% respectively as the average pump speed is reduced. The downtime period setting for shutdown cycles may be increased to give the well more time to recover in each cycle, to help reduce the total number of cycles. Each of the Stage 2 periods of operation starting at times B, C, D, E and F may essentially be considered “substages” or “subphases”.

Eventually, the monitored properties indicate that the well fluid level has lowered to the point that Stage 3 mode of operation is initiated. The Operational parameters, including rules for adjusting the various settings, may now be selected to deal with a well that has less fluid that Stage 2. With reference to FIG. 7B, at time “F” in FIG. 7B the lower speed limit is substantially reduced in this example. Downtime may be further increased for shutdown cycles. The controller may set the following parameters from Table 4D.

	TABLE 4D
	Upper Speed Limit	8 SPM
	Lower Speed Limit	4 SPM
	Speed Rate of Change	<1% per stroke for speed increase;
		<3% per stroke for speed decrease
	First Pump Fillage	70% (10 consecutive strokes)
	Threshold (Speed adjust)
	Second Pump Fillage	60% (10 consecutive strokes)
	Threshold (Shutdown)

The speed rate of change may be increased (e.g. to 0.3% for speed increases and 0.5% for speed decreases) during Stage 3. The downtime period setting for shutdown cycles may be further increased (e.g. doubled) as this stage progresses, for example at time “G” in FIG. 7B. The various example steps of controlling the pump by adjusting setpoints illustrate examples of controlling the pump at least in part on monitored pump properties that are indicative of the fluid level (e.g. GFLAP).

The example of FIGS. 7A and 7B is provided for illustrative purposes and embodiments are not limited to the specific operational parameter settings discussed above.

While certain numerical values are given as examples above, values and sub-ranges within disclosed ranges may also be used in other embodiments. Although several example embodiments are described herein, modifications, adaptations, and other implementations are possible. Features from one or more of the above-described embodiments may be combined or used in sub-combinations with other features described above or with other features which may not be explicitly described above. It is to be understood that a combination of more than one of the approaches described above may be implemented. The example methods described herein may be modified by substituting, reordering, or adding steps to the disclosed methods. Embodiments are not limited to any particular one or more of the approaches, methods or apparatuses disclosed herein. One skilled in the art will appreciate that variations, alterations of the embodiments described herein may be made in various implementations without departing from the scope of the claims.