Producing Fluids from Subsurface Reservoirs Using Electric Submersible Pumps

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

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.

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.

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.

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.

Like reference symbols in the various drawings indicate like elements.

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.

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.

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

The subsurface formationincludes a layer of impermeable cap rockat the surface. Facies underlying the impermeable cap rocksinclude three layers,, and. A fault lineextends across the layerand the layer.

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. Seismic surveys attempt to identify locations where interaction between layers of the subsurface formationare likely to trap oil and gas by limiting this upward migration. For example,shows an anticline trap, where the layer of impermeable cap rockhas an upward convex configuration, and a fault trap, where the fault linemight allow oil and gas to flow in with clay material between the walls traps the petroleum. Other traps include salt domes and stratigraphic traps.

A seismic source(for example, a seismic vibrator or an explosion) generates seismic waves that propagate in the earth. Although illustrated as a single component in, the source or sourcesare typically a line or an array of sources. The generated seismic waves include seismic body wavesthat travel into the ground and seismic surface wavestravel along the ground surface and diminish as they get further from the surface. As the seismic body wavescontact 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.

The seismic body wavesare received by a sensor or sensors. Although illustrated as a single component in, the sensor or sensorsare typically a line or an array of sensorsthat generate an output signal in response to received seismic waves including waves reflected by the horizons in the subsurface formation. The sensorscan be geophone-receivers that produce electrical output signals transmitted as input data, for example, to a computeron a seismic control truck. Based on the input data, the computermay generate a seismic data output, for example, a seismic two-way response time plot.

A control centercan be operatively coupled to the seismic control truckand other data acquisition and wellsite systems. The control centermay have computer facilities for receiving, storing, processing, and analyzing data from the seismic control truckand other data acquisition and wellsite systems that provide additional information about the subsurface formation. For example, the control centercan receive data from a computerassociated with a well logging unit.

The computer systemscan be located in a different location than the control center. 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.

In some embodiments, a wellborethat has been drilled in the subsurface formationis logged in a well logging operation. The wellboreextends downhole from a wellhead. The wellboreis a vertical wellbore but well logging can also be performed in other wellbores, for example, slanted or horizontal wellbores. In the well logging operation, the wellborepenetrates through three layers,, andof a subsurface formation. A control trucklowers a logging tooldown the wellboreon a wireline.

The computer systemsin the control centercan 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. For example, an injection welland a production wellextend into layerof the subsurface formation. An ESPinstalled in the production wellis operated to produce fluids from layerof the subsurface formation. Based on data gathered by the exploratory field operations, the computer systemscan generate models such as a reservoir model for portions of the subsurface formation. These models can simulate the effects of production field operations (e.g., injecting water or carbon dioxide through the injection wellto increase the production of hydrocarbons through the production well). The simulations can be used to plan and, in some instances, control field operations (e.g., the operation of pumps associated with the injection welland the production well). This specification describes an approach to monitoring and controlling ESPs that accounts for head deterioration (e.g., head deterioration caused by mechanical wear).

is a schematic illustrating a ESP monitoring and control system. In some instances, the ESP monitoring and control systemis implemented on the computer systemsin the control center. In some instances, the ESP monitoring control systemis 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.

The ESP monitoring and control systemincludes an ESP modeling module, a head derating module, and a display modulethat integrate ESP parameters and variables in one system. The ESP monitoring and control systemis in electronic communication (e.g., wired or wireless electronic communication) with ESPs, downhole sensors, and surface units. Typical downhole sensorsmeasure parameters such as pump intake and discharge pressure and temperature, vibration, current leaks and typical surface unitsmeasure parameters such as wellhead temperature, pressure, and chemical injection rates.

Communication between the ESP monitoring and control systemand the ESPscan 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 ESPsto the ESP monitoring control systemand control signals sent from the ESP monitoring and control systemto the ESPs. Communication between the ESP monitoring and control systemand the downhole sensorscan include, for example, pressure, temperature, and fluid properties measured by the downhole sensorsand sent from the downhole sensorsto the ESP monitoring control systemas well as control signals sent from the ESP monitoring and control systemto the downhole sensors. Communication between the ESP monitoring and control systemand the surface unitscan include, for example, operational data sent from the surface unitsto the ESP monitoring control systemand control signals sent from the ESP monitoring and control systemto the surface units.

A databaseis electronic communication with the ESP monitoring and control system, the ESPs, the downhole sensors, and the surface units. The databasestores 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.

Based on information received from the ESPs, the downhole sensors, the surface units, and the database, the ESP monitoring and control systemmodels ESP and well performance. It also provides historical matching with rate tests, streamlined ESP diagnostics, and decision-making across the ESP's operational lifespan.

The ESP modeling moduleprovides 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 moduleperiodically updates the underlying ESP model using a head correction factor generated by the head derating module.

The ESP modeling moduleconsiders 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 modulecan 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.

When portable separator rate tests are performed, the head derating moduleuses 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) 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 moduleis transferred to the ESP modeling modulewhich uses them to update the underlying ESP model using a head correction factor generated by the head derating module.

The display moduleof the ESP monitoring and control systemis 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.

is flow chart of a methodof 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). The methodreflects the impact of the gradual deterioration of pump performance due to mechanical wear by incorporating calculation of the head correction factor.

A portable separator rate test is performed at the well to obtain an operating point for the electric submersible pump in the well (step). 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.

A performance curve for the electric submersible pump is retrieved (step). 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 databaseand retrieved by the ESP monitoring and control systemas 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). The specific gravity and viscosity of fluid being produced from the well can be retrieved from database and/or received real-time from sensors.

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). 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.

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 curveand the operating pointdetermined by the portable separator rate test are plotted together. The adjusted performance curveis shifted vertically and horizontal to pass through the operating pointproviding a shifted pump curve. The ratio necessary to provide this shift is the head correction used in this approach.

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

illustrates the significance of accounting for the mechanical wear on pump performance.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.

illustrate a prototype ESP monitoring and control system.is a screenshot of an oil field overview interface. The oil field overview interfacedisplays motor loading, well status, pump model, smart functions, pump status, delta P at the surface, a well productivity index, an estimated production rate, a pump rating summary, and the total production rate for the field. The oil field overview interfacecan 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.

is a screenshot of a well gauges interface. The well gauges interfacedisplays a downhole motor load gauge, an operational pump condition gauge, a pressure delta gauge, an amperage gaugeof the selected ESP, a flow rate gaugefor the selected ESP, and a dropdown menufor selection of a specific well. These five gauges can be used to monitor production rate performance, ESP motor performance, and surface pressure performance.

The amperageof 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.

The flow rate gaugeshows 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. 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.

is a screenshot of a well history interface. The well history interfacedisplays historical data from a selected well including micromotion, pressure, downhole sensor readings, and motor electrical readings. This ESP historical data can be used to predict failures and trips. The well history interfacecan show the complete well history or selected periods.

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.

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.

illustrates hydrocarbon production operationsthat include both one or more field operationsand one or more computational operations, 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, specifically, for example, either as field operationsor computational operations, or both.

Examples of field operationsinclude 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. 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 operationsand responsively triggering the field operationsincluding, for example, generating plans and signals that provide feedback to and control physical components of the field operations. Alternatively or in addition, the field operationscan trigger the methods of the present disclosure. For example, implementing physical components (including, for example, hardware, such as sensors) deployed in the field operationscan generate plans and signals that can be provided as input or feedback (or both) to the methods of the present disclosure.

Examples of computational operationsinclude one or more computer systemsthat 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 operationscan be implemented using one or more databases, which store data received from the field operationsand/or generated internally within the computational operations(e.g., by implementing the methods of the present disclosure) or both. For example, the one or more computer systemsprocess inputs from the field operationsto assess conditions in the physical world, the outputs of which are stored in the databases. For example, seismic sensors of the field operationscan 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 operationswhere they are stored in the databasesand analyzed by the one or more computer systems.

In some implementations, one or more outputsgenerated by the one or more computer systemscan be provided as feedback/input to the field operations(either as direct input or stored in the databases). The field operationscan use the feedback/input to control physical components used to perform the field operationsin the real world.

For example, the computational operationscan process the seismic data to generate three-dimensional (3D) maps of the subsurface formation. The computational operationscan 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 operationsto process new information about the formation and control the drilling to adjust to the observed conditions in real-time.

The one or more computer systemscan update the 3D maps of the subsurface formation as information from one exploration well is received and the computational operationscan 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 operationsto 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 operationscan control machine operated valves upstream of the refinery to reduce the likelihood of plant disruptions that run the risk of taking the plant offline.

In some implementations of the computational operations, 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.

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.

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.