System and method for adaptive delivery of chemicals to electric submersible pumping systems

Abstract

Systems and methods are disclosed for carrying out a chemical treatment on a well located at a well site, wherein an electric submersible pumping system is deployed in the well to recover hydrocarbons and associated fluids. The method includes the steps of connecting a chemical treatment system to the well that includes an injection pump and an injection pump controller, initiating the chemical treatment by setting the injection pump at an initial flow rate, calculating a virtual flow rate for the electric submersible pumping system with a virtual flow module, and automatically adjusting the output of the injection pump based on the virtual flow rate calculated by the virtual flow module.

Description

FILED OCTOBER 10, 2025 61DAL-511130-WO-2SYSTEM AND METHOD FOR ADAPTIVE DELIVERY OF CHEMICALS TO ELECTRIC SUBMERSIBLE PUMPING SYSTEMSRelated Applications

[0001] This application claims the benefit of United States Provisional Patent Application Serial No. 63 / 719,514 filed November 12, 2024 and entitled. '“System and Method for Adaptive Delivery of Chemicals to Electric Submersible Pumping Systems." the disclosure of which is herein incorporated by reference.Field of the Invention

[0002] 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 delivery of treatment chemicals to a well that includes an electric submersible pumping system or other artificial lift system.Background

[0003] Operators of oil and gas wells may periodically need to apply treatment chemicals to improve the recovery of hydrocarbons or other fluids. In “continuous” injection cases, the treatment chemicals are either: 1) injected from a chemical injection skid located near the well dow n a capillary string strapped to the tubing down or 2) down the casing / tubing annulus side with an access point positioned at the wellhead. In “non-continuous” situations, the treatment chemicals are applied in “periodic batch” operations in which large volumes are pumped from a delivery7truck down the casing / tubing annulus or down the tubing.

[0004] In many wells, the production of oil and gas varies rapidly between gas and liquid dominant multiphase fluids. These rapid phase changes in the multiphase fluid stream, sourced from the reservoir, can challenge the use of electric submersible pumps and other artificial lift systems. Advanced gas handling pump configurations, variable speed drive control modes, andautomated back pressure valves are some of the tools used to help extend run lives and maximize production.

[0005] However, rapid changes in three-phase flow behavior can challenge the ability to inhibit scale and corrosion efficiently using the methods discussed above. In the past, “continuous” chemical injection pumps have been configured to deliver a flow of treatment chemicals at steady rate using a “set-it-and-leave-it" strategy. As depicted in FIG. 1, a service technician following a prior art approach manually conducts a chemical drawdown rate (typically monthly) and then sets the chemical injection system to inject the treatment chemical at constant rate 300 according to the most recent data regarding the rate of production of liquid hydrocarbons 302 and gas hydrocarbons 304. As illustrated in FIG. 1, the rate of production of liquid hydrocarbons 302 drops rapidly while the production rate of gas hydrocarbons 304 increases due to a gas slugging event. Using the conventional “set-it-and-leave-it” approach for delivering treatment chemicals to the well, treatment chemicals injected at a rate 300 intended to match the initial production rate of the liquid hydrocarbons 302 become excessive during and after the gas slugging event.

[0006] More advanced chemical injection methods apply a constant treatment chemical injection rate that is monitored and managed remotely. These systems work efficiently for wells that have little or no gas interference, but require constant attention if operating below the bubble point. However, as liquid production rates vary from targeted set points, the system either undertreats when there is liquid influx or overtreats during gassy phases, which leads to unnecessary chemical costs. Although a controller can be set up to inject treatment chemicals appropriate for the highest possible production rate from the well, this strategy would be inefficient and expensive, and the excess treatment chemicals can lead to emulsion issues if saturation levels remain elevated. There is. therefore, a need for improved systems and methods that overcome these and other deficiencies in the prior art.Summary of the Invention

[0007] In some embodiments, the present disclosure is directed to a fluid recovery system for producing fluids from a subterranean well located at a well site that includes surface processing facilities and a local data network. The fluid recovery system includes an electric submersible pumping system deployed in the subterranean well, a chemical treatment system, and an integrated control system. The electric submersible pumping system has a motor drive, an electric motor driven by the motor drive and a pump driven by the electric motor. The chemical treatment system is configured to deliver a treatment chemical to the well according to a prescribed chemical treatment. The chemical treatment system includes an injection pump, an injection pump motor, an injection pump controller, a chemical liquid discharge line feeding into the well, and an integrated control system. The integrated control system comprises a virtual flow module configured to calculate a virtual flow rate for the electric submersible pumping system. The integrated control system is also configured to automatically adjust the operation of the chemical treatment system in response to the virtual flow rate calculated by the virtual flow module.

[0008] In other aspects, the present disclosure is directed to a method for carrying out a chemical treatment on a well located at a well site, wherein an electric submersible pumping system is deployed in the well to recovery hydrocarbons and associated water. The “continuous” method includes the steps of connecting a chemical treatment system to the well that includes an injection pump and an injection pump controller, initiating the chemical treatment by setting the injection pump at an initial flow rate to establish a baseline, calculating a virtual flow rate for the electric submersible pumping system with a virtual flow module, and automatically’ adjusting the output of the injection pump based on the virtual flow rate calculated by the virtual flow module.

[0009] In yet other embodiments, the present disclosure is directed to a method for carrying out a chemical treatment on a well located at a well site, wherein an electric submersible pumping system is deployed in the well to recover hydrocarbons or other fluids. The method includes the steps of connecting a chemical treatment system to the well that includes an injection pump and an injection pump controller, then establishing a chemical treatment by aligning the chemical injection rate in direct correspondence with a virtual flow rate derived from the electric submersible pumping system.Brief Descriptions of the Drawings

[0010] FIG. 1 presents comparative graphs between the production rates of multiphase hydrocarbons with the deliver}' rate of treatment chemicals according to a PRIOR ART system.

[0011] FIG. 2 is an illustration of a well site with an embodiment of the adaptive chemical treatment system.

[0012] FIG. 3 is a block diagram depicting an embodiment in which multiphase hydrocarbon flow rates are determined using a machine learning model based on data inputs from the electric submersible pumping system.

[0013] FIG. 4 is a process flow diagram depicting an exemplar}' embodiment of an adaptive method for chemical injection based on the multiphase hydrocarbon flow profile determined through the system outlined in FIG. 3.

[0014] FIG. 5 presents comparative graphs between the production rates of multiphase hydrocarbons with the delivery rate of treatment chemicals according to the adaptive method depicted in FIG. 4.Written Description

[0015] Beginning with FIG. 2. shown therein is a depiction of a well site 200 that includes one or more wells 202 and surface facilities 204. The surface facilities 204 can include, for example, a tank battery 206. a flare stack 208, and a separator 2W. Generally, the well 202 is used toproduce hydrocarbons and associated water, which are then separated, stored and eventually transported from the surface facilities 204. A fluid recovery system 100 is used to produce hydrocarbons, associated water or other fluids from the wells 202. The well site 200 includes a local data network 212 that connects to a remote data network 214.

[0016] In the embodiment depicted in FIG. 2, the fluid recovery system 100 includes an electric submersible pumping system 102, a chemical treatment 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 (e.g., hydrocarbons, associated water, and other fluids) from the well 202. The electric submersible pumping system 102 includes an electric motor(s) 108 and a multistage centrifugal pump(s) 110. 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. The electric motor 108 can be an induction motor or a permanent magnet motor driven by the 3-phase electrical power from the surface.

[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 surface facilities 204. The electric submersible pumping system 102 can include additional components, such as a seal '‘protector” section 114 located between the motor 108 and the pump 110. The motor 108 is controlled by a variable speed (or variable frequency) motor drive 116. The 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 motor drive 116 to the electric motor 108 can adjust the speed, torque and other operational characteristics of the electric motor 108.

[0018] The chemical treatment system 104 includes an injection line 118, a chemical tank 120 and an injection pump 122, which cooperate to deliver the treatment chemicals from thechemical tank 120 to the well 202. The injection pump 122 includes an injection pump motor 124. The chemical treatment system 104 also includes an injection pump controller 126 that controls the operation of the injection pump 122 by adjusting the power provided to the injection pump motor 124. The injection pump controller 126 can be connected to the integrated control system 106 through the local data network 212. The injection pump controller 126 can also be connected to the motor drive 116 through the local datanetwork 212.

[0019] The integrated control system 106 refers to the collection of computerized controllers that adjust the operation of the electric submersible pumping system 102, chemical treatment system 104 and surface facilities 204. The integrated control system 106 includes a virtual flow module 128 and a networking module 130. The networking module 130 provides for wired or wireless data connections with other computers at the well site 200 through the local data network 212, as well as to computers located at one or more remote locations 216 through the remote data network 214. The networking module 130 can be part of a SC ADA (Supervisory Control and Data Acquisition) network, which exchanges information between an operator at the remote location 216 and the well site 200.

[0020] The virtual flow module 128 is a computer-implemented system that is configured to estimate the output from the electric submersible pumping system 102 in real time using virtual flow inputs available from both electrical readings obtained from the electric submersible motor, power cable, variable frequency drive, and the downhole sensors located on or in proximity with the electric submersible pumping system 102. In exemplar}' embodiments, the virtual flow module 128 is a computer-implemented model that produces a flow estimation (a "virtual flow measurement’7) for the electric submersible pumping system 102 based on measurements obtained from the electric submersible pumping system 102 and motor drive 116. Suitable virtual flow meters and virtual flow software are available from Baker Hughes Company, including the virtual flow meters available under the NeuraFlow brand.

[0021] As illustrated in the block diagram of FIG. 3, the virtual flow inputs may include the intake pressure at the pump 110 (PIP), the discharge pressure from the pump 110 (PDP), motor and output current, and the frequency of the drive current applied to the electric motor 108 by the motor drive 116. These measurements are used as inputs to a correlative model based on neural networks or other machine learning systems that correlate these inputs with anticipated multiphase flow rates from the pump 110. The virtual flow module 128 is capable of accurately deriving virtual flow rates from the pump 110 that can be trended, analyzed, and used for adjusting the operation of the electric submersible pumping system 102 and chemical treatment system 104.

[0022] The virtual flow module 128 can be located on or in cloud-based or physical computer servers located at remote locations 216. To ensure low-latency performance, the remote data network 214 must efficiently and rapidly exchange information from the well site 200 to the virtual flow module 128. Alternatively, the virtual flow module 128 can be located within one or more of the computerized components located at the well site 200, such as the motor drive 116 or dedicated edge devices. In some applications, portions of the virtual flow module 128 may be located at the remote location 216, while other portions of the virtual flow module 128 are located at the well site 200. In each case, the virtual flow module 128 achieves the near instantaneous calculation of virtual flow rates by processing the virtual flow inputs through a model that includes a well-trained advanced algorithm matched to the design curves for the electric submersible pumping system 102.

[0023] Importantly, the virtual flow rates are determined more rapidly than relying on physical sensors located within the separator 210 or other component within the surface facility 204. The virtual flow module 128 acquires the virtual flow inputs and calculates the virtual flow rates in real time or near-real time so that the virtual flow rates accurately reflect the conditions at the electric submersible pumping system 102. In contrast, flow rates measured by sensorson the surface incur significant lag delays at the electric submersible pumping system 102 because of the travel time required for the well fluids to reach the surface facilities from the producing formation of the well 202. Additionally, the well fluids may undergo phase changes as the fluids are lifted to the surface and hydrostatic pressure declines, which frustrates efforts to accurately evaluate conditions at the electric submersible pumping system 102 based on measurements at the surface.

[0024] For example, if the electric submersible pumping system 102 encounters intermittent gas slugging that diminishes the liquid production from the electric submersible pumping system 102, the virtual flow module 128 can identify the decline in liquid flow within the virtual flow rates almost instantaneously as the decline is occurring because the virtual flow inputs can be acquired and processed in seconds or fractions of seconds. In contrast, conventional flow measurement equipment located in the surface facilities 204 might not detect declines in liquid production for minutes or even hours due to the relatively slow movement of fluids from the depths of the well 202 to the surface facilities 204.

[0025] The virtual flow rates produced by the virtual flow module 128 can be used to optimize the operation of the chemical treatment system 104 so that the chemical treatment system 104 more rapidly responds to changes in the downhole conditions near the electric submersible pumping system 102. For example, the virtual flow rates can be used by the integrated control system 106 to rapidly adjust the operation of the injection pump 122 so that the volume of injected treatment chemicals closely matches the conditions present at the electric submersible pumping system 102.

[0026] FIG. 4 depicts an exemplary embodiment of a method 400 for the automatic adaptive chemical injection using virtual flow rates produced by the virtual flow module 128. At step 402, the virtual flow module 128 acquires measured and virtual inputs from the electric submersible pumping system 102. In some embodiments, the measured inputs include pumpintake pressure (PIP), pump discharge pressure (PDP) and motor drive frequency. In other embodiments, measured and virtual inputs include one or more of the following measurements from the electric submersible pumping system 102: liquid / gas fraction, well fluid temperature, well fluid composition, pump and motor vibration, motor torque, motor temperature, and drive current amperage. These measurements can be taken directly or indirectly inferred from the electric submersible pumping system 102 or from the motor drive 116. It will be appreciated that in yet other embodiments, the virtual flow module 128 uses one or more of the pump intake pressure (PIP), pump discharge pressure (PDP) and motor drive frequency inputs, together with one or more of the liquid / gas fraction, well fluid temperature, well fluid composition, pump and motor vibration, motor torque, motor temperature, and drive current amperage measurements.

[0027] At step 404, the virtual flow module 128 determines the virtual flow rates from the measured and virtual inputs. At step 406, the integrated control system 106 uses the virtual flow rates to adjust the operation of the chemical treatment system 104 by adjusting the output of the injection pump motor 124 through the injection pump controller 126. Importantly, because the treatment chemical is provided to the well 202 through the injection line 118, the rate at which the treatment chemicals are hydraulically injected at the electric submersible pumping system 102 is substantially the same as the discharge rate from the injection pump 122 on the surface. In this way, an adjustment to the discharge rate of the injection pump 122 corresponds almost exactly with the discharge rate of treatment chemical at the electric submersible pumping system 102.

[0028] At step 408, the integrated control system 106 adjusts the operation of the chemical injection pump 122 according to one or more correlation strategies. In some embodiments, correlation treatment strategy seeks to adjust the injection rate of the treatment chemicals in linear proportion to the output from the pump 110 of the electric submersible pumping system102. For example, if the liquid output from the electric submersible pumping system 102 declines by 50%, the integrated control system 106 can be configured to automatically and proportionately reduce the output from the chemical injection pump 122 by 50%. In other embodiments, the correlation strategy adjusts the output of the chemical injection pump 122 according to a non-linear relationship or an inverse linear or non-linear relationship (i.e., the injection rate increases as the production from the electric submersible pumping system 102 decreases or vice versa).

[0029] At step 408, the integrated control system 106 determines whether the chemical injection rate matches the output from the electric submersible pumping system 102. If not, the method returns to step 406 and further adjustments are made to the operation of the chemical injection pump 122. The method cycles between steps 406 and 408 until the injection rate of the treatment chemicals satisfactorily satisfies the treatment strategy. The process then returns to step 404 when new virtual flow rates are determined by the virtual flow module 128. It will be appreciated that the virtual flow module 128 can be configured to determine the virtual flow rate on a predetermined frequency, such as once per: 1-1000 milliseconds, 1 second, 10 seconds, 30 seconds, 1 minute, 10 minutes, 30 minutes, 1 hour, 2 hours, 12 hours, 24 hours, 48 hours, or week.

[0030] Referring now to FIG. 5, the method 400 can be applied to rapidly adjust the operation of the chemical treatment system 104 to precisely match the liquid output from the electric submersible pumping system 102. When the gas slugging event occurs, the virtual flow module 128 immediately detects the reduction in liquid output from the electric submersible pumping system 102 in the virtual flow rates calculated from the rapid acquisition and processing of the virtual flow inputs . The integrated control sy stem 106 can then adj ust the output of the chemical treatment system 106 based on the virtual flow rates. Compared to the prior art control system depicted in FIG. 1. the output from the chemical treatment system can be promptly matched tothe output of the electric submersible pumping system 102 to avoid the wasteful and expensive deployment of treatment chemicals in the well 202.

[0031] Thus, in exemplary embodiments, a method for conducting an adaptive chemical treatment includes the steps of automatically determining a virtual flow rate with the virtual flow module 128 and then automatically adjusting the operation of the chemical treatment system 104 so the output of the chemical injection pump 122 corresponds to the output from the electric submersible pumping system 102. 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.

Claims

What is claimed is:

1. A fluid recovery system for producing fluids from a subterranean well located at a well site that includes surface processing facilities and a local data network, the fluid recovery system comprising:an electric submersible pumping system deployed in the subterranean well, wherein the electric submersible pumping system comprises:a motor drive;an electric motor driven by the motor drive; anda pump driven by the electric motor;a chemical treatment system configured to deliver a treatment chemical to the well according to a prescribed chemical treatment, wherein the chemical treatment system comprises:an injection pump;an injection pump motor;a chemical delivery line into the well; andan injection pump controller; andan integrated control system, wherein the integrated control system comprises a virtual flow module configured to calculate a virtual flow rate for the electric submersible pumping system, and wherein the integrated control system is configured to automatically adjust the operation of the chemical treatment system in response to the virtual flow rate calculated by the virtual flow module.

2. The fluid recovery system of claim 1, wherein the electric submersible pumping system outputs signals representative of intake pressure at the pump (PIP), discharge pressure at the pump (PDP), motor current, and frequency of the drive current provided by the motor drive to the electric motor.

3. The fluid recovery system of claim 2, wherein the virtual flow module calculates the virtual flow rate based on the intake pressure at the pump (PIP), discharge pressure at the pump (PDP) motor current, and frequency of the drive current provided by the motor drive to the electric motor.

4. The fluid recovery system of claim 1, wherein the virtual flow module calculates the virtual flow rate based on a measured well condition or operational parameter of the electric submersible pumping system selected from the group consisting of pump intake pressure (PIP), pump discharge pressure (PDP), drive current frequency, liquid / gas fraction, well fluid temperature, well fluid composition, pump and motor vibration, motor torque, and motor temperature, and drive current amperage.

5. The fluid recovery system of claim 1, wherein the integrated control system comprises a networking module that connects the integrated control system to a remote location.

6. The fluid recovery system of claim 5, wherein the virtual flow module is located at the remote location.

7. The fluid recovery system of claim 5, wherein the virtual flow module is located at the well site.

8. A method for carrying out a chemical treatment on a well located at a well site, wherein an electric submersible pumping system is deployed in the well to recover hydrocarbons and associated fluids, the method comprising the steps of:connecting a chemical treatment system to the well that includes an injection pump and an injection pump controller;initiating the chemical treatment by setting the injection pump at an initial flow rate; calculating a virtual flow rate for the electric submersible pumping system with a virtual flow module; andautomatically aligning the output of the injection pump based on the virtual flow rate calculated by the virtual flow module.

9. The method of claim 8, wherein the step of calculating the virtual flow rate comprises the step of obtaining inputs from the electric submersible pumping system, wherein the inputs are selected from the group consisting of measured inputs, virtual inputs and combinations of measured inputs and virtual inputs.

10. The method of claim 9, wherein the step of acquiring measured and virtual inputs comprises acquiring measurements from the electric submersible pumping system for pump intake pressure (PIP), pump discharge pressure (PDP), motor current, output current, and a frequency of current provided to the electric submersible pumping system.

11. The method of claim 9, wherein the step of automatically adjusting the output of the injection pump based on the virtual flow rate comprises adjusting the output of the injection pump in a linear proportion to the virtual flow rate of the electric submersible pumping system.

12. The method of claim 9, wherein the step of automatically adjusting the output of the injection pump based on the virtual flow rate comprises adjusting the output of the injection pump in a non-linear relationship to the virtual flow rate of the electric submersible pumping system.

13. A method for carrying out a chemical treatment on a well located at a well site, wherein an electric submersible pumping system is deployed in the well to recover petroleum products or other fluids, the method comprising the steps of:connecting a chemical treatment system to the well that includes an injection pump and an injection pump controller;initiating a chemical treatment by setting the injection pump at a first injection rate; calculating a virtual flow rate for the electric submersible pumping system with a virtual flow module on a periodic basis, wherein the virtual flow rate represents an output of the electric submersible pumping system;determining that the output of the electric submersible pumping system has changed based on a change to the virtual flow rate; andautomatically adjusting the output of the injection pump to a second injection rate based on the change to the virtual flow rate.

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