Advanced management of artificial lift systems in sandy applications

Abstract

A fluid recovery system is configured to assist with the recovery of hydrocarbons or other fluids from a well. The fluid recovery system includes an electric submersible pumping system, a chemical injection system and an integrated control system. The electric submersible pumping system includes an electric motor, a pump driven by the electric motor and a motor drive configured to control the operation of the electric motor. The electric submersible pumping system includes a signal processing module that is configured to detect a sand slugging event by identifying a sand slugging signature in frequency spectrums derived from the current drawn by the motor from the motor drive. The integrated control system is configured to automatically cause the chemical injection system to increase the injection of treatment chemicals into the well if a sand slugging event is detected.

Description

FIELD OF THE INVENTION

[0001] This invention relates generally to the field of artificial lift systems, and more particularly but not by way of limitation, to a system and method for improving the operation of artificial lift systems deployed in wells prone to sand slugging.BACKGROUND

[0002] Artificial lift systems are used to assist with the secondary recovery of oil and gas products through wells drilled into hydrocarbon-producing subterranean formations. Artificial lift systems include electric submersible pumping systems, rod lift systems, gas lift systems, and plunger lift systems. The type of artificial lift system deployed in a particular well depends on a number of factors, including the volume of fluids to be produced from the well and the conditions in the wellbore, including the ratio of gases-to-liquids and the presence of sand or other solids in the produced fluid.

[0003] Recent advances in hydraulic fracturing and other stimulation techniques have improved the recovery of petroleum products. During a hydraulic fracturing operation, sand or other proppant material is slurried with a carrier fluid and pumped into the wellbore under elevated pressures to fracture the producing formation. The sand holds the fractures open to maintain the increased permeability of the formation to encourage the movement of fluids into the wellbore. In some cases, the hydraulic fracturing operation is carried out during the initial completion of the well. In other cases, the hydraulic fracturing operation is conducted after the well has been in production to stimulate and improve the recovery of hydrocarbons.

[0004] Whether naturally occurring or introduced through hydraulic fracturing, the presence of sand and other solids in the wellbore can create problems for artificial lift systems. In particular, the movement of concentrated slugs of sand entrained in wellbore fluids can reduce the efficiency of electric submersible pumping systems. Sand slugs often include agglomerated particles that are difficult to process through turbomachinery. To help break up the agglomerated sand, well operators can inject surfactants into the well to “wet” the sand particles, which reduces the ability of the sand to bind together. Although generally effective, it can be difficult to intelligently control the injection of surfactants or other treatment chemicals intended to address sand slugging in the wellbore.SUMMARY OF THE INVENTION

[0005] In exemplary embodiments, the present disclosure is directed to a fluid recovery system is configured to assist with the recovery of hydrocarbons or other fluids from a well. The fluid recovery system includes an electric submersible pumping system, a chemical injection system and an integrated control system. The electric submersible pumping system includes an electric motor, a pump driven by the electric motor and a motor drive configured to control the operation of the electric motor. The electric submersible pumping system includes a signal processing module that detects the presence of a sand slugging event through an evaluation of signals fed to the motor. The integrated control system is configured to automatically cause the chemical injection system to increase the injection of treatment chemicals into the well if a sand slugging event is impacting the operation of the electric submersible pumping system.

[0006] In some embodiments, the present disclosure describes a fluid recovery system for recovering hydrocarbon fluids from a well, where the fluid recovery system includes an electric submersible pumping system, a chemical injection system, and an integrated control system. The integrated control system is configured to automatically control the operation of the chemical injection system in response to the determination of a sand slugging event impacting the electric submersible pumping system. The electric submersible pumping system can include a signal processing module that is configured to detect the presence of sand slugging at electric submersible pumping system based on signals between the variable speed drive and the electric motor.

[0007] In other embodiments, the present disclosure is directed to a method for mitigating the impact of sand slugging on an electric submersible pumping system deployed in a well to recover hydrocarbon fluids from a subterranean formation. The method includes the steps of providing a chemical injection system that supplies a treatment chemical to the well, identifying the occurrence of a sand slugging event impacting the performance of the electric submersible pumping system, and automatically adjusting the operation of the chemical injection system to increase the delivery of the treatment chemical to the well. The step of identifying the occurrence of the sand slugging event can be performed by providing a signal processing module with data about the performance of a motor in the electric submersible pumping system and determining that the sand slugging event has occurred based on the performance of the motor of the electric submersible pumping system.

[0008] In yet other embodiments, the present disclosure is directed to a fluid recovery system for recovering hydrocarbon fluids from a well in which the fluid recovery system includes an electric submersible pumping system, a chemical injection system, and an integrated control system. The electric submersible pumping system includes a primary pump, an electric motor configured to actuate the primary pump, a motor drive configured to provide the electric motor with a drive current, and a signal processing module configured to determine the presence of sand slugging based on the operational parameters of the electric motor. The chemical injection system includes a chemical tank that contains a treatment chemical, an injection pump connected between the well and the chemical tank, and an injection pump drive configured to control the operation of the injection pump. The integrated control system is configured to automatically control the operation of the chemical injection system in response to the detection of sand slugging by the signal processing module.BRIEF DESCRIPTIONS OF THE DRAWINGS

[0009] FIG. 1 is an illustration of a well site with an embodiment of the fluid recovery system.

[0010] FIG. 2 is a graph showing the effect of a chemical treatment on the current draw of the electric motor of the electric submersible pumping system of FIG. 1.

[0011] FIG. 3 is a graph showing the effect of a chemical treatment on the intake pressure of the electric submersible pumping system of FIG. 1.

[0012] FIG. 4 is a graph showing the effect of a chemical treatment on the intake and discharge pressures of the electric submersible pumping system of FIG. 1.

[0013] FIG. 5 depicts a process flow diagram for a method of mitigating sand slugging.WRITTEN DESCRIPTION

[0014] Beginning with FIG. 1, shown therein is a depiction of a well site 200 that includes one or more wells 202, a surface processing facility 204 and a fluid recovery system 100. The fluid recovery system 100 is configured to recover petroleum products, water, or other fluids from the well 202 and move those fluids to the surface processing facility 204. The surface processing facility 204 can include, for example, a tank battery 206, a flare 208, and a separator 210.

[0015] The well site 200 includes a local data network 212 that connects to a remote data network 214 to exchange information with a remote facility 216. The local data network 212 includes networking and edge computing devices that are configured to monitor the status and performance of the fluid recovery system 100, report information from the well site 200 to the remote network 214, and receive instructions from the remote network 214 to adjust the operation of the fluid recovery system 100.

[0016] In the embodiment depicted in FIG. 1, the fluid recovery system 100 includes an electric submersible pumping system 102, a chemical injection system 104 and an integrated control system 106. The electric submersible pumping system 102 is installed in the well 202 and configured to assist with the removal of target fluids from the well 202. The electric submersible pumping system 102 includes an electric motor 108 and a pump 110, which may be a multistage centrifugal pump. The electric motor 108 converts electricity into torque, which is transferred to the pump 110 through a series of interconnected rotating shafts within the electric submersible pumping system 102.

[0017] The pump 110 can be connected to production tubing 112, which extends out of the well 202 to the surface, where it is connected to the processing facility 204. The electric submersible pumping system 102 can include additional components, such as a seal section 114 located between the motor 108 and the pump 110. The motor 108 is connected to a variable speed (or variable frequency) primary motor drive 116. The primary motor drive 116 outputs a control signal to the motor 108 through a power cable to control the operation of the electric submersible pumping system 102. Adjusting the drive signal output from the primary motor drive 116 to the electric motor 108 can adjust the speed, torque and other operational characteristics of the electric motor 108.

[0018] The electric submersible pumping system 102 also includes an advanced signal processing module 118 that is configured to process information about the operation of the electric submersible pumping system 102. The signal processing module 118 can be integrated into the primary motor drive 116 or functionally connected to the primary motor drive 116 as a separate component (as depicted in FIG. 1). The signal processing module 118 is configured to interpret various inputs received from the primary motor drive 116, the motor 108, the pump 110 and other surface-based or downhole equipment to estimate certain performance characteristics of the electric submersible pumping system 102, which may otherwise be difficult to directly measure.

[0019] In some embodiments, current and voltage waveforms are obtained by the signal processing module 118 with high sampling rates and long sampling windows of the three-phase drive current provided to the motor 108 by the primary motor drive 116. Next, features are derived from both voltage and current waveforms. Operating frequency, power level, speed and torque are also calculated and estimated from the electrical measurements. With enough data collected, the features determined in the absence of a sand slugging event are compared to the features determined when a sand slugging event has been independently determined and verified in a test environment. This comparison yields a “sand slugging signature” that includes those features that represent the presence of a sand slugging event.

[0020] After the features are determined, the method of capturing these features is developed and deployed in the real production environment. The initial period after the monitoring system start is used to collect features for the method to learn the baseline for a specific asset, this can accommodate the difference caused by different application and increase the feature capturing sensitivity.

[0021] Thus, in one mode of operation, the signal processing module 118 is trained on a test data set to identify features that correlate with the presence of sand slugging through the electric submersible pumping system 102. Once trained, the signal processing module 118 can monitor the performance of the electric submersible pumping system 102 by comparing the features produced by the current and voltage supplied by the primary motor drive 116 to the motor 108 to determine if those features match those that were previously identified during training as an indication of sand slugging. The primary motor drive 116 and signal processing module 118 are connected to the local data network 212.

[0022] The chemical injection system 104 includes at least one chemical tank 120, an injection pump 122 and an injection pump drive 124. The chemical tank 120 can include level control sensors that are connected to the local data network 212 and configured to report the level of treatment chemicals in the chemical tank 120. The chemical tank 120 is supplied with one or more treatment chemicals that are useful in breaking up sand agglomerations. Such treatment chemicals may include surfactants, sand dispersants, and other wetting agents that are designed to disperse sand or other solids found in the well 202, including calcium carbonate, calcium sulfate, and iron sulfide. In some cases, the chemical tank 120 is filled or replaced by a chemical delivery truck 218 in response to an automatically generated request from the fluid recovery system 100.

[0023] The chemical tank 120 and injection pump drive 124 are connected to the local data network 212 to provide for the coordinated control of the electric submersible pumping system 102 and chemical injection system 104 by the integrated control system 106. The chemical injection system 104 can supply the term prescribed chemical treatment to the electric submersible pumping system 102 through an injection line or to the annular space in the well 202 surrounding the electric submersible pumping system 102. As used herein, the term “prescribed chemical treatment” refers to the composition of the treatment chemicals and the volumes, injection rates and times the treatment chemicals are delivered by the chemical injection system 104.

[0024] The integrated control system 106 refers to the collection of computerized controllers that adjust the operation of the electric submersible pumping system 102 and chemical injection system 104. The integrated control system 106 includes, for example, the injection pump drive 124, the primary motor drive 116 and the signal processing module 118. The integrated control system 106 is connected to the local data network 212 and the remote data network 214. This permits an operator located at the remote facility 216 to monitor and adjust the operation of the fluid recovery system 100 through a data connection to the integrated control system 106.

[0025] Turning to FIG. 2, shown therein is a graph depicting the current (amps) drawn by the electric motor 108 from the primary motor drive 116 over a period in which the electric submersible pumping system 102 experiences sand slugging and the chemical injection system 104 applies a prescribed chemical treatment. The frequency of the drive signal provided by the primary motor drive 116 to the motor 108 is also depicted. Before the treatment takes place, the current drawn by the motor 108 fluctuates. The fluctuating current signal is interpreted by the signal processing module 118 as an indication of sand passing through the electric submersible pumping system 102. Once the prescribed chemical treatment has been applied to the well 202, the motor 108 begins to draw less current from the primary motor drive 116 and the current draw becomes more stable. This suggests that the prescribed chemical treatment has resolved the sand slugging and improved the operational efficiency of the electric submersible pumping system 102.

[0026] Similarly, FIG. 3 provides a graph depicting the intake pressure of the pump 110 over a period in which the electric submersible pumping system 102 experiences sand slugging and the chemical injection system 104 applies a prescribed chemical treatment. The frequency of the drive signal provided by the primary motor drive 116 to the motor 108 is also depicted. Before the treatment takes place, the intake pressure of the pump 110 fluctuates and temporarily drops. The fluctuating intake pressure is interpreted by the signal processing module 118 as an indication of sand slugging at the electric submersible pumping system 102. Once the prescribed chemical treatment has been applied to the well 202, the sand slugging resolves and the pump intake pressure (PIP) is significantly more stable.

[0027] FIG. 4 provides a graph depicting the intake pressure and discharge pressure of the pump 110 over a period in which the electric submersible pumping system 102 experiences sand slugging and the chemical injection system 104 applies a prescribed chemical treatment. Before the treatment takes place, the intake pressure of the pump 110 fluctuates and temporarily drops. As the intake pressure fluctuates, the discharge pressure also experiences instability. The fluctuating intake and discharge pressures are interpreted by the signal processing module 118 as an indication of sand slugging at the electric submersible pumping system 102. Once the prescribed chemical treatment has been applied to the well 202, the sand slugging resolves and the pump intake and discharge pressures are significantly more stable.

[0028] As illustrated in FIGS. 2-4, the identification and resolution of sand slugging can be determined by examining signals produced by the motor 108, primary motor drive 116 and pump 110. In some embodiments, the frequency spectrums for the current drawn by the motor 108 are interpreted by the signal processing module 118 as including those features that through training were correlated as an indirect indication of the presence and extent of sand slugging at the pump 110. In other embodiments, the signal processing module 118 interprets the intake and discharge pressures of the pump 110 to automatically identify and quantity the sand slugging event. The diagnosis of sand slugging by the signal processing module 118 can be used by the fluid recovery system 100 to automatically initiate the prescribed chemical treatment, which can be automatically tailored to address the specific sand slugging event. Thus, in exemplary embodiments, the fluid recovery system 100 makes possible a method of mitigating sand slugging through the coordinated use of the electric submersible pumping system 102 and chemical injection system 104.

[0029] Turning to FIG. 5, shown therein is a process flow diagram for a method 300 of mitigating sand slugging in the electric submersible pumping system 102 using the intelligent automated control of the chemical injection system 104. At step 302, the fluid recovery system 100 is placed into a normal (or first) operating mode in which the electric submersible pumping system 102 and chemical injection system 104 are operated in accordance with baseline parameters. During the first operating mode, the chemical injection system 104 can be idle or configured to deliver the treatment chemical into the well 202 according to a first treatment prescription. The electric motor 108 is operated by the primary motor drive 116 in accordance with standard control schemes.

[0030] At step 304, the integrated control system 106 determines that a sand slugging event is occurring. The identification of the sand slugging can be made by examining the intake and discharge pressures of the pump 110, or by the presence of a sand slugging signature within the features identified in the frequency spectrums of the electrical current supplied by the primary motor drive 116 to the electric motor 108. It will be appreciated that the determination of the sand slugging event can be made by the integrated control system 106 or by computer systems located at the remote facility in response to data transferred from the well site 200 over the remote data network 214. At step 306, the operator is automatically alerted through one or both of local data network 212 and remote data network 214 to the detected sand slugging event. At step 308, the integrated control system 106 can be configured to automatically alert the chemical supplier that the output of the chemical injection system 104 has been increased and that the supply of treatment chemical in the chemical tank 120 will be exhausted or reduced during the treatment period. This allows the chemical supplier to arrange to deliver additional treatment chemicals to the well site 200 before the chemical tank 120 is empty to ensure an uninterrupted, continuous supply of treatment chemicals.

[0031] At step 310, the integrated control system 106 automatically adjusts the operation of the chemical injection system 104 to apply an increased (or second) chemical treatment prescription. The integrated control system 106 instructs the injection pump drive 124 to apply an increased rate of treatment chemical for a prescribed treatment period. Importantly, the chemical treatment prescription can be formulated based on the specific conditions in the well 202. In this way, the chemical treatment prescription can include multiple injection rates, multiple injection periods within intervening idle periods, and batch-injection steps in which a large volume of treatment chemical is injected within a short period.

[0032] At step 312, the integrated control system 106 determines whether the sand slugging event has subsided or passed based on the same parameters used to identify the onset of the sand slugging event. If the integrated control system 106 determines that the sand slugging event has been sufficiently resolved, the integrated control system 106 can instruct the chemical injection system 104 and electric submersible pumping system 102 to return to normal operating parameters at step 314. If the integrated control system 106 determines that the sand slugging event persists at step 312, the method returns to step 310 and the chemical injection system 104 is instructed to continue applying the treatment chemical at the initial treatment chemical prescription, or at an adjusted treatment chemical prescription that may involve increasing or decreasing the injection of treatment chemicals into the well 202.

[0033] Although the exemplary embodiments have been described in connection with an improved system and method for mitigating sand slugging in an electric submersible pumping system, it will be appreciated that the fluid recovery system 100 can also be configured to automatically address other adverse conditions detected in the well 202 or within the processing facility 204. For example, the integrated control system 106 can be configured to automatically increase the injection of scale prevention chemicals from the chemical injection system 104 if the signal processing module 118 determines that scaling is occurring within the electric submersible pumping system 102 based on signals produced by the electric submersible pumping system 102.

[0034] Although the present embodiments have been disclosed in connection with the electric submersible pumping system 102, it will be appreciated that the same systems and methods can be adapted for use in automatically detecting and responding to sand slugging events affecting the operation of other artificial lift systems, including rod lift, gas lift and plunger lift systems.

[0035] It is to be understood that even though numerous characteristics and advantages of various embodiments of the present invention have been set forth in the foregoing description, together with details of the structure and functions of various embodiments of the invention, this disclosure is illustrative only, and changes may be made in detail, especially in matters of structure and arrangement of parts within the principles of the present invention to the full extent indicated by the broad general meaning of the terms in which the appended claims are expressed.

Examples

Embodiment Construction

[0014]Beginning with FIG. 1, shown therein is a depiction of a well site 200 that includes one or more wells 202, a surface processing facility 204 and a fluid recovery system 100. The fluid recovery system 100 is configured to recover petroleum products, water, or other fluids from the well 202 and move those fluids to the surface processing facility 204. The surface processing facility 204 can include, for example, a tank battery 206, a flare 208, and a separator 210.

[0015]The well site 200 includes a local data network 212 that connects to a remote data network 214 to exchange information with a remote facility 216. The local data network 212 includes networking and edge computing devices that are configured to monitor the status and performance of the fluid recovery system 100, report information from the well site 200 to the remote network 214, and receive instructions from the remote network 214 to adjust the operation of the fluid recovery system 100.

[0016]In the embodiment d...

FIELD OF THE INVENTION

[0001] This invention relates generally to the field of artificial lift systems, and more particularly but not by way of limitation, to a system and method for improving the operation of artificial lift systems deployed in wells prone to sand slugging.BACKGROUND

[0002] Artificial lift systems are used to assist with the secondary recovery of oil and gas products through wells drilled into hydrocarbon-producing subterranean formations. Artificial lift systems include electric submersible pumping systems, rod lift systems, gas lift systems, and plunger lift systems. The type of artificial lift system deployed in a particular well depends on a number of factors, including the volume of fluids to be produced from the well and the conditions in the wellbore, including the ratio of gases-to-liquids and the presence of sand or other solids in the produced fluid.

[0003] Recent advances in hydraulic fracturing and other stimulation techniques have improved the recovery of petroleum products. During a hydraulic fracturing operation, sand or other proppant material is slurried with a carrier fluid and pumped into the wellbore under elevated pressures to fracture the producing formation. The sand holds the fractures open to maintain the increased permeability of the formation to encourage the movement of fluids into the wellbore. In some cases, the hydraulic fracturing operation is carried out during the initial completion of the well. In other cases, the hydraulic fracturing operation is conducted after the well has been in production to stimulate and improve the recovery of hydrocarbons.

[0004] Whether naturally occurring or introduced through hydraulic fracturing, the presence of sand and other solids in the wellbore can create problems for artificial lift systems. In particular, the movement of concentrated slugs of sand entrained in wellbore fluids can reduce the efficiency of electric submersible pumping systems. Sand slugs often include agglomerated particles that are difficult to process through turbomachinery. To help break up the agglomerated sand, well operators can inject surfactants into the well to “wet” the sand particles, which reduces the ability of the sand to bind together. Although generally effective, it can be difficult to intelligently control the injection of surfactants or other treatment chemicals intended to address sand slugging in the wellbore.SUMMARY OF THE INVENTION

[0005] In exemplary embodiments, the present disclosure is directed to a fluid recovery system is configured to assist with the recovery of hydrocarbons or other fluids from a well. The fluid recovery system includes an electric submersible pumping system, a chemical injection system and an integrated control system. The electric submersible pumping system includes an electric motor, a pump driven by the electric motor and a motor drive configured to control the operation of the electric motor. The electric submersible pumping system includes a signal processing module that detects the presence of a sand slugging event through an evaluation of signals fed to the motor. The integrated control system is configured to automatically cause the chemical injection system to increase the injection of treatment chemicals into the well if a sand slugging event is impacting the operation of the electric submersible pumping system.

[0006] In some embodiments, the present disclosure describes a fluid recovery system for recovering hydrocarbon fluids from a well, where the fluid recovery system includes an electric submersible pumping system, a chemical injection system, and an integrated control system. The integrated control system is configured to automatically control the operation of the chemical injection system in response to the determination of a sand slugging event impacting the electric submersible pumping system. The electric submersible pumping system can include a signal processing module that is configured to detect the presence of sand slugging at electric submersible pumping system based on signals between the variable speed drive and the electric motor.

[0007] In other embodiments, the present disclosure is directed to a method for mitigating the impact of sand slugging on an electric submersible pumping system deployed in a well to recover hydrocarbon fluids from a subterranean formation. The method includes the steps of providing a chemical injection system that supplies a treatment chemical to the well, identifying the occurrence of a sand slugging event impacting the performance of the electric submersible pumping system, and automatically adjusting the operation of the chemical injection system to increase the delivery of the treatment chemical to the well. The step of identifying the occurrence of the sand slugging event can be performed by providing a signal processing module with data about the performance of a motor in the electric submersible pumping system and determining that the sand slugging event has occurred based on the performance of the motor of the electric submersible pumping system.

[0008] In yet other embodiments, the present disclosure is directed to a fluid recovery system for recovering hydrocarbon fluids from a well in which the fluid recovery system includes an electric submersible pumping system, a chemical injection system, and an integrated control system. The electric submersible pumping system includes a primary pump, an electric motor configured to actuate the primary pump, a motor drive configured to provide the electric motor with a drive current, and a signal processing module configured to determine the presence of sand slugging based on the operational parameters of the electric motor. The chemical injection system includes a chemical tank that contains a treatment chemical, an injection pump connected between the well and the chemical tank, and an injection pump drive configured to control the operation of the injection pump. The integrated control system is configured to automatically control the operation of the chemical injection system in response to the detection of sand slugging by the signal processing module.BRIEF DESCRIPTIONS OF THE DRAWINGS

[0009] FIG. 1 is an illustration of a well site with an embodiment of the fluid recovery system.

[0010] FIG. 2 is a graph showing the effect of a chemical treatment on the current draw of the electric motor of the electric submersible pumping system of FIG. 1.

[0011] FIG. 3 is a graph showing the effect of a chemical treatment on the intake pressure of the electric submersible pumping system of FIG. 1.

[0012] FIG. 4 is a graph showing the effect of a chemical treatment on the intake and discharge pressures of the electric submersible pumping system of FIG. 1.

[0013] FIG. 5 depicts a process flow diagram for a method of mitigating sand slugging.WRITTEN DESCRIPTION

[0014] Beginning with FIG. 1, shown therein is a depiction of a well site 200 that includes one or more wells 202, a surface processing facility 204 and a fluid recovery system 100. The fluid recovery system 100 is configured to recover petroleum products, water, or other fluids from the well 202 and move those fluids to the surface processing facility 204. The surface processing facility 204 can include, for example, a tank battery 206, a flare 208, and a separator 210.

[0015] The well site 200 includes a local data network 212 that connects to a remote data network 214 to exchange information with a remote facility 216. The local data network 212 includes networking and edge computing devices that are configured to monitor the status and performance of the fluid recovery system 100, report information from the well site 200 to the remote network 214, and receive instructions from the remote network 214 to adjust the operation of the fluid recovery system 100.

[0016] In the embodiment depicted in FIG. 1, the fluid recovery system 100 includes an electric submersible pumping system 102, a chemical injection system 104 and an integrated control system 106. The electric submersible pumping system 102 is installed in the well 202 and configured to assist with the removal of target fluids from the well 202. The electric submersible pumping system 102 includes an electric motor 108 and a pump 110, which may be a multistage centrifugal pump. The electric motor 108 converts electricity into torque, which is transferred to the pump 110 through a series of interconnected rotating shafts within the electric submersible pumping system 102.

[0017] The pump 110 can be connected to production tubing 112, which extends out of the well 202 to the surface, where it is connected to the processing facility 204. The electric submersible pumping system 102 can include additional components, such as a seal section 114 located between the motor 108 and the pump 110. The motor 108 is connected to a variable speed (or variable frequency) primary motor drive 116. The primary motor drive 116 outputs a control signal to the motor 108 through a power cable to control the operation of the electric submersible pumping system 102. Adjusting the drive signal output from the primary motor drive 116 to the electric motor 108 can adjust the speed, torque and other operational characteristics of the electric motor 108.

[0018] The electric submersible pumping system 102 also includes an advanced signal processing module 118 that is configured to process information about the operation of the electric submersible pumping system 102. The signal processing module 118 can be integrated into the primary motor drive 116 or functionally connected to the primary motor drive 116 as a separate component (as depicted in FIG. 1). The signal processing module 118 is configured to interpret various inputs received from the primary motor drive 116, the motor 108, the pump 110 and other surface-based or downhole equipment to estimate certain performance characteristics of the electric submersible pumping system 102, which may otherwise be difficult to directly measure.

[0019] In some embodiments, current and voltage waveforms are obtained by the signal processing module 118 with high sampling rates and long sampling windows of the three-phase drive current provided to the motor 108 by the primary motor drive 116. Next, features are derived from both voltage and current waveforms. Operating frequency, power level, speed and torque are also calculated and estimated from the electrical measurements. With enough data collected, the features determined in the absence of a sand slugging event are compared to the features determined when a sand slugging event has been independently determined and verified in a test environment. This comparison yields a “sand slugging signature” that includes those features that represent the presence of a sand slugging event.

[0020] After the features are determined, the method of capturing these features is developed and deployed in the real production environment. The initial period after the monitoring system start is used to collect features for the method to learn the baseline for a specific asset, this can accommodate the difference caused by different application and increase the feature capturing sensitivity.

[0021] Thus, in one mode of operation, the signal processing module 118 is trained on a test data set to identify features that correlate with the presence of sand slugging through the electric submersible pumping system 102. Once trained, the signal processing module 118 can monitor the performance of the electric submersible pumping system 102 by comparing the features produced by the current and voltage supplied by the primary motor drive 116 to the motor 108 to determine if those features match those that were previously identified during training as an indication of sand slugging. The primary motor drive 116 and signal processing module 118 are connected to the local data network 212.

[0022] The chemical injection system 104 includes at least one chemical tank 120, an injection pump 122 and an injection pump drive 124. The chemical tank 120 can include level control sensors that are connected to the local data network 212 and configured to report the level of treatment chemicals in the chemical tank 120. The chemical tank 120 is supplied with one or more treatment chemicals that are useful in breaking up sand agglomerations. Such treatment chemicals may include surfactants, sand dispersants, and other wetting agents that are designed to disperse sand or other solids found in the well 202, including calcium carbonate, calcium sulfate, and iron sulfide. In some cases, the chemical tank 120 is filled or replaced by a chemical delivery truck 218 in response to an automatically generated request from the fluid recovery system 100.

[0023] The chemical tank 120 and injection pump drive 124 are connected to the local data network 212 to provide for the coordinated control of the electric submersible pumping system 102 and chemical injection system 104 by the integrated control system 106. The chemical injection system 104 can supply the term prescribed chemical treatment to the electric submersible pumping system 102 through an injection line or to the annular space in the well 202 surrounding the electric submersible pumping system 102. As used herein, the term “prescribed chemical treatment” refers to the composition of the treatment chemicals and the volumes, injection rates and times the treatment chemicals are delivered by the chemical injection system 104.

[0024] The integrated control system 106 refers to the collection of computerized controllers that adjust the operation of the electric submersible pumping system 102 and chemical injection system 104. The integrated control system 106 includes, for example, the injection pump drive 124, the primary motor drive 116 and the signal processing module 118. The integrated control system 106 is connected to the local data network 212 and the remote data network 214. This permits an operator located at the remote facility 216 to monitor and adjust the operation of the fluid recovery system 100 through a data connection to the integrated control system 106.

[0025] Turning to FIG. 2, shown therein is a graph depicting the current (amps) drawn by the electric motor 108 from the primary motor drive 116 over a period in which the electric submersible pumping system 102 experiences sand slugging and the chemical injection system 104 applies a prescribed chemical treatment. The frequency of the drive signal provided by the primary motor drive 116 to the motor 108 is also depicted. Before the treatment takes place, the current drawn by the motor 108 fluctuates. The fluctuating current signal is interpreted by the signal processing module 118 as an indication of sand passing through the electric submersible pumping system 102. Once the prescribed chemical treatment has been applied to the well 202, the motor 108 begins to draw less current from the primary motor drive 116 and the current draw becomes more stable. This suggests that the prescribed chemical treatment has resolved the sand slugging and improved the operational efficiency of the electric submersible pumping system 102.

[0026] Similarly, FIG. 3 provides a graph depicting the intake pressure of the pump 110 over a period in which the electric submersible pumping system 102 experiences sand slugging and the chemical injection system 104 applies a prescribed chemical treatment. The frequency of the drive signal provided by the primary motor drive 116 to the motor 108 is also depicted. Before the treatment takes place, the intake pressure of the pump 110 fluctuates and temporarily drops. The fluctuating intake pressure is interpreted by the signal processing module 118 as an indication of sand slugging at the electric submersible pumping system 102. Once the prescribed chemical treatment has been applied to the well 202, the sand slugging resolves and the pump intake pressure (PIP) is significantly more stable.

[0027] FIG. 4 provides a graph depicting the intake pressure and discharge pressure of the pump 110 over a period in which the electric submersible pumping system 102 experiences sand slugging and the chemical injection system 104 applies a prescribed chemical treatment. Before the treatment takes place, the intake pressure of the pump 110 fluctuates and temporarily drops. As the intake pressure fluctuates, the discharge pressure also experiences instability. The fluctuating intake and discharge pressures are interpreted by the signal processing module 118 as an indication of sand slugging at the electric submersible pumping system 102. Once the prescribed chemical treatment has been applied to the well 202, the sand slugging resolves and the pump intake and discharge pressures are significantly more stable.

[0028] As illustrated in FIGS. 2-4, the identification and resolution of sand slugging can be determined by examining signals produced by the motor 108, primary motor drive 116 and pump 110. In some embodiments, the frequency spectrums for the current drawn by the motor 108 are interpreted by the signal processing module 118 as including those features that through training were correlated as an indirect indication of the presence and extent of sand slugging at the pump 110. In other embodiments, the signal processing module 118 interprets the intake and discharge pressures of the pump 110 to automatically identify and quantity the sand slugging event. The diagnosis of sand slugging by the signal processing module 118 can be used by the fluid recovery system 100 to automatically initiate the prescribed chemical treatment, which can be automatically tailored to address the specific sand slugging event. Thus, in exemplary embodiments, the fluid recovery system 100 makes possible a method of mitigating sand slugging through the coordinated use of the electric submersible pumping system 102 and chemical injection system 104.

[0029] Turning to FIG. 5, shown therein is a process flow diagram for a method 300 of mitigating sand slugging in the electric submersible pumping system 102 using the intelligent automated control of the chemical injection system 104. At step 302, the fluid recovery system 100 is placed into a normal (or first) operating mode in which the electric submersible pumping system 102 and chemical injection system 104 are operated in accordance with baseline parameters. During the first operating mode, the chemical injection system 104 can be idle or configured to deliver the treatment chemical into the well 202 according to a first treatment prescription. The electric motor 108 is operated by the primary motor drive 116 in accordance with standard control schemes.

[0030] At step 304, the integrated control system 106 determines that a sand slugging event is occurring. The identification of the sand slugging can be made by examining the intake and discharge pressures of the pump 110, or by the presence of a sand slugging signature within the features identified in the frequency spectrums of the electrical current supplied by the primary motor drive 116 to the electric motor 108. It will be appreciated that the determination of the sand slugging event can be made by the integrated control system 106 or by computer systems located at the remote facility in response to data transferred from the well site 200 over the remote data network 214. At step 306, the operator is automatically alerted through one or both of local data network 212 and remote data network 214 to the detected sand slugging event. At step 308, the integrated control system 106 can be configured to automatically alert the chemical supplier that the output of the chemical injection system 104 has been increased and that the supply of treatment chemical in the chemical tank 120 will be exhausted or reduced during the treatment period. This allows the chemical supplier to arrange to deliver additional treatment chemicals to the well site 200 before the chemical tank 120 is empty to ensure an uninterrupted, continuous supply of treatment chemicals.

[0031] At step 310, the integrated control system 106 automatically adjusts the operation of the chemical injection system 104 to apply an increased (or second) chemical treatment prescription. The integrated control system 106 instructs the injection pump drive 124 to apply an increased rate of treatment chemical for a prescribed treatment period. Importantly, the chemical treatment prescription can be formulated based on the specific conditions in the well 202. In this way, the chemical treatment prescription can include multiple injection rates, multiple injection periods within intervening idle periods, and batch-injection steps in which a large volume of treatment chemical is injected within a short period.

[0032] At step 312, the integrated control system 106 determines whether the sand slugging event has subsided or passed based on the same parameters used to identify the onset of the sand slugging event. If the integrated control system 106 determines that the sand slugging event has been sufficiently resolved, the integrated control system 106 can instruct the chemical injection system 104 and electric submersible pumping system 102 to return to normal operating parameters at step 314. If the integrated control system 106 determines that the sand slugging event persists at step 312, the method returns to step 310 and the chemical injection system 104 is instructed to continue applying the treatment chemical at the initial treatment chemical prescription, or at an adjusted treatment chemical prescription that may involve increasing or decreasing the injection of treatment chemicals into the well 202.

[0033] Although the exemplary embodiments have been described in connection with an improved system and method for mitigating sand slugging in an electric submersible pumping system, it will be appreciated that the fluid recovery system 100 can also be configured to automatically address other adverse conditions detected in the well 202 or within the processing facility 204. For example, the integrated control system 106 can be configured to automatically increase the injection of scale prevention chemicals from the chemical injection system 104 if the signal processing module 118 determines that scaling is occurring within the electric submersible pumping system 102 based on signals produced by the electric submersible pumping system 102.

[0034] Although the present embodiments have been disclosed in connection with the electric submersible pumping system 102, it will be appreciated that the same systems and methods can be adapted for use in automatically detecting and responding to sand slugging events affecting the operation of other artificial lift systems, including rod lift, gas lift and plunger lift systems.

[0035] It is to be understood that even though numerous characteristics and advantages of various embodiments of the present invention have been set forth in the foregoing description, together with details of the structure and functions of various embodiments of the invention, this disclosure is illustrative only, and changes may be made in detail, especially in matters of structure and arrangement of parts within the principles of the present invention to the full extent indicated by the broad general meaning of the terms in which the appended claims are expressed.

Examples

Embodiment Construction

[0014]Beginning with FIG. 1, shown therein is a depiction of a well site 200 that includes one or more wells 202, a surface processing facility 204 and a fluid recovery system 100. The fluid recovery system 100 is configured to recover petroleum products, water, or other fluids from the well 202 and move those fluids to the surface processing facility 204. The surface processing facility 204 can include, for example, a tank battery 206, a flare 208, and a separator 210.

[0015]The well site 200 includes a local data network 212 that connects to a remote data network 214 to exchange information with a remote facility 216. The local data network 212 includes networking and edge computing devices that are configured to monitor the status and performance of the fluid recovery system 100, report information from the well site 200 to the remote network 214, and receive instructions from the remote network 214 to adjust the operation of the fluid recovery system 100.

[0016]In the embodiment d...

Claims

1. A fluid recovery system for recovering hydrocarbon fluids from a well, the fluid recovery system comprising:an electric submersible pumping system, wherein the electric submersible pumping system comprises:an electric motor deployed in the well;a pump deployed in the well and driven by the electric motor;a motor drive configured to supply a drive current to the electric motor; anda signal processing module that identifies the presence of a sand slugging event by comparing the drive current against a known sand slugging signature derived from a test data set;a chemical injection system; andan integrated control system, wherein the integrated control system is configured to automatically control the operation of the chemical injection system in response to the determination of a sand slugging event impacting the electric submersible pumping system.

2. (canceled)3. The fluid recovery system of claim 1, wherein the signal processing module is configured to identify the presence of the sand slugging event based on features of frequency spectrums of the drive current applied to the electric motor by the motor drive.

4. The fluid recovery system of claim 3, wherein the chemical injection system comprises:a chemical tank;an injection pump connected between the chemical tank and the well; andan injection pump drive configured to control the operation of the injection pump.

5. (canceled)6. (canceled)7. (canceled)8. (canceled)9. (canceled)10. (canceled)11. (canceled)12. A fluid recovery system for recovering hydrocarbon fluids from a well, the fluid recovery system comprising:an electric submersible pumping system, wherein the electric submersible pumping system comprises:a primary pump;an electric motor configured to actuate the primary pump;a motor drive configured to provide the electric motor with a drive current; anda signal processing module configured to detect a sand slugging event by identifying a sand slugging signature from features derived from the electric submersible pumping system, wherein such features include fluctuating drive current drawn by the electric motor, fluctuating intake pressure at the primary pump, and fluctuating discharge pressure at the primary pump;a chemical injection system, wherein the chemical injection system comprises:a chemical tank that contains a treatment chemical;an injection pump connected between the well and the chemical tank; andan injection pump drive configured to control the operation of the injection pump; andan integrated control system, wherein the integrated control system is configured to automatically control the operation of the chemical injection system in response to the detection of the sand slugging event by the signal processing module.

13. The fluid recovery system of claim 12, wherein the treatment chemical is selected from the group consisting of surfactants, wetting agents, and sand dispersants.

14. A fluid recovery system for recovering hydrocarbon fluids from a well, the fluid recovery system comprising:an electric submersible pumping system, wherein the electric submersible pumping system comprises:an electric motor deployed in the well;a pump deployed in the well and driven by the electric motor, wherein the pump has a pump intake pressure (PIP);a motor drive configured to supply a drive current to the electric motor; anda signal processing module that identifies a sand slugging event at the electric submersible pumping system by identifying fluctuations in the drive current or fluctuations in the pump intake pressure (PIP);a chemical injection system; andan integrated control system, wherein the integrated control system is configured to automatically control the operation of the chemical injection system in response to the determination of a sand slugging event impacting the electric submersible pumping system.

15. The fluid recovery system of claim 14, wherein the chemical injection system comprises:a chemical tank that includes a treatment chemical;an injection pump connected between the chemical tank and the well; andan injection pump drive configured to control the operation of the injection pump.

16. The fluid recovery system of claim 15, wherein the treatment chemical is selected from the group consisting of surfactants, wetting agents, and sand dispersants.

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