Producing Fluids from Subsurface Reservoirs Using Electric Submersible Pumps

Abstract

Systems and methods for producing fluid from a well can use an electric submersible pump. These approaches can include: performing a portable separator rate test in the well to obtain an operating point for the electric submersible pump in the well; receiving a performance curve for the electric submersible pump; adjusting the performance curve for the electric submersible pump based on specific gravity and viscosity of fluid being produced from the well; calculating a head correction necessary to shift the adjusted performance curve to pass through the operating point obtained from the portable separator rate test; updating a model of the electric submersible pump by incorporating the calculated head correction; and executing the model of the electric submersible pump to predict flow rates from the well at surface conditions.

Description

TECHNICAL FIELD

[0001] This specification relates to producing fluids from subsurface reservoirs using electric submersible pumps (ESPs).BACKGROUND

[0002] ESPs are efficient and reliable artificial-lift tools for lifting high volumes of fluids from wellbores. ESPs have been used to produce fluids from reservoirs containing hydrocarbons.SUMMARY

[0003] This specification describes an approach to producing fluids from reservoirs (e.g., reservoirs containing hydrocarbons) using ESPs. This approach incorporates systems and methods calculating head deterioration in ESPs due to mechanical wear, accounting for pump head curve performance deviations, and improving ESP monitoring. These systems and methods are based on experimental data from portable separator rate tests and ESP sensor data and account for variables such as pump intake and discharge pressure and frequency during testing. Using this approach, the systems can estimate water cut and fluid specific gravity which are then used generate flow rate based on ESP downhole sensor data and using oil field correlation for head deration caused by mechanical wear.

[0004] This approach evaluates intake and discharge pressures against choke settings to control draw-down, considering factors like Delta P, pump ratings, motor loading, and well inflow for improved ESP management. By integrating manufacturer pump curves, the system keeps wells operating within desired ranges, thereby extending equipment lifespan. It facilitates quick adjustments such as choke size changes to adapt to changing ESP conditions. By addressing issues of low motor load in some wells, the system rerates motors by adjusting voltage, thus enhancing motor load and allowing previously non-operational wells to function.

[0005] The details of one or more embodiments of the invention are set forth in the accompanying drawings and the description below. Other features, objects, and advantages of the invention will be apparent from the description and drawings, and from the claims.DESCRIPTION OF DRAWINGS

[0006] FIG. 1 is a schematic view of exploration and production activities being performed in a subsurface formation.

[0007] FIG. 2 is a schematic illustrating a ESP monitoring and control system.

[0008] FIG. 3 is flow chart of a method of producing hydrocarbons using an ESP monitoring and control system.

[0009] FIG. 4 illustrates an ESP pump curve modified using oil field correction for head deration caused by mechanical wear.

[0010] FIG. 5 illustrates the relationship between ESP run life and % deviation.

[0011] FIGS. 6A-6C illustrate a prototype ESP monitoring and control system.

[0012] FIG. 7 illustrates hydrocarbon production operations.

[0013] FIG. 8 is a block diagram of an example computer system.

[0014] Like reference symbols in the various drawings indicate like elements.DETAILED DESCRIPTION

[0015] This specification describes an approach to producing fluids from reservoirs (e.g., reservoirs containing hydrocarbons) using ESPs. This approach incorporates systems and methods calculating head deterioration in ESPs due to mechanical wear, accounting for pump head curve performance deviations, and improving ESP monitoring. These systems and methods are based on experimental data from portable separator rate tests and ESP sensor data and account for variables such as pump intake and discharge pressure and frequency during testing. Using this approach, the systems can estimate water cut and fluid specific gravity which are then used generate flow rate based on ESP downhole sensor data and using oil field correlation for head deration caused by mechanical wear.

[0016] The systems and methods disclosed in this specification can be used for monitoring and controlling ESPs. They integrate a field correlation and ESP parameters into a unified system. This system, underpinned by the new methodology, offers diagnostic capabilities, production optimization, and ESP well tracking. It provides a comprehensive field overview of all ESP wells simultaneously, identifying wells requiring intervention, optimization, or replacement. The system provides a dynamic and interactive graphical user interface, offering a holistic view of all ESP wells with three primary modules.

[0017] FIG. 1 is a schematic view of operations being performed in a subsurface formation 100. These includes exploration operations as well as production operations using ESPs to produce fluids from the subsurface formation.

[0018] The subsurface formation 100 includes a layer of impermeable cap rock 102 at the surface. Facies underlying the impermeable cap rocks 102 include three layers 104, 106, and 108. A fault line 110 extends across the layer 104 and the layer 106.

[0019] Oil and gas tend to rise through permeable reservoir rock until further upward migration is blocked, for example, by the layer of impermeable cap rock 102. Seismic surveys attempt to identify locations where interaction between layers of the subsurface formation 100 are likely to trap oil and gas by limiting this upward migration. For example, FIG. 1 shows an anticline trap 107, where the layer of impermeable cap rock 102 has an upward convex configuration, and a fault trap 109, where the fault line 110 might allow oil and gas to flow in with clay material between the walls traps the petroleum. Other traps include salt domes and stratigraphic traps.

[0020] A seismic source 112 (for example, a seismic vibrator or an explosion) generates seismic waves that propagate in the earth. Although illustrated as a single component in FIG. 1, the source or sources 112 are typically a line or an array of sources 112. The generated seismic waves include seismic body waves 114 that travel into the ground and seismic surface waves 115 travel along the ground surface and diminish as they get further from the surface. As the seismic body waves 114 contact interfaces between geologic bodies or layers that have different velocities, each interface reflects some of the energy of the seismic wave and refracts some of the energy of the seismic wave. Such interfaces are sometimes referred to as horizons.

[0021] The seismic body waves 114 are received by a sensor or sensors 116. Although illustrated as a single component in FIG. 1, the sensor or sensors 116 are typically a line or an array of sensors 116 that generate an output signal in response to received seismic waves including waves reflected by the horizons in the subsurface formation 100. The sensors 116 can be geophone-receivers that produce electrical output signals transmitted as input data, for example, to a computer 118 on a seismic control truck 120. Based on the input data, the computer 118 may generate a seismic data output, for example, a seismic two-way response time plot.

[0022] A control center 122 can be operatively coupled to the seismic control truck 120 and other data acquisition and wellsite systems. The control center 122 may have computer facilities for receiving, storing, processing, and analyzing data from the seismic control truck 120 and other data acquisition and wellsite systems that provide additional information about the subsurface formation. For example, the control center 122 can receive data from a computer 119 associated with a well logging unit 121.

[0023] The computer systems 124 can be located in a different location than the control center 122. Some computer systems are provided with functionality for manipulating and analyzing the data, such as performing seismic interpretation or borehole resistivity image log interpretation to identify geological surfaces in the subsurface formation or performing simulation, planning, and optimization of production operations of the wellsite systems.

[0024] In some embodiments, a wellbore 130 that has been drilled in the subsurface formation 100 is logged in a well logging operation 128. The wellbore 130 extends downhole from a wellhead 132. The wellbore 130 is a vertical wellbore but well logging can also be performed in other wellbores, for example, slanted or horizontal wellbores. In the well logging operation 128, the wellbore 130 penetrates through three layers 102, 104, and 106 of a subsurface formation 100. A control truck 121 lowers a logging tool 134 down the wellbore 130 on a wireline 136.

[0025] The computer systems 124 in the control center 122 can be configured to analyze, model, control, optimize, or perform management tasks of field operations associated with development and production of resources such as oil and gas from the subsurface formation 100. For example, an injection well 123 and a production well 125 extend into layer 104 of the subsurface formation 100. An ESP 126 installed in the production well 125 is operated to produce fluids from layer 104 of the subsurface formation 100. Based on data gathered by the exploratory field operations, the computer systems 124 can generate models such as a reservoir model for portions of the subsurface formation 100. These models can simulate the effects of production field operations (e.g., injecting water or carbon dioxide through the injection well 123 to increase the production of hydrocarbons through the production well 125). The simulations can be used to plan and, in some instances, control field operations (e.g., the operation of pumps associated with the injection well 123 and the production well 125). This specification describes an approach to monitoring and controlling ESPs that accounts for head deterioration (e.g., head deterioration caused by mechanical wear).

[0026] FIG. 2 is a schematic illustrating a ESP monitoring and control system 200. In some instances, the ESP monitoring and control system 200 is implemented on the computer systems 124 in the control center 122. In some instances, the ESP monitoring control system 200 is implemented on separate computer systems, for example, standalone computer systems located in the vicinity of ESPs being used for production of fluids from the subsurface formation 100.

[0027] The ESP monitoring and control system 200 includes an ESP modeling module 210, a head derating module 212, and a display module 214 that integrate ESP parameters and variables in one system. The ESP monitoring and control system 200 is in electronic communication (e.g., wired or wireless electronic communication) with ESPs 216, downhole sensors 218, and surface units 220. Typical downhole sensors 218 measure parameters such as pump intake and discharge pressure and temperature, vibration, current leaks and typical surface units 220 measure parameters such as wellhead temperature, pressure, and chemical injection rates.

[0028] Communication between the ESP monitoring and control system 200 and the ESPs 216 can include, for example, operational data (e.g., wellhead variables such as temperature, pressure, chemical injection rates; electrical variables such as motor current consumption and voltage; and down hole variables such as pump intake and discharge pressure and temperature, vibration, and current leaks) sent from the ESPs 216 to the ESP monitoring control system 200 and control signals sent from the ESP monitoring and control system 200 to the ESPs 216. Communication between the ESP monitoring and control system 200 and the downhole sensors 218 can include, for example, pressure, temperature, and fluid properties measured by the downhole sensors 218 and sent from the downhole sensors 218 to the ESP monitoring control system 200 as well as control signals sent from the ESP monitoring and control system 200 to the downhole sensors 218. Communication between the ESP monitoring and control system 200 and the surface units 220 can include, for example, operational data sent from the surface units 220 to the ESP monitoring control system 200 and control signals sent from the ESP monitoring and control system 200 to the surface units 220.

[0029] A database 222 is electronic communication with the ESP monitoring and control system 200, the ESPs 216, the downhole sensors 218, and the surface units 220. The database 222 stores information including, for example, downhole sensor data, fluid properties, electrical readings, and manufacturer-provided ESP curves. The database also receives and stores the results operational tests such as portable separator rate tests performed in the field.

[0030] Based on information received from the ESPs 216, the downhole sensors 218, the surface units 220, and the database 222, the ESP monitoring and control system 200 models ESP and well performance. It also provides historical matching with rate tests, streamlined ESP diagnostics, and decision-making across the ESP's operational lifespan.

[0031] The ESP modeling module 210 provides real-time diagnostic capabilities, production optimization, and proactive tracking of ESP well conditions prior to any trip or failure. Utilizing scatter plots and visual basic software, it models current ESP production rates and combines various well variables. This allows for interventions such as ESP replacement, system upgrades or downgrades, choke valve adjustments, and optimization for wells with poor reservoir inflow or those running under optimal conditions. The ESP modeling module 210 periodically updates the underlying ESP model using a head correction factor generated by the head derating module 212.

[0032] The ESP modeling module 210 considers variables like pump intake and discharge pressure and frequency during testing, emphasizes the alignment of operational points with the catalogue curve and recognizes potential influences such as measurement errors, pump wear, and fluid property deviations. After model updates to incorporate the head correction factor, the ESP modeling module 210 can be used to estimate water cut and fluid specific gravity and generate flow rate based on ESP downhole sensor data and using oil field correlation for head deration caused by mechanical wear.

[0033] When portable separator rate tests are performed, the head derating module 212 uses the results of these tests and associated fluid properties measurements to adjust a pump performance curve (e.g., a manufacturer's pump performance retrieved from the database 222) to calculate a head correction factor reflecting current pump performance as impacted by head deterioration in ESPs caused by mechanical wear. The head correction factor calculated by the head derating module 212 is transferred to the ESP modeling module 210 which uses them to update the underlying ESP model using a head correction factor generated by the head derating module 212.

[0034] The display module 214 of the ESP monitoring and control system 200 is a graphical user interface which provides a comprehensive field overview, displaying multiple ESP wells simultaneously. The system significantly improves ESP turnaround through performance forecasting and a detailed equipment availability catalog.

[0035] FIG. 3 is flow chart of a method 300 of producing hydrocarbons from a well using an ESP monitoring and control system accounting for gradual deterioration of pump performance due to mechanical wear (e.g., the ESP monitoring and control system 200). The method 300 reflects the impact of the gradual deterioration of pump performance due to mechanical wear by incorporating calculation of the head correction factor.

[0036] A portable separator rate test is performed at the well to obtain an operating point for the electric submersible pump in the well (step 310). Portable separator tests can provide an accurate measurement of the fluid production rates and are used by petroleum engineers and field technicians to analyze and understand the behavior and characteristics of oil and gas wells. Portable separator tests specifically is a method that brings a high level of flexibility and efficiency to this process. Well testing, helps in evaluating the performance of a well and the field at large. The portable separator tests are distinguished by their use of a mobile unit that can be transported and set up at different well sites as needed. This flexibility is particularly useful in fields where permanent facilities are not yet established or where wells are spread out over a large area. The test separator works by taking a sample of the well's output and dividing it into its three main constituents: oil, gas, and water. This separation is crucial because it allows for the precise measurement of the flow rates of each phase of the output, information which is vital for understanding the well's behavior and for making informed decisions about its management. These devices measure the volume of oil, gas, and water separately with high precision, which is essential for reliable data analysis. The calibration of these meters is performed under controlled conditions to ensure that they provide accurate readings when deployed in the field.

[0037] A performance curve for the electric submersible pump is retrieved (step 312). ESPs have nominal pump performance curves. These nominal curves are typically provided by the manufacturer and are based on a standard fluid specific gravity of 1.0. As new ESPs are installed in a field, the associated pump performance curve can be stored the database 222 and retrieved by the ESP monitoring and control system 200 as part of the approach to updating a ESP model to reflect deteriorating pump performance. After retrieval, the nominal performance curve for the electric submersible pump is adjusted based on specific gravity and viscosity of fluid being produced from the well (step 314). The specific gravity and viscosity of fluid being produced from the well can be retrieved from database and / or received real-time from sensors.

[0038] A head correction necessary to shift the adjusted performance curve to pass through the operating point obtained from the portable separator rate test is calculated (step 316). The head correction can be calculated as a ratio between the retrieved pump curve and the adjusted pump curve. The calculation of this ratio can be done graphically or numerically.

[0039] FIG. 4 illustrates an ESP pump curve modified using oil field correction for head deration caused by mechanical wear before and after a shift to pass through the operating point obtained from the portable separator rate test. The adjusted pump curve 410 and the operating point 412 determined by the portable separator rate test are plotted together. The adjusted performance curve 410 is shifted vertically and horizontal to pass through the operating point 412 providing a shifted pump curve 414. The ratio necessary to provide this shift is the head correction used in this approach.

[0040] Referring again to FIG. 3, the head correction is used to update a model of the electric submersible pump (step 318). The updated model of the electric submersible pump is then executed to predict flow rates from the well at surface conditions (step 320). Optionally, the model results can be used to control the electric submersible pump based on the predicted flow rates (step 322).

[0041] FIG. 5 illustrates the significance of accounting for the mechanical wear on pump performance. FIG. 5 shows the percentage deviation between the portable rate test and the calculated flow rate against the ESP's operational lifespan for over 100 real data points from various oil fields and different pump curves. This chart reveals a correlation between increased ESP run life and greater deviation between the portable separator rate test and the flow rate calculated using downhole sensor data. This finding underscores the importance of ESP run life in applying accurate head deterioration corrections and achieving reliable values.

[0042] FIGS. 6A-6C illustrate a prototype ESP monitoring and control system. FIG. 6A is a screenshot of an oil field overview interface 600. The oil field overview interface 600 displays motor loading 610, well status 612, pump model 614, smart functions 616, pump status 618, delta P at the surface 620, a well productivity index 622, an estimated production rate 624, a pump rating summary 626, and the total production rate for the field 628. The oil field overview interface 600 can be used to identify wells to optimize by relaxing or restricting the choke valves, wells with poor inflow from reservoir and optimized wells, running on optimal conditions, wells to up-grade or down-grade the ESP system, and wells to intervene with rig to replace the ESP.

[0043] FIG. 6B is a screenshot of a well gauges interface 640. The well gauges interface 640 displays a downhole motor load gauge 642, an operational pump condition gauge 644, a pressure delta gauge 646, an amperage gauge 648 of the selected ESP, a flow rate gauge 650 for the selected ESP, and a dropdown menu 652 for selection of a specific well. These five gauges can be used to monitor production rate performance, ESP motor performance, and surface pressure performance.

[0044] The amperage 648 of the selected ESP is based on the name plate amperage of the selected pump with the green zone indicating the normal operational zone. If the well is operating close to the red zone, there is potential for a tripped well due to underload. The motor loading gauge shows the amperage percentage consumption as a function of name plate motor for the selected ESP.

[0045] The flow rate gauge 650 shows the pump range envelop (indicated by the green zone) with the red zone indicating when the ESP is running on upthrust (i.e., above the maximum pump capacity) or on downthrust (i.e., below the minimum pump capacity). The displayed flow rates reflect the head derating correction calculated, for example, by the method 300. Downthrust increases as the flow through the stage decreases (e.g., on the left-hand side of the pump curve). Upthrust increases as the flow through the stage increases (e.g., on the right-hand side of the pump curve). Flow rates to the left of the operating range will increase wear on the downthrust washers. Flows to the right of the operating range will cause wear on the upthrust washers. By keeping wells on range according to the ESP catalog, the ESP system can help extend the run life of the ESPs.

[0046] FIG. 6C is a screenshot of a well history interface 670. The well history interface 670 displays historical data from a selected well including micromotion 672, pressure 674, downhole sensor readings 676, and motor electrical readings 678. This ESP historical data can be used to predict failures and trips. The well history interface 670 can show the complete well history or selected periods.

[0047] Leveraging the head derating factor, the prototype ESP monitoring and control system achieved a closer alignment between downhole and portable separator rate test results—slashing the deviation from 14% to 6%. Table 1 presents the deviation between downhole and portable separator rate test results using the described head derating approach using the prototype ESP monitoring and control system.

[0048] The resultant ESP model, grounded in this approach, provides precise historical matches to conducted rate tests, refining ESP diagnostics and decision-making throughout its lifecycle. This enhances ESP turnaround, empowering users with performance forecasting and facilitating equipment planning.TABLE 1DeviationHeadDeviationBefore ApplyDeratingafter applyWellHDFFactorHDFWell A20%0.877%Well B16%0.9510% Well C10%0.943%Well D15%0.927%Well E 1%1.000%Well F17%0.883%Well G17%0.8913% Average14%6%Hydrocarbon Operations

[0049] FIG. 7 illustrates hydrocarbon production operations 700 that include both one or more field operations 710 and one or more computational operations 712, which exchange information and control exploration for the production of hydrocarbons. In some implementations, outputs of techniques of the present disclosure can be performed before, during, or in combination with the hydrocarbon production operations 700, specifically, for example, either as field operations 710 or computational operations 712, or both.

[0050] Examples of field operations 710 include forming / drilling a wellbore, hydraulic fracturing, producing through the wellbore, injecting fluids (such as water) through the wellbore, to name a few. In some implementations, methods of the present disclosure can trigger or control the field operations 710. For example, the methods of the present disclosure can generate data from hardware / software including sensors and physical data gathering equipment (e.g., seismic sensors, well logging tools, flow meters, and temperature and pressure sensors). The methods of the present disclosure can include transmitting the data from the hardware / software to the field operations 710 and responsively triggering the field operations 710 including, for example, generating plans and signals that provide feedback to and control physical components of the field operations 710. Alternatively or in addition, the field operations 710 can trigger the methods of the present disclosure. For example, implementing physical components (including, for example, hardware, such as sensors) deployed in the field operations 710 can generate plans and signals that can be provided as input or feedback (or both) to the methods of the present disclosure.

[0051] Examples of computational operations 712 include one or more computer systems 720 that include one or more processors and computer-readable media (e.g., non-transitory computer-readable media) operatively coupled to the one or more processors to execute computer operations to perform the methods of the present disclosure. The computational operations 712 can be implemented using one or more databases 718, which store data received from the field operations 710 and / or generated internally within the computational operations 712 (e.g., by implementing the methods of the present disclosure) or both. For example, the one or more computer systems 720 process inputs from the field operations 710 to assess conditions in the physical world, the outputs of which are stored in the databases 718. For example, seismic sensors of the field operations 710 can be used to perform a seismic survey to map subterranean features, such as facies and faults. In performing a seismic survey, seismic sources (e.g., seismic vibrators or explosions) generate seismic waves that propagate in the earth and seismic receivers (e.g., geophones) measure reflections generated as the seismic waves interact with boundaries between layers of a subsurface formation. The source and received signals are provided to the computational operations 712 where they are stored in the databases 718 and analyzed by the one or more computer systems 720.

[0052] In some implementations, one or more outputs 722 generated by the one or more computer systems 720 can be provided as feedback / input to the field operations 710 (either as direct input or stored in the databases 718). The field operations 710 can use the feedback / input to control physical components used to perform the field operations 710 in the real world.

[0053] For example, the computational operations 712 can process the seismic data to generate three-dimensional (3D) maps of the subsurface formation. The computational operations 712 can use these 3D maps to provide plans for locating and drilling exploratory wells. In some operations, the exploratory wells are drilled using logging-while-drilling (LWD) techniques which incorporate logging tools into the drill string. LWD techniques can enable the computational operations 712 to process new information about the formation and control the drilling to adjust to the observed conditions in real-time.

[0054] The one or more computer systems 720 can update the 3D maps of the subsurface formation as information from one exploration well is received and the computational operations 712 can adjust the location of the next exploration well based on the updated 3D maps. Similarly, the data received from production operations can be used by the computational operations 712 to control components of the production operations. For example, production well and pipeline data can be analyzed to predict slugging in pipelines leading to a refinery and the computational operations 712 can control machine operated valves upstream of the refinery to reduce the likelihood of plant disruptions that run the risk of taking the plant offline.

[0055] In some implementations of the computational operations 712, customized user interfaces can present intermediate or final results of the above-described processes to a user. Information can be presented in one or more textual, tabular, or graphical formats, such as through a dashboard. The information can be presented at one or more on-site locations (such as at an oil well or other facility), on the Internet (such as on a webpage), on a mobile application (or app), or at a central processing facility.

[0056] The presented information can include feedback, such as changes in parameters or processing inputs, that the user can select to improve a production environment, such as in the exploration, production, and / or testing of petrochemical processes or facilities. For example, the feedback can include parameters that, when selected by the user, can cause a change to, or an improvement in, drilling parameters (including drill bit speed and direction) or overall production of a gas or oil well. The feedback, when implemented by the user, can improve the speed and accuracy of calculations, streamline processes, improve models, and solve problems related to efficiency, performance, safety, reliability, costs, downtime, and the need for human interaction.

[0057] In some implementations, the feedback can be implemented in real-time, such as to provide an immediate or near-immediate change in operations or in a model. The term real-time (or similar terms as understood by one of ordinary skill in the art) means that an action and a response are temporally proximate such that an individual perceives the action and the response occurring substantially simultaneously. For example, the time difference for a response to display (or for an initiation of a display) of data following the individual's action to access the data can be less than 1 millisecond (ms), less than 1 second(s), or less than 5 s. While the requested data need not be displayed (or initiated for display) instantaneously, it is displayed (or initiated for display) without any intentional delay, taking into account processing limitations of a described computing system and time required to, for example, gather, accurately measure, analyze, process, store, or transmit the data.

[0058] Events can include readings or measurements captured by downhole equipment such as sensors, pumps, bottom hole assemblies, or other equipment. The readings or measurements can be analyzed at the surface, such as by using applications that can include modeling applications and machine learning. The analysis can be used to generate changes to settings of downhole equipment, such as drilling equipment. In some implementations, values of parameters or other variables that are determined can be used automatically (such as through using rules) to implement changes in oil or gas well exploration, production / drilling, or testing. For example, outputs of the present disclosure can be used as inputs to other equipment and / or systems at a facility. This can be especially useful for systems or various pieces of equipment that are located several meters or several miles apart, or are located in different countries or other jurisdictions.

[0059] FIG. 8 is a block diagram of an example computer system 800 used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures described in the present disclosure, according to some implementations of the present disclosure. The illustrated computer 802 is intended to encompass any computing device such as a server, a desktop computer, a laptop / notebook computer, a wireless data port, a smart phone, a personal data assistant (PDA), a tablet computing device, or one or more processors within these devices, including physical instances, virtual instances, or both. The computer 802 can include input devices such as keypads, keyboards, and touch screens that can accept user information. Also, the computer 802 can include output devices that can convey information associated with the operation of the computer 802. The information can include digital data, visual data, audio information, or a combination of information. The information can be presented in a graphical user interface (UI) (or GUI).

[0060] The computer 802 can serve in a role as a client, a network component, a server, a database, a persistency, or components of a computer system for performing the subject matter described in the present disclosure. The illustrated computer 802 is communicably coupled with a network 830. In some implementations, one or more components of the computer 802 can be configured to operate within different environments, including cloud-computing-based environments, local environments, global environments, and combinations of environments.

[0061] At a high level, the computer 802 is an electronic computing device operable to receive, transmit, process, store, and manage data and information associated with the described subject matter. According to some implementations, the computer 802 can also include, or be communicably coupled with, an application server, an email server, a web server, a caching server, a streaming data server, or a combination of servers.

[0062] The computer 802 can receive requests over network 830 from a client application (for example, executing on another computer 802). The computer 802 can respond to the received requests by processing the received requests using software applications. Requests can also be sent to the computer 802 from internal users (for example, from a command console), external (or third) parties, automated applications, entities, individuals, systems, and computers.

[0063] Each of the components of the computer 802 can communicate using a system bus 803. In some implementations, any or all of the components of the computer 802, including hardware or software components, can interface with each other or the interface 804 (or a combination of both), over the system bus 803. Interfaces can use an application programming interface (API) 812, a service layer 813, or a combination of the API 812 and service layer 813. The API 812 can include specifications for routines, data structures, and object classes. The API 812 can be either computer-language independent or dependent. The API 812 can refer to a complete interface, a single function, or a set of APIs.

[0064] The service layer 813 can provide software services to the computer 802 and other components (whether illustrated or not) that are communicably coupled to the computer 802. The functionality of the computer 802 can be accessible for all service consumers using this service layer. Software services, such as those provided by the service layer 813, can provide reusable, defined functionalities through a defined interface. For example, the interface can be software written in JAVA, C++, or a language providing data in extensible markup language (XML) format. While illustrated as an integrated component of the computer 802, in alternative implementations, the API 812 or the service layer 813 can be stand-alone components in relation to other components of the computer 802 and other components communicably coupled to the computer 802. Moreover, any or all parts of the API 812 or the service layer 813 can be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of the present disclosure.

[0065] The computer 802 includes an interface 804. Although illustrated as a single interface 804 in FIG. 8, two or more interfaces 804 can be used according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. The interface 804 can be used by the computer 802 for communicating with other systems that are connected to the network 830 (whether illustrated or not) in a distributed environment. Generally, the interface 804 can include, or be implemented using, logic encoded in software or hardware (or a combination of software and hardware) operable to communicate with the network 830. More specifically, the interface 804 can include software supporting one or more communication protocols associated with communications. As such, the network 830 or the hardware of the interface can be operable to communicate physical signals within and outside of the illustrated computer 802.

[0066] The computer 802 includes a processor 805. Although illustrated as a single processor 805 in FIG. 8, two or more processors 805 can be used according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. Generally, the processor 805 can execute instructions and can manipulate data to perform the operations of the computer 802, including operations using algorithms, methods, functions, processes, flows, and procedures as described in the present disclosure.

[0067] The computer 802 also includes a database 806 that can hold data (for example, seismic data 816) for the computer 802 and other components connected to the network 830 (whether illustrated or not). For example, database 806 can be an in-memory, conventional, or a database storing data consistent with the present disclosure. In some implementations, database 806 can be a combination of two or more different database types (for example, hybrid in-memory and conventional databases) according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. Although illustrated as a single database 806 in FIG. 8, two or more databases (of the same, different, or combination of types) can be used according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. While database 806 is illustrated as an internal component of the computer 802, in alternative implementations, database 806 can be external to the computer 802.

[0068] The computer 802 also includes a memory 807 that can hold data for the computer 802 or a combination of components connected to the network 830 (whether illustrated or not). Memory 807 can store any data consistent with the present disclosure. In some implementations, memory 807 can be a combination of two or more different types of memory (for example, a combination of semiconductor and magnetic storage) according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. Although illustrated as a single memory 807 in FIG. 8, two or more memories 807 (of the same, different, or combination of types) can be used according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. While memory 807 is illustrated as an internal component of the computer 802, in alternative implementations, memory 807 can be external to the computer 802.

[0069] The application 808 can be an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. For example, application 808 can serve as one or more components, modules, or applications. Further, although illustrated as a single application 808, the application 808 can be implemented as multiple applications 808 on the computer 802. In addition, although illustrated as internal to the computer 802, in alternative implementations, the application 808 can be external to the computer 802.

[0070] The computer 802 can also include a power supply 814. The power supply 814 can include a rechargeable or non-rechargeable battery that can be configured to be either user- or non-user-replaceable. In some implementations, the power supply 814 can include power-conversion and management circuits, including recharging, standby, and power management functionalities. In some implementations, the power-supply 814 can include a power plug to allow the computer 802 to be plugged into a wall socket or a power source to, for example, power the computer 802 or recharge a rechargeable battery.

[0071] There can be any number of computers 802 associated with, or external to, a computer system containing computer 802, with each computer 802 communicating over network 830. Further, the terms “client,”“user,” and other appropriate terminology can be used interchangeably, as appropriate, without departing from the scope of the present disclosure. Moreover, the present disclosure contemplates that many users can use one computer 802 and one user can use multiple computers 802.

[0072] Implementations of the subject matter and the functional operations described in this specification can be implemented in digital electronic circuitry, in tangibly embodied computer software or firmware, in computer hardware, including the structures disclosed in this specification and their structural equivalents, or in combinations of one or more of them. Software implementations of the described subject matter can be implemented as one or more computer programs. Each computer program can include one or more modules of computer program instructions encoded on a tangible, non transitory, computer-readable computer-storage medium for execution by, or to control the operation of, data processing apparatus. Alternatively, or additionally, the program instructions can be encoded in / on an artificially generated propagated signal. The example, the signal can be a machine-generated electrical, optical, or electromagnetic signal that is generated to encode information for transmission to suitable receiver apparatus for execution by a data processing apparatus. The computer-storage medium can be a machine-readable storage device, a machine-readable storage substrate, a random or serial access memory device, or a combination of computer-storage mediums.

[0073] The terms “data processing apparatus,”“computer,” and “electronic computer device” (or equivalent as understood by one of ordinary skill in the art) refer to data processing hardware. For example, a data processing apparatus can encompass all kinds of apparatus, devices, and machines for processing data, including by way of example, a programmable processor, a computer, or multiple processors or computers. The apparatus can also include special purpose logic circuitry including, for example, a central processing unit (CPU), a field programmable gate array (FPGA), or an application specific integrated circuit (ASIC). In some implementations, the data processing apparatus or special purpose logic circuitry (or a combination of the data processing apparatus or special purpose logic circuitry) can be hardware- or software-based (or a combination of both hardware- and software-based). The apparatus can optionally include code that creates an execution environment for computer programs, for example, code that constitutes processor firmware, a protocol stack, a database management system, an operating system, or a combination of execution environments. The present disclosure contemplates the use of data processing apparatuses with or without conventional operating systems, for example, LINUX, UNIX, WINDOWS, MAC OS, ANDROID, or IOS.

[0074] A computer program, which can also be referred to or described as a program, software, a software application, a module, a software module, a script, or code, can be written in any form of programming language. Programming languages can include, for example, compiled languages, interpreted languages, declarative languages, or procedural languages. Programs can be deployed in any form, including as stand-alone programs, modules, components, subroutines, or units for use in a computing environment. A computer program can, but need not, correspond to a file in a file system. A program can be stored in a portion of a file that holds other programs or data, for example, one or more scripts stored in a markup language document, in a single file dedicated to the program in question, or in multiple coordinated files storing one or more modules, sub programs, or portions of code. A computer program can be deployed for execution on one computer or on multiple computers that are located, for example, at one site or distributed across multiple sites that are interconnected by a communication network. While portions of the programs illustrated in the various figures may be shown as individual modules that implement the various features and functionality through various objects, methods, or processes, the programs can instead include a number of sub-modules, third-party services, components, and libraries. Conversely, the features and functionality of various components can be combined into single components as appropriate. Thresholds used to make computational determinations can be statically, dynamically, or both statically and dynamically determined.

[0075] The methods, processes, or logic flows described in this specification can be performed by one or more programmable computers executing one or more computer programs to perform functions by operating on input data and generating output. The methods, processes, or logic flows can also be performed by, and apparatus can also be implemented as, special purpose logic circuitry, for example, a CPU, an FPGA, or an ASIC.

[0076] Computers suitable for the execution of a computer program can be based on one or more of general and special purpose microprocessors and other kinds of CPUs. The elements of a computer are a CPU for performing or executing instructions and one or more memory devices for storing instructions and data. Generally, a CPU can receive instructions and data from (and write data to) a memory. A computer can also include, or be operatively coupled to, one or more mass storage devices for storing data. In some implementations, a computer can receive data from, and transfer data to, the mass storage devices including, for example, magnetic, magneto optical disks, or optical disks. Moreover, a computer can be embedded in another device, for example, a mobile telephone, a personal digital assistant (PDA), a mobile audio or video player, a game console, a global positioning system (GPS) receiver, or a portable storage device such as a universal serial bus (USB) flash drive.

[0077] Computer readable media (transitory or non-transitory, as appropriate) suitable for storing computer program instructions and data can include all forms of permanent / non-permanent and volatile / non-volatile memory, media, and memory devices. Computer readable media can include, for example, semiconductor memory devices such as random access memory (RAM), read only memory (ROM), phase change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), and flash memory devices. Computer readable media can also include, for example, magnetic devices such as tape, cartridges, cassettes, and internal / removable disks. Computer readable media can also include magneto optical disks and optical memory devices and technologies including, for example, digital video disc (DVD), CD ROM, DVD+ / −R, DVD-RAM, DVD-ROM, HD-DVD, and BLURAY. The memory can store various objects or data, including caches, classes, frameworks, applications, modules, backup data, jobs, web pages, web page templates, data structures, database tables, repositories, and dynamic information. Types of objects and data stored in memory can include parameters, variables, algorithms, instructions, rules, constraints, and references. Additionally, the memory can include logs, policies, security or access data, and reporting files. The processor and the memory can be supplemented by, or incorporated in, special purpose logic circuitry.

[0078] Implementations of the subject matter described in the present disclosure can be implemented on a computer having a display device for providing interaction with a user, including displaying information to (and receiving input from) the user. Types of display devices can include, for example, a cathode ray tube (CRT), a liquid crystal display (LCD), a light-emitting diode (LED), and a plasma monitor. Display devices can include a keyboard and pointing devices including, for example, a mouse, a trackball, or a trackpad. User input can also be provided to the computer through the use of a touchscreen, such as a tablet computer surface with pressure sensitivity or a multi-touch screen using capacitive or electric sensing. Other kinds of devices can be used to provide for interaction with a user, including to receive user feedback including, for example, sensory feedback including visual feedback, auditory feedback, or tactile feedback. Input from the user can be received in the form of acoustic, speech, or tactile input. In addition, a computer can interact with a user by sending documents to, and receiving documents from, a device that is used by the user. For example, the computer can send web pages to a web browser on a user's client device in response to requests received from the web browser.

[0079] The term “graphical user interface,” or “GUI,” can be used in the singular or the plural to describe one or more graphical user interfaces and each of the displays of a particular graphical user interface. Therefore, a GUI can represent any graphical user interface, including, but not limited to, a web browser, a touch screen, or a command line interface (CLI) that processes information and efficiently presents the information results to the user. In general, a GUI can include a plurality of user interface (UI) elements, some or all associated with a web browser, such as interactive fields, pull-down lists, and buttons. These and other UI elements can be related to or represent the functions of the web browser.

[0080] Implementations of the subject matter described in this specification can be implemented in a computing system that includes a back end component, for example, as a data server, or that includes a middleware component, for example, an application server. Moreover, the computing system can include a front-end component, for example, a client computer having one or both of a graphical user interface or a Web browser through which a user can interact with the computer. The components of the system can be interconnected by any form or medium of wireline or wireless digital data communication (or a combination of data communication) in a communication network. Examples of communication networks include a local area network (LAN), a radio access network (RAN), a metropolitan area network (MAN), a wide area network (WAN), Worldwide Interoperability for Microwave Access (WIMAX), a wireless local area network (WLAN) (for example, using 802.11 a / b / g / n or 802.20 or a combination of protocols), all or a portion of the Internet, or any other communication system or systems at one or more locations (or a combination of communication networks). The network can communicate with, for example, Internet Protocol (IP) packets, frame relay frames, asynchronous transfer mode (ATM) cells, voice, video, data, or a combination of communication types between network addresses.

[0081] The computing system can include clients and servers. A client and server can generally be remote from each other and can typically interact through a communication network. The relationship of client and server can arise by virtue of computer programs running on the respective computers and having a client-server relationship.

[0082] Cluster file systems can be any file system type accessible from multiple servers for read and update. Locking or consistency tracking may not be necessary since the locking of exchange file system can be done at application layer. Furthermore, Unicode data files can be different from non-Unicode data files.

[0083] While this specification contains many specific implementation details, these should not be construed as limitations on the scope of what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features that are described in this specification in the context of separate implementations can also be implemented, in combination, in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations, separately, or in any suitable sub-combination. Moreover, although previously described features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can, in some cases, be excised from the combination, and the claimed combination may be directed to a sub-combination or variation of a sub-combination.

[0084] Particular implementations of the subject matter have been described. Other implementations, alterations, and permutations of the described implementations are within the scope of the following claims as will be apparent to those skilled in the art. While operations are depicted in the drawings or claims in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed (some operations may be considered optional), to achieve desirable results. In certain circumstances, multitasking or parallel processing (or a combination of multitasking and parallel processing) may be advantageous and performed as deemed appropriate.

[0085] Moreover, the separation or integration of various system modules and components in the previously described implementations should not be understood as requiring such separation or integration in all implementations, and it should be understood that the described program components and systems can generally be integrated together in a single software product or packaged into multiple software products.

[0086] Accordingly, the previously described example implementations do not define or constrain the present disclosure. Other changes, substitutions, and alterations are also possible without departing from the spirit and scope of the present disclosure.

[0087] Furthermore, any claimed implementation is considered to be applicable to at least a computer-implemented method; a non-transitory, computer-readable medium storing computer-readable instructions to perform the computer-implemented method; and a computer system comprising a computer memory interoperably coupled with a hardware processor configured to perform the computer-implemented method or the instructions stored on the non-transitory, computer-readable medium.Examples

[0088] In some implementations, methods for producing fluid from a well using an electric submersible pump include: performing a portable separator rate test in the well to obtain an operating point for the electric submersible pump in the well; receiving a performance curve for the electric submersible pump; adjusting the performance curve for the electric submersible pump based on specific gravity and viscosity of fluid being produced from the well; calculating a head correction necessary to shift the adjusted performance curve to pass through the operating point obtained from the portable separator rate test; updating a model of the electric submersible pump by incorporating the calculated head correction; and executing the model of the electric submersible pump to predict flow rates from the well at surface conditions.

[0089] In some implementations, methods for producing fluid from a well using an electric submersible pump include: receiving, by a processor, results of a portable separator rate test in the well to obtain an operating point for the electric submersible pump in the well; receiving, by the processor, a performance curve for the electric submersible pump; adjusting, by the processor, the performance curve for the electric submersible pump based on specific gravity and viscosity of fluid being produced from the well; calculating, by the processor, a head correction necessary to shift the adjusted performance curve to pass through the operating point obtained from the portable separator rate test; updating, by the processor, a model of the electric submersible pump by incorporating the calculated head correction; and executing, by the processor, the model of the electric submersible pump to predict flow rates from the well at surface conditions.

[0090] In an example implementation combinable with any other example implementation, the methods also include controlling the electric submersible pump based on the predicted flow rates.

[0091] In an example implementation combinable with any other example implementation, receiving the performance curve for the electric submersible pump includes receiving a nominal performance curve for the electric submersible pump.

[0092] In an example implementation combinable with any other example implementation, receiving the performance curve for the electric submersible pump includes receiving a performance curve for the electric submersible pump updated from a nominal performance curve for the electric submersible pump.

[0093] In an example implementation combinable with any other example implementation, calculating a head correction includes calculating a ratio between the retrieved pump curve and shifted pump curve. In some cases, calculating the ratio between the retrieved pump curve and shifted pump curve includes calculating the ratio graphically.

[0094] In an example implementation combinable with any other example implementation, the methods also include receiving operational data from the electric submersible pump. In some cases, the methods also include receiving pressure, temperature, and fluid properties from downhole sensors. In some cases, the methods also include sending control signals sent to the electric submersible pump.

[0095] In an example implementation combinable with any other example implementation, the methods also include modeling current electric submersible pump production rates.

[0096] In an example implementation combinable with any other example implementation, executing the model of the electric submersible pump includes estimating water cut and fluid specific gravity.

[0097] A number of embodiments of the systems and methods have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of this specification. Accordingly, other embodiments are within the scope of the following claims.

Examples

examples

[0088]In some implementations, methods for producing fluid from a well using an electric submersible pump include: performing a portable separator rate test in the well to obtain an operating point for the electric submersible pump in the well; receiving a performance curve for the electric submersible pump; adjusting the performance curve for the electric submersible pump based on specific gravity and viscosity of fluid being produced from the well; calculating a head correction necessary to shift the adjusted performance curve to pass through the operating point obtained from the portable separator rate test; updating a model of the electric submersible pump by incorporating the calculated head correction; and executing the model of the electric submersible pump to predict flow rates from the well at surface conditions.

[0089]In some implementations, methods for producing fluid from a well using an electric submersible pump include: receiving, by a processor, results of a portable ...

TECHNICAL FIELD

[0001] This specification relates to producing fluids from subsurface reservoirs using electric submersible pumps (ESPs).BACKGROUND

[0002] ESPs are efficient and reliable artificial-lift tools for lifting high volumes of fluids from wellbores. ESPs have been used to produce fluids from reservoirs containing hydrocarbons.SUMMARY

[0003] This specification describes an approach to producing fluids from reservoirs (e.g., reservoirs containing hydrocarbons) using ESPs. This approach incorporates systems and methods calculating head deterioration in ESPs due to mechanical wear, accounting for pump head curve performance deviations, and improving ESP monitoring. These systems and methods are based on experimental data from portable separator rate tests and ESP sensor data and account for variables such as pump intake and discharge pressure and frequency during testing. Using this approach, the systems can estimate water cut and fluid specific gravity which are then used generate flow rate based on ESP downhole sensor data and using oil field correlation for head deration caused by mechanical wear.

[0004] This approach evaluates intake and discharge pressures against choke settings to control draw-down, considering factors like Delta P, pump ratings, motor loading, and well inflow for improved ESP management. By integrating manufacturer pump curves, the system keeps wells operating within desired ranges, thereby extending equipment lifespan. It facilitates quick adjustments such as choke size changes to adapt to changing ESP conditions. By addressing issues of low motor load in some wells, the system rerates motors by adjusting voltage, thus enhancing motor load and allowing previously non-operational wells to function.

[0005] The details of one or more embodiments of the invention are set forth in the accompanying drawings and the description below. Other features, objects, and advantages of the invention will be apparent from the description and drawings, and from the claims.DESCRIPTION OF DRAWINGS

[0006] FIG. 1 is a schematic view of exploration and production activities being performed in a subsurface formation.

[0007] FIG. 2 is a schematic illustrating a ESP monitoring and control system.

[0008] FIG. 3 is flow chart of a method of producing hydrocarbons using an ESP monitoring and control system.

[0009] FIG. 4 illustrates an ESP pump curve modified using oil field correction for head deration caused by mechanical wear.

[0010] FIG. 5 illustrates the relationship between ESP run life and % deviation.

[0011] FIGS. 6A-6C illustrate a prototype ESP monitoring and control system.

[0012] FIG. 7 illustrates hydrocarbon production operations.

[0013] FIG. 8 is a block diagram of an example computer system.

[0014] Like reference symbols in the various drawings indicate like elements.DETAILED DESCRIPTION

[0015] This specification describes an approach to producing fluids from reservoirs (e.g., reservoirs containing hydrocarbons) using ESPs. This approach incorporates systems and methods calculating head deterioration in ESPs due to mechanical wear, accounting for pump head curve performance deviations, and improving ESP monitoring. These systems and methods are based on experimental data from portable separator rate tests and ESP sensor data and account for variables such as pump intake and discharge pressure and frequency during testing. Using this approach, the systems can estimate water cut and fluid specific gravity which are then used generate flow rate based on ESP downhole sensor data and using oil field correlation for head deration caused by mechanical wear.

[0016] The systems and methods disclosed in this specification can be used for monitoring and controlling ESPs. They integrate a field correlation and ESP parameters into a unified system. This system, underpinned by the new methodology, offers diagnostic capabilities, production optimization, and ESP well tracking. It provides a comprehensive field overview of all ESP wells simultaneously, identifying wells requiring intervention, optimization, or replacement. The system provides a dynamic and interactive graphical user interface, offering a holistic view of all ESP wells with three primary modules.

[0017] FIG. 1 is a schematic view of operations being performed in a subsurface formation 100. These includes exploration operations as well as production operations using ESPs to produce fluids from the subsurface formation.

[0018] The subsurface formation 100 includes a layer of impermeable cap rock 102 at the surface. Facies underlying the impermeable cap rocks 102 include three layers 104, 106, and 108. A fault line 110 extends across the layer 104 and the layer 106.

[0019] Oil and gas tend to rise through permeable reservoir rock until further upward migration is blocked, for example, by the layer of impermeable cap rock 102. Seismic surveys attempt to identify locations where interaction between layers of the subsurface formation 100 are likely to trap oil and gas by limiting this upward migration. For example, FIG. 1 shows an anticline trap 107, where the layer of impermeable cap rock 102 has an upward convex configuration, and a fault trap 109, where the fault line 110 might allow oil and gas to flow in with clay material between the walls traps the petroleum. Other traps include salt domes and stratigraphic traps.

[0020] A seismic source 112 (for example, a seismic vibrator or an explosion) generates seismic waves that propagate in the earth. Although illustrated as a single component in FIG. 1, the source or sources 112 are typically a line or an array of sources 112. The generated seismic waves include seismic body waves 114 that travel into the ground and seismic surface waves 115 travel along the ground surface and diminish as they get further from the surface. As the seismic body waves 114 contact interfaces between geologic bodies or layers that have different velocities, each interface reflects some of the energy of the seismic wave and refracts some of the energy of the seismic wave. Such interfaces are sometimes referred to as horizons.

[0021] The seismic body waves 114 are received by a sensor or sensors 116. Although illustrated as a single component in FIG. 1, the sensor or sensors 116 are typically a line or an array of sensors 116 that generate an output signal in response to received seismic waves including waves reflected by the horizons in the subsurface formation 100. The sensors 116 can be geophone-receivers that produce electrical output signals transmitted as input data, for example, to a computer 118 on a seismic control truck 120. Based on the input data, the computer 118 may generate a seismic data output, for example, a seismic two-way response time plot.

[0022] A control center 122 can be operatively coupled to the seismic control truck 120 and other data acquisition and wellsite systems. The control center 122 may have computer facilities for receiving, storing, processing, and analyzing data from the seismic control truck 120 and other data acquisition and wellsite systems that provide additional information about the subsurface formation. For example, the control center 122 can receive data from a computer 119 associated with a well logging unit 121.

[0023] The computer systems 124 can be located in a different location than the control center 122. Some computer systems are provided with functionality for manipulating and analyzing the data, such as performing seismic interpretation or borehole resistivity image log interpretation to identify geological surfaces in the subsurface formation or performing simulation, planning, and optimization of production operations of the wellsite systems.

[0024] In some embodiments, a wellbore 130 that has been drilled in the subsurface formation 100 is logged in a well logging operation 128. The wellbore 130 extends downhole from a wellhead 132. The wellbore 130 is a vertical wellbore but well logging can also be performed in other wellbores, for example, slanted or horizontal wellbores. In the well logging operation 128, the wellbore 130 penetrates through three layers 102, 104, and 106 of a subsurface formation 100. A control truck 121 lowers a logging tool 134 down the wellbore 130 on a wireline 136.

[0025] The computer systems 124 in the control center 122 can be configured to analyze, model, control, optimize, or perform management tasks of field operations associated with development and production of resources such as oil and gas from the subsurface formation 100. For example, an injection well 123 and a production well 125 extend into layer 104 of the subsurface formation 100. An ESP 126 installed in the production well 125 is operated to produce fluids from layer 104 of the subsurface formation 100. Based on data gathered by the exploratory field operations, the computer systems 124 can generate models such as a reservoir model for portions of the subsurface formation 100. These models can simulate the effects of production field operations (e.g., injecting water or carbon dioxide through the injection well 123 to increase the production of hydrocarbons through the production well 125). The simulations can be used to plan and, in some instances, control field operations (e.g., the operation of pumps associated with the injection well 123 and the production well 125). This specification describes an approach to monitoring and controlling ESPs that accounts for head deterioration (e.g., head deterioration caused by mechanical wear).

[0026] FIG. 2 is a schematic illustrating a ESP monitoring and control system 200. In some instances, the ESP monitoring and control system 200 is implemented on the computer systems 124 in the control center 122. In some instances, the ESP monitoring control system 200 is implemented on separate computer systems, for example, standalone computer systems located in the vicinity of ESPs being used for production of fluids from the subsurface formation 100.

[0027] The ESP monitoring and control system 200 includes an ESP modeling module 210, a head derating module 212, and a display module 214 that integrate ESP parameters and variables in one system. The ESP monitoring and control system 200 is in electronic communication (e.g., wired or wireless electronic communication) with ESPs 216, downhole sensors 218, and surface units 220. Typical downhole sensors 218 measure parameters such as pump intake and discharge pressure and temperature, vibration, current leaks and typical surface units 220 measure parameters such as wellhead temperature, pressure, and chemical injection rates.

[0028] Communication between the ESP monitoring and control system 200 and the ESPs 216 can include, for example, operational data (e.g., wellhead variables such as temperature, pressure, chemical injection rates; electrical variables such as motor current consumption and voltage; and down hole variables such as pump intake and discharge pressure and temperature, vibration, and current leaks) sent from the ESPs 216 to the ESP monitoring control system 200 and control signals sent from the ESP monitoring and control system 200 to the ESPs 216. Communication between the ESP monitoring and control system 200 and the downhole sensors 218 can include, for example, pressure, temperature, and fluid properties measured by the downhole sensors 218 and sent from the downhole sensors 218 to the ESP monitoring control system 200 as well as control signals sent from the ESP monitoring and control system 200 to the downhole sensors 218. Communication between the ESP monitoring and control system 200 and the surface units 220 can include, for example, operational data sent from the surface units 220 to the ESP monitoring control system 200 and control signals sent from the ESP monitoring and control system 200 to the surface units 220.

[0029] A database 222 is electronic communication with the ESP monitoring and control system 200, the ESPs 216, the downhole sensors 218, and the surface units 220. The database 222 stores information including, for example, downhole sensor data, fluid properties, electrical readings, and manufacturer-provided ESP curves. The database also receives and stores the results operational tests such as portable separator rate tests performed in the field.

[0030] Based on information received from the ESPs 216, the downhole sensors 218, the surface units 220, and the database 222, the ESP monitoring and control system 200 models ESP and well performance. It also provides historical matching with rate tests, streamlined ESP diagnostics, and decision-making across the ESP's operational lifespan.

[0031] The ESP modeling module 210 provides real-time diagnostic capabilities, production optimization, and proactive tracking of ESP well conditions prior to any trip or failure. Utilizing scatter plots and visual basic software, it models current ESP production rates and combines various well variables. This allows for interventions such as ESP replacement, system upgrades or downgrades, choke valve adjustments, and optimization for wells with poor reservoir inflow or those running under optimal conditions. The ESP modeling module 210 periodically updates the underlying ESP model using a head correction factor generated by the head derating module 212.

[0032] The ESP modeling module 210 considers variables like pump intake and discharge pressure and frequency during testing, emphasizes the alignment of operational points with the catalogue curve and recognizes potential influences such as measurement errors, pump wear, and fluid property deviations. After model updates to incorporate the head correction factor, the ESP modeling module 210 can be used to estimate water cut and fluid specific gravity and generate flow rate based on ESP downhole sensor data and using oil field correlation for head deration caused by mechanical wear.

[0033] When portable separator rate tests are performed, the head derating module 212 uses the results of these tests and associated fluid properties measurements to adjust a pump performance curve (e.g., a manufacturer's pump performance retrieved from the database 222) to calculate a head correction factor reflecting current pump performance as impacted by head deterioration in ESPs caused by mechanical wear. The head correction factor calculated by the head derating module 212 is transferred to the ESP modeling module 210 which uses them to update the underlying ESP model using a head correction factor generated by the head derating module 212.

[0034] The display module 214 of the ESP monitoring and control system 200 is a graphical user interface which provides a comprehensive field overview, displaying multiple ESP wells simultaneously. The system significantly improves ESP turnaround through performance forecasting and a detailed equipment availability catalog.

[0035] FIG. 3 is flow chart of a method 300 of producing hydrocarbons from a well using an ESP monitoring and control system accounting for gradual deterioration of pump performance due to mechanical wear (e.g., the ESP monitoring and control system 200). The method 300 reflects the impact of the gradual deterioration of pump performance due to mechanical wear by incorporating calculation of the head correction factor.

[0036] A portable separator rate test is performed at the well to obtain an operating point for the electric submersible pump in the well (step 310). Portable separator tests can provide an accurate measurement of the fluid production rates and are used by petroleum engineers and field technicians to analyze and understand the behavior and characteristics of oil and gas wells. Portable separator tests specifically is a method that brings a high level of flexibility and efficiency to this process. Well testing, helps in evaluating the performance of a well and the field at large. The portable separator tests are distinguished by their use of a mobile unit that can be transported and set up at different well sites as needed. This flexibility is particularly useful in fields where permanent facilities are not yet established or where wells are spread out over a large area. The test separator works by taking a sample of the well's output and dividing it into its three main constituents: oil, gas, and water. This separation is crucial because it allows for the precise measurement of the flow rates of each phase of the output, information which is vital for understanding the well's behavior and for making informed decisions about its management. These devices measure the volume of oil, gas, and water separately with high precision, which is essential for reliable data analysis. The calibration of these meters is performed under controlled conditions to ensure that they provide accurate readings when deployed in the field.

[0037] A performance curve for the electric submersible pump is retrieved (step 312). ESPs have nominal pump performance curves. These nominal curves are typically provided by the manufacturer and are based on a standard fluid specific gravity of 1.0. As new ESPs are installed in a field, the associated pump performance curve can be stored the database 222 and retrieved by the ESP monitoring and control system 200 as part of the approach to updating a ESP model to reflect deteriorating pump performance. After retrieval, the nominal performance curve for the electric submersible pump is adjusted based on specific gravity and viscosity of fluid being produced from the well (step 314). The specific gravity and viscosity of fluid being produced from the well can be retrieved from database and / or received real-time from sensors.

[0038] A head correction necessary to shift the adjusted performance curve to pass through the operating point obtained from the portable separator rate test is calculated (step 316). The head correction can be calculated as a ratio between the retrieved pump curve and the adjusted pump curve. The calculation of this ratio can be done graphically or numerically.

[0039] FIG. 4 illustrates an ESP pump curve modified using oil field correction for head deration caused by mechanical wear before and after a shift to pass through the operating point obtained from the portable separator rate test. The adjusted pump curve 410 and the operating point 412 determined by the portable separator rate test are plotted together. The adjusted performance curve 410 is shifted vertically and horizontal to pass through the operating point 412 providing a shifted pump curve 414. The ratio necessary to provide this shift is the head correction used in this approach.

[0040] Referring again to FIG. 3, the head correction is used to update a model of the electric submersible pump (step 318). The updated model of the electric submersible pump is then executed to predict flow rates from the well at surface conditions (step 320). Optionally, the model results can be used to control the electric submersible pump based on the predicted flow rates (step 322).

[0041] FIG. 5 illustrates the significance of accounting for the mechanical wear on pump performance. FIG. 5 shows the percentage deviation between the portable rate test and the calculated flow rate against the ESP's operational lifespan for over 100 real data points from various oil fields and different pump curves. This chart reveals a correlation between increased ESP run life and greater deviation between the portable separator rate test and the flow rate calculated using downhole sensor data. This finding underscores the importance of ESP run life in applying accurate head deterioration corrections and achieving reliable values.

[0042] FIGS. 6A-6C illustrate a prototype ESP monitoring and control system. FIG. 6A is a screenshot of an oil field overview interface 600. The oil field overview interface 600 displays motor loading 610, well status 612, pump model 614, smart functions 616, pump status 618, delta P at the surface 620, a well productivity index 622, an estimated production rate 624, a pump rating summary 626, and the total production rate for the field 628. The oil field overview interface 600 can be used to identify wells to optimize by relaxing or restricting the choke valves, wells with poor inflow from reservoir and optimized wells, running on optimal conditions, wells to up-grade or down-grade the ESP system, and wells to intervene with rig to replace the ESP.

[0043] FIG. 6B is a screenshot of a well gauges interface 640. The well gauges interface 640 displays a downhole motor load gauge 642, an operational pump condition gauge 644, a pressure delta gauge 646, an amperage gauge 648 of the selected ESP, a flow rate gauge 650 for the selected ESP, and a dropdown menu 652 for selection of a specific well. These five gauges can be used to monitor production rate performance, ESP motor performance, and surface pressure performance.

[0044] The amperage 648 of the selected ESP is based on the name plate amperage of the selected pump with the green zone indicating the normal operational zone. If the well is operating close to the red zone, there is potential for a tripped well due to underload. The motor loading gauge shows the amperage percentage consumption as a function of name plate motor for the selected ESP.

[0045] The flow rate gauge 650 shows the pump range envelop (indicated by the green zone) with the red zone indicating when the ESP is running on upthrust (i.e., above the maximum pump capacity) or on downthrust (i.e., below the minimum pump capacity). The displayed flow rates reflect the head derating correction calculated, for example, by the method 300. Downthrust increases as the flow through the stage decreases (e.g., on the left-hand side of the pump curve). Upthrust increases as the flow through the stage increases (e.g., on the right-hand side of the pump curve). Flow rates to the left of the operating range will increase wear on the downthrust washers. Flows to the right of the operating range will cause wear on the upthrust washers. By keeping wells on range according to the ESP catalog, the ESP system can help extend the run life of the ESPs.

[0046] FIG. 6C is a screenshot of a well history interface 670. The well history interface 670 displays historical data from a selected well including micromotion 672, pressure 674, downhole sensor readings 676, and motor electrical readings 678. This ESP historical data can be used to predict failures and trips. The well history interface 670 can show the complete well history or selected periods.

[0047] Leveraging the head derating factor, the prototype ESP monitoring and control system achieved a closer alignment between downhole and portable separator rate test results—slashing the deviation from 14% to 6%. Table 1 presents the deviation between downhole and portable separator rate test results using the described head derating approach using the prototype ESP monitoring and control system.

[0048] The resultant ESP model, grounded in this approach, provides precise historical matches to conducted rate tests, refining ESP diagnostics and decision-making throughout its lifecycle. This enhances ESP turnaround, empowering users with performance forecasting and facilitating equipment planning.TABLE 1DeviationHeadDeviationBefore ApplyDeratingafter applyWellHDFFactorHDFWell A20%0.877%Well B16%0.9510% Well C10%0.943%Well D15%0.927%Well E 1%1.000%Well F17%0.883%Well G17%0.8913% Average14%6%Hydrocarbon Operations

[0049] FIG. 7 illustrates hydrocarbon production operations 700 that include both one or more field operations 710 and one or more computational operations 712, which exchange information and control exploration for the production of hydrocarbons. In some implementations, outputs of techniques of the present disclosure can be performed before, during, or in combination with the hydrocarbon production operations 700, specifically, for example, either as field operations 710 or computational operations 712, or both.

[0050] Examples of field operations 710 include forming / drilling a wellbore, hydraulic fracturing, producing through the wellbore, injecting fluids (such as water) through the wellbore, to name a few. In some implementations, methods of the present disclosure can trigger or control the field operations 710. For example, the methods of the present disclosure can generate data from hardware / software including sensors and physical data gathering equipment (e.g., seismic sensors, well logging tools, flow meters, and temperature and pressure sensors). The methods of the present disclosure can include transmitting the data from the hardware / software to the field operations 710 and responsively triggering the field operations 710 including, for example, generating plans and signals that provide feedback to and control physical components of the field operations 710. Alternatively or in addition, the field operations 710 can trigger the methods of the present disclosure. For example, implementing physical components (including, for example, hardware, such as sensors) deployed in the field operations 710 can generate plans and signals that can be provided as input or feedback (or both) to the methods of the present disclosure.

[0051] Examples of computational operations 712 include one or more computer systems 720 that include one or more processors and computer-readable media (e.g., non-transitory computer-readable media) operatively coupled to the one or more processors to execute computer operations to perform the methods of the present disclosure. The computational operations 712 can be implemented using one or more databases 718, which store data received from the field operations 710 and / or generated internally within the computational operations 712 (e.g., by implementing the methods of the present disclosure) or both. For example, the one or more computer systems 720 process inputs from the field operations 710 to assess conditions in the physical world, the outputs of which are stored in the databases 718. For example, seismic sensors of the field operations 710 can be used to perform a seismic survey to map subterranean features, such as facies and faults. In performing a seismic survey, seismic sources (e.g., seismic vibrators or explosions) generate seismic waves that propagate in the earth and seismic receivers (e.g., geophones) measure reflections generated as the seismic waves interact with boundaries between layers of a subsurface formation. The source and received signals are provided to the computational operations 712 where they are stored in the databases 718 and analyzed by the one or more computer systems 720.

[0052] In some implementations, one or more outputs 722 generated by the one or more computer systems 720 can be provided as feedback / input to the field operations 710 (either as direct input or stored in the databases 718). The field operations 710 can use the feedback / input to control physical components used to perform the field operations 710 in the real world.

[0053] For example, the computational operations 712 can process the seismic data to generate three-dimensional (3D) maps of the subsurface formation. The computational operations 712 can use these 3D maps to provide plans for locating and drilling exploratory wells. In some operations, the exploratory wells are drilled using logging-while-drilling (LWD) techniques which incorporate logging tools into the drill string. LWD techniques can enable the computational operations 712 to process new information about the formation and control the drilling to adjust to the observed conditions in real-time.

[0054] The one or more computer systems 720 can update the 3D maps of the subsurface formation as information from one exploration well is received and the computational operations 712 can adjust the location of the next exploration well based on the updated 3D maps. Similarly, the data received from production operations can be used by the computational operations 712 to control components of the production operations. For example, production well and pipeline data can be analyzed to predict slugging in pipelines leading to a refinery and the computational operations 712 can control machine operated valves upstream of the refinery to reduce the likelihood of plant disruptions that run the risk of taking the plant offline.

[0055] In some implementations of the computational operations 712, customized user interfaces can present intermediate or final results of the above-described processes to a user. Information can be presented in one or more textual, tabular, or graphical formats, such as through a dashboard. The information can be presented at one or more on-site locations (such as at an oil well or other facility), on the Internet (such as on a webpage), on a mobile application (or app), or at a central processing facility.

[0056] The presented information can include feedback, such as changes in parameters or processing inputs, that the user can select to improve a production environment, such as in the exploration, production, and / or testing of petrochemical processes or facilities. For example, the feedback can include parameters that, when selected by the user, can cause a change to, or an improvement in, drilling parameters (including drill bit speed and direction) or overall production of a gas or oil well. The feedback, when implemented by the user, can improve the speed and accuracy of calculations, streamline processes, improve models, and solve problems related to efficiency, performance, safety, reliability, costs, downtime, and the need for human interaction.

[0057] In some implementations, the feedback can be implemented in real-time, such as to provide an immediate or near-immediate change in operations or in a model. The term real-time (or similar terms as understood by one of ordinary skill in the art) means that an action and a response are temporally proximate such that an individual perceives the action and the response occurring substantially simultaneously. For example, the time difference for a response to display (or for an initiation of a display) of data following the individual's action to access the data can be less than 1 millisecond (ms), less than 1 second(s), or less than 5 s. While the requested data need not be displayed (or initiated for display) instantaneously, it is displayed (or initiated for display) without any intentional delay, taking into account processing limitations of a described computing system and time required to, for example, gather, accurately measure, analyze, process, store, or transmit the data.

[0058] Events can include readings or measurements captured by downhole equipment such as sensors, pumps, bottom hole assemblies, or other equipment. The readings or measurements can be analyzed at the surface, such as by using applications that can include modeling applications and machine learning. The analysis can be used to generate changes to settings of downhole equipment, such as drilling equipment. In some implementations, values of parameters or other variables that are determined can be used automatically (such as through using rules) to implement changes in oil or gas well exploration, production / drilling, or testing. For example, outputs of the present disclosure can be used as inputs to other equipment and / or systems at a facility. This can be especially useful for systems or various pieces of equipment that are located several meters or several miles apart, or are located in different countries or other jurisdictions.

[0059] FIG. 8 is a block diagram of an example computer system 800 used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures described in the present disclosure, according to some implementations of the present disclosure. The illustrated computer 802 is intended to encompass any computing device such as a server, a desktop computer, a laptop / notebook computer, a wireless data port, a smart phone, a personal data assistant (PDA), a tablet computing device, or one or more processors within these devices, including physical instances, virtual instances, or both. The computer 802 can include input devices such as keypads, keyboards, and touch screens that can accept user information. Also, the computer 802 can include output devices that can convey information associated with the operation of the computer 802. The information can include digital data, visual data, audio information, or a combination of information. The information can be presented in a graphical user interface (UI) (or GUI).

[0060] The computer 802 can serve in a role as a client, a network component, a server, a database, a persistency, or components of a computer system for performing the subject matter described in the present disclosure. The illustrated computer 802 is communicably coupled with a network 830. In some implementations, one or more components of the computer 802 can be configured to operate within different environments, including cloud-computing-based environments, local environments, global environments, and combinations of environments.

[0061] At a high level, the computer 802 is an electronic computing device operable to receive, transmit, process, store, and manage data and information associated with the described subject matter. According to some implementations, the computer 802 can also include, or be communicably coupled with, an application server, an email server, a web server, a caching server, a streaming data server, or a combination of servers.

[0062] The computer 802 can receive requests over network 830 from a client application (for example, executing on another computer 802). The computer 802 can respond to the received requests by processing the received requests using software applications. Requests can also be sent to the computer 802 from internal users (for example, from a command console), external (or third) parties, automated applications, entities, individuals, systems, and computers.

[0063] Each of the components of the computer 802 can communicate using a system bus 803. In some implementations, any or all of the components of the computer 802, including hardware or software components, can interface with each other or the interface 804 (or a combination of both), over the system bus 803. Interfaces can use an application programming interface (API) 812, a service layer 813, or a combination of the API 812 and service layer 813. The API 812 can include specifications for routines, data structures, and object classes. The API 812 can be either computer-language independent or dependent. The API 812 can refer to a complete interface, a single function, or a set of APIs.

[0064] The service layer 813 can provide software services to the computer 802 and other components (whether illustrated or not) that are communicably coupled to the computer 802. The functionality of the computer 802 can be accessible for all service consumers using this service layer. Software services, such as those provided by the service layer 813, can provide reusable, defined functionalities through a defined interface. For example, the interface can be software written in JAVA, C++, or a language providing data in extensible markup language (XML) format. While illustrated as an integrated component of the computer 802, in alternative implementations, the API 812 or the service layer 813 can be stand-alone components in relation to other components of the computer 802 and other components communicably coupled to the computer 802. Moreover, any or all parts of the API 812 or the service layer 813 can be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of the present disclosure.

[0065] The computer 802 includes an interface 804. Although illustrated as a single interface 804 in FIG. 8, two or more interfaces 804 can be used according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. The interface 804 can be used by the computer 802 for communicating with other systems that are connected to the network 830 (whether illustrated or not) in a distributed environment. Generally, the interface 804 can include, or be implemented using, logic encoded in software or hardware (or a combination of software and hardware) operable to communicate with the network 830. More specifically, the interface 804 can include software supporting one or more communication protocols associated with communications. As such, the network 830 or the hardware of the interface can be operable to communicate physical signals within and outside of the illustrated computer 802.

[0066] The computer 802 includes a processor 805. Although illustrated as a single processor 805 in FIG. 8, two or more processors 805 can be used according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. Generally, the processor 805 can execute instructions and can manipulate data to perform the operations of the computer 802, including operations using algorithms, methods, functions, processes, flows, and procedures as described in the present disclosure.

[0067] The computer 802 also includes a database 806 that can hold data (for example, seismic data 816) for the computer 802 and other components connected to the network 830 (whether illustrated or not). For example, database 806 can be an in-memory, conventional, or a database storing data consistent with the present disclosure. In some implementations, database 806 can be a combination of two or more different database types (for example, hybrid in-memory and conventional databases) according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. Although illustrated as a single database 806 in FIG. 8, two or more databases (of the same, different, or combination of types) can be used according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. While database 806 is illustrated as an internal component of the computer 802, in alternative implementations, database 806 can be external to the computer 802.

[0068] The computer 802 also includes a memory 807 that can hold data for the computer 802 or a combination of components connected to the network 830 (whether illustrated or not). Memory 807 can store any data consistent with the present disclosure. In some implementations, memory 807 can be a combination of two or more different types of memory (for example, a combination of semiconductor and magnetic storage) according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. Although illustrated as a single memory 807 in FIG. 8, two or more memories 807 (of the same, different, or combination of types) can be used according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. While memory 807 is illustrated as an internal component of the computer 802, in alternative implementations, memory 807 can be external to the computer 802.

[0069] The application 808 can be an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer 802 and the described functionality. For example, application 808 can serve as one or more components, modules, or applications. Further, although illustrated as a single application 808, the application 808 can be implemented as multiple applications 808 on the computer 802. In addition, although illustrated as internal to the computer 802, in alternative implementations, the application 808 can be external to the computer 802.

[0070] The computer 802 can also include a power supply 814. The power supply 814 can include a rechargeable or non-rechargeable battery that can be configured to be either user- or non-user-replaceable. In some implementations, the power supply 814 can include power-conversion and management circuits, including recharging, standby, and power management functionalities. In some implementations, the power-supply 814 can include a power plug to allow the computer 802 to be plugged into a wall socket or a power source to, for example, power the computer 802 or recharge a rechargeable battery.

[0071] There can be any number of computers 802 associated with, or external to, a computer system containing computer 802, with each computer 802 communicating over network 830. Further, the terms “client,”“user,” and other appropriate terminology can be used interchangeably, as appropriate, without departing from the scope of the present disclosure. Moreover, the present disclosure contemplates that many users can use one computer 802 and one user can use multiple computers 802.

[0072] Implementations of the subject matter and the functional operations described in this specification can be implemented in digital electronic circuitry, in tangibly embodied computer software or firmware, in computer hardware, including the structures disclosed in this specification and their structural equivalents, or in combinations of one or more of them. Software implementations of the described subject matter can be implemented as one or more computer programs. Each computer program can include one or more modules of computer program instructions encoded on a tangible, non transitory, computer-readable computer-storage medium for execution by, or to control the operation of, data processing apparatus. Alternatively, or additionally, the program instructions can be encoded in / on an artificially generated propagated signal. The example, the signal can be a machine-generated electrical, optical, or electromagnetic signal that is generated to encode information for transmission to suitable receiver apparatus for execution by a data processing apparatus. The computer-storage medium can be a machine-readable storage device, a machine-readable storage substrate, a random or serial access memory device, or a combination of computer-storage mediums.

[0073] The terms “data processing apparatus,”“computer,” and “electronic computer device” (or equivalent as understood by one of ordinary skill in the art) refer to data processing hardware. For example, a data processing apparatus can encompass all kinds of apparatus, devices, and machines for processing data, including by way of example, a programmable processor, a computer, or multiple processors or computers. The apparatus can also include special purpose logic circuitry including, for example, a central processing unit (CPU), a field programmable gate array (FPGA), or an application specific integrated circuit (ASIC). In some implementations, the data processing apparatus or special purpose logic circuitry (or a combination of the data processing apparatus or special purpose logic circuitry) can be hardware- or software-based (or a combination of both hardware- and software-based). The apparatus can optionally include code that creates an execution environment for computer programs, for example, code that constitutes processor firmware, a protocol stack, a database management system, an operating system, or a combination of execution environments. The present disclosure contemplates the use of data processing apparatuses with or without conventional operating systems, for example, LINUX, UNIX, WINDOWS, MAC OS, ANDROID, or IOS.

[0074] A computer program, which can also be referred to or described as a program, software, a software application, a module, a software module, a script, or code, can be written in any form of programming language. Programming languages can include, for example, compiled languages, interpreted languages, declarative languages, or procedural languages. Programs can be deployed in any form, including as stand-alone programs, modules, components, subroutines, or units for use in a computing environment. A computer program can, but need not, correspond to a file in a file system. A program can be stored in a portion of a file that holds other programs or data, for example, one or more scripts stored in a markup language document, in a single file dedicated to the program in question, or in multiple coordinated files storing one or more modules, sub programs, or portions of code. A computer program can be deployed for execution on one computer or on multiple computers that are located, for example, at one site or distributed across multiple sites that are interconnected by a communication network. While portions of the programs illustrated in the various figures may be shown as individual modules that implement the various features and functionality through various objects, methods, or processes, the programs can instead include a number of sub-modules, third-party services, components, and libraries. Conversely, the features and functionality of various components can be combined into single components as appropriate. Thresholds used to make computational determinations can be statically, dynamically, or both statically and dynamically determined.

[0075] The methods, processes, or logic flows described in this specification can be performed by one or more programmable computers executing one or more computer programs to perform functions by operating on input data and generating output. The methods, processes, or logic flows can also be performed by, and apparatus can also be implemented as, special purpose logic circuitry, for example, a CPU, an FPGA, or an ASIC.

[0076] Computers suitable for the execution of a computer program can be based on one or more of general and special purpose microprocessors and other kinds of CPUs. The elements of a computer are a CPU for performing or executing instructions and one or more memory devices for storing instructions and data. Generally, a CPU can receive instructions and data from (and write data to) a memory. A computer can also include, or be operatively coupled to, one or more mass storage devices for storing data. In some implementations, a computer can receive data from, and transfer data to, the mass storage devices including, for example, magnetic, magneto optical disks, or optical disks. Moreover, a computer can be embedded in another device, for example, a mobile telephone, a personal digital assistant (PDA), a mobile audio or video player, a game console, a global positioning system (GPS) receiver, or a portable storage device such as a universal serial bus (USB) flash drive.

[0077] Computer readable media (transitory or non-transitory, as appropriate) suitable for storing computer program instructions and data can include all forms of permanent / non-permanent and volatile / non-volatile memory, media, and memory devices. Computer readable media can include, for example, semiconductor memory devices such as random access memory (RAM), read only memory (ROM), phase change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), and flash memory devices. Computer readable media can also include, for example, magnetic devices such as tape, cartridges, cassettes, and internal / removable disks. Computer readable media can also include magneto optical disks and optical memory devices and technologies including, for example, digital video disc (DVD), CD ROM, DVD+ / −R, DVD-RAM, DVD-ROM, HD-DVD, and BLURAY. The memory can store various objects or data, including caches, classes, frameworks, applications, modules, backup data, jobs, web pages, web page templates, data structures, database tables, repositories, and dynamic information. Types of objects and data stored in memory can include parameters, variables, algorithms, instructions, rules, constraints, and references. Additionally, the memory can include logs, policies, security or access data, and reporting files. The processor and the memory can be supplemented by, or incorporated in, special purpose logic circuitry.

[0078] Implementations of the subject matter described in the present disclosure can be implemented on a computer having a display device for providing interaction with a user, including displaying information to (and receiving input from) the user. Types of display devices can include, for example, a cathode ray tube (CRT), a liquid crystal display (LCD), a light-emitting diode (LED), and a plasma monitor. Display devices can include a keyboard and pointing devices including, for example, a mouse, a trackball, or a trackpad. User input can also be provided to the computer through the use of a touchscreen, such as a tablet computer surface with pressure sensitivity or a multi-touch screen using capacitive or electric sensing. Other kinds of devices can be used to provide for interaction with a user, including to receive user feedback including, for example, sensory feedback including visual feedback, auditory feedback, or tactile feedback. Input from the user can be received in the form of acoustic, speech, or tactile input. In addition, a computer can interact with a user by sending documents to, and receiving documents from, a device that is used by the user. For example, the computer can send web pages to a web browser on a user's client device in response to requests received from the web browser.

[0079] The term “graphical user interface,” or “GUI,” can be used in the singular or the plural to describe one or more graphical user interfaces and each of the displays of a particular graphical user interface. Therefore, a GUI can represent any graphical user interface, including, but not limited to, a web browser, a touch screen, or a command line interface (CLI) that processes information and efficiently presents the information results to the user. In general, a GUI can include a plurality of user interface (UI) elements, some or all associated with a web browser, such as interactive fields, pull-down lists, and buttons. These and other UI elements can be related to or represent the functions of the web browser.

[0080] Implementations of the subject matter described in this specification can be implemented in a computing system that includes a back end component, for example, as a data server, or that includes a middleware component, for example, an application server. Moreover, the computing system can include a front-end component, for example, a client computer having one or both of a graphical user interface or a Web browser through which a user can interact with the computer. The components of the system can be interconnected by any form or medium of wireline or wireless digital data communication (or a combination of data communication) in a communication network. Examples of communication networks include a local area network (LAN), a radio access network (RAN), a metropolitan area network (MAN), a wide area network (WAN), Worldwide Interoperability for Microwave Access (WIMAX), a wireless local area network (WLAN) (for example, using 802.11 a / b / g / n or 802.20 or a combination of protocols), all or a portion of the Internet, or any other communication system or systems at one or more locations (or a combination of communication networks). The network can communicate with, for example, Internet Protocol (IP) packets, frame relay frames, asynchronous transfer mode (ATM) cells, voice, video, data, or a combination of communication types between network addresses.

[0081] The computing system can include clients and servers. A client and server can generally be remote from each other and can typically interact through a communication network. The relationship of client and server can arise by virtue of computer programs running on the respective computers and having a client-server relationship.

[0082] Cluster file systems can be any file system type accessible from multiple servers for read and update. Locking or consistency tracking may not be necessary since the locking of exchange file system can be done at application layer. Furthermore, Unicode data files can be different from non-Unicode data files.

[0083] While this specification contains many specific implementation details, these should not be construed as limitations on the scope of what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features that are described in this specification in the context of separate implementations can also be implemented, in combination, in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations, separately, or in any suitable sub-combination. Moreover, although previously described features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can, in some cases, be excised from the combination, and the claimed combination may be directed to a sub-combination or variation of a sub-combination.

[0084] Particular implementations of the subject matter have been described. Other implementations, alterations, and permutations of the described implementations are within the scope of the following claims as will be apparent to those skilled in the art. While operations are depicted in the drawings or claims in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed (some operations may be considered optional), to achieve desirable results. In certain circumstances, multitasking or parallel processing (or a combination of multitasking and parallel processing) may be advantageous and performed as deemed appropriate.

[0085] Moreover, the separation or integration of various system modules and components in the previously described implementations should not be understood as requiring such separation or integration in all implementations, and it should be understood that the described program components and systems can generally be integrated together in a single software product or packaged into multiple software products.

[0086] Accordingly, the previously described example implementations do not define or constrain the present disclosure. Other changes, substitutions, and alterations are also possible without departing from the spirit and scope of the present disclosure.

[0087] Furthermore, any claimed implementation is considered to be applicable to at least a computer-implemented method; a non-transitory, computer-readable medium storing computer-readable instructions to perform the computer-implemented method; and a computer system comprising a computer memory interoperably coupled with a hardware processor configured to perform the computer-implemented method or the instructions stored on the non-transitory, computer-readable medium.Examples

[0088] In some implementations, methods for producing fluid from a well using an electric submersible pump include: performing a portable separator rate test in the well to obtain an operating point for the electric submersible pump in the well; receiving a performance curve for the electric submersible pump; adjusting the performance curve for the electric submersible pump based on specific gravity and viscosity of fluid being produced from the well; calculating a head correction necessary to shift the adjusted performance curve to pass through the operating point obtained from the portable separator rate test; updating a model of the electric submersible pump by incorporating the calculated head correction; and executing the model of the electric submersible pump to predict flow rates from the well at surface conditions.

[0089] In some implementations, methods for producing fluid from a well using an electric submersible pump include: receiving, by a processor, results of a portable separator rate test in the well to obtain an operating point for the electric submersible pump in the well; receiving, by the processor, a performance curve for the electric submersible pump; adjusting, by the processor, the performance curve for the electric submersible pump based on specific gravity and viscosity of fluid being produced from the well; calculating, by the processor, a head correction necessary to shift the adjusted performance curve to pass through the operating point obtained from the portable separator rate test; updating, by the processor, a model of the electric submersible pump by incorporating the calculated head correction; and executing, by the processor, the model of the electric submersible pump to predict flow rates from the well at surface conditions.

[0090] In an example implementation combinable with any other example implementation, the methods also include controlling the electric submersible pump based on the predicted flow rates.

[0091] In an example implementation combinable with any other example implementation, receiving the performance curve for the electric submersible pump includes receiving a nominal performance curve for the electric submersible pump.

[0092] In an example implementation combinable with any other example implementation, receiving the performance curve for the electric submersible pump includes receiving a performance curve for the electric submersible pump updated from a nominal performance curve for the electric submersible pump.

[0093] In an example implementation combinable with any other example implementation, calculating a head correction includes calculating a ratio between the retrieved pump curve and shifted pump curve. In some cases, calculating the ratio between the retrieved pump curve and shifted pump curve includes calculating the ratio graphically.

[0094] In an example implementation combinable with any other example implementation, the methods also include receiving operational data from the electric submersible pump. In some cases, the methods also include receiving pressure, temperature, and fluid properties from downhole sensors. In some cases, the methods also include sending control signals sent to the electric submersible pump.

[0095] In an example implementation combinable with any other example implementation, the methods also include modeling current electric submersible pump production rates.

[0096] In an example implementation combinable with any other example implementation, executing the model of the electric submersible pump includes estimating water cut and fluid specific gravity.

[0097] A number of embodiments of the systems and methods have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of this specification. Accordingly, other embodiments are within the scope of the following claims.

Examples

examples

[0088]In some implementations, methods for producing fluid from a well using an electric submersible pump include: performing a portable separator rate test in the well to obtain an operating point for the electric submersible pump in the well; receiving a performance curve for the electric submersible pump; adjusting the performance curve for the electric submersible pump based on specific gravity and viscosity of fluid being produced from the well; calculating a head correction necessary to shift the adjusted performance curve to pass through the operating point obtained from the portable separator rate test; updating a model of the electric submersible pump by incorporating the calculated head correction; and executing the model of the electric submersible pump to predict flow rates from the well at surface conditions.

[0089]In some implementations, methods for producing fluid from a well using an electric submersible pump include: receiving, by a processor, results of a portable ...

Claims

1. A method for producing fluid from a well using an electric submersible pump, the method comprising:performing a portable separator rate test in the well to obtain an operating point for the electric submersible pump in the well;receiving a performance curve for the electric submersible pump;adjusting the performance curve for the electric submersible pump based on specific gravity and viscosity of fluid being produced from the well;calculating a head correction necessary to shift the adjusted performance curve to pass through the operating point obtained from the portable separator rate test;updating a model of the electric submersible pump by incorporating the calculated head correction; andexecuting the model of the electric submersible pump to predict flow rates from the well at surface conditions.

2. The method of claim 1, further comprising controlling the electric submersible pump based on the predicted flow rates.

3. The method of claim 1, wherein receiving the performance curve for the electric submersible pump comprising receiving a nominal performance curve for the electric submersible pump.

4. The method of claim 1, wherein receiving the performance curve for the electric submersible pump comprising receiving a performance curve for the electric submersible pump updated from a nominal performance curve for the electric submersible pump.

5. The method of claim 1, wherein calculating a head correction comprises calculating a ratio between the retrieved pump curve and shifted pump curve.

6. The method of claim 5, wherein calculating the ratio between the retrieved pump curve and shifted pump curve comprises calculating the ratio graphically.

7. The method of claim 1, further comprising receiving operational data from the electric submersible pump.

8. The method of claim 7, further comprising receiving pressure, temperature, and fluid properties from downhole sensors.

9. The method of claim 8, further comprising sending control signals sent to the electric submersible pump.

10. The method of claim 1, further comprising modeling current electric submersible pump production rates.

11. The method of claim 1, wherein executing the model of the electric submersible pump comprises estimating water cut and fluid specific gravity.

12. A method for producing fluid from a well using an electric submersible pump, the method comprising:receiving, by a processor, results of a portable separator rate test in the well to obtain an operating point for the electric submersible pump in the well;receiving, by the processor, a performance curve for the electric submersible pump;adjusting, by the processor, the performance curve for the electric submersible pump based on specific gravity and viscosity of fluid being produced from the well;calculating, by the processor, a head correction necessary to shift the adjusted performance curve to pass through the operating point obtained from the portable separator rate test;updating, by the processor, a model of the electric submersible pump by incorporating the calculated head correction; andexecuting, by the processor, the model of the electric submersible pump to predict flow rates from the well at surface conditions.

13. The method of claim 12, wherein receiving the performance curve for the electric submersible pump comprising receiving a nominal performance curve for the electric submersible pump.

14. The method of claim 12, wherein receiving the performance curve for the electric submersible pump comprising receiving a performance curve for the electric submersible pump updated from a nominal performance curve for the electric submersible pump.

15. The method of claim 12, wherein calculating a head correction comprises calculating a ratio between the retrieved pump curve and shifted pump curve.

16. The method of claim 15, wherein calculating the ratio between the retrieved pump curve and shifted pump curve comprises calculating the ratio graphically.

17. The method of claim 12, further comprising receiving, by the processor, operational data from the electric submersible pump.

18. The method of claim 17, further comprising receiving, by the processor, pressure, temperature, and fluid properties from downhole sensors.

19. The method of claim 18, further comprising sending control signals sent to the electric submersible pump.

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