Systems and methods for artificial lift design

Abstract

A method of designing an artificial lift system for producing fluid from a wellbore includes receiving wellbore data indicating configuration specifications and production specifications for the wellbore and identifying a plurality of candidate electrical submersible pump (ESP) designs for implementing in the wellbore based on the wellbore data. The method further includes determining a design score for each of the plurality of candidate ESP designs, the candidate ESP designs each indicating a collection of downhole components defining an ESP system. The design score is based on inventory data for an inventory of available downhole components and historical wellbore data, the historical wellbore data indicating historical conditions for the wellbore and historical production performance for the wellbore. The method further includes selecting an ESP design from the plurality of candidate ESP designs based on an associated design score best fulfilling one or more criteria.

Description

IS24.1121-WO-PCTSYSTEMS AND METHODS FOR ARTIFICIAL LIFT DESIGNCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] The present application claims priority to and the benefit of United States Provisional Patent Application Serial No. 63 / 693292 titled “SYSTEMS AND METHODS FOR ARTIFICIAL LIFT DESIGN” filed September 11, 2024, the disclosure of which is incorporated herein by reference in its entirety.BACKGROUND OF THE DISCLOSURE

[0002] Wellbores may be drilled into a surface location or seabed for a variety of exploratory or extraction purposes. For example, a wellbore may be drilled to access fluids, such as liquid and gaseous hydrocarbons, stored in subterranean formations and to extract the fluids from the formations. Wellbores used to produce or extract fluids may be formed in earthen formations using earth-boring tools such as drill bits for drilling wellbores and reamers for enlarging the diameters of wellbores.

[0003] Some wellbores may implement electrical submersible pumps (ESPs) for facilitating flowing production fluids to the surface of the wellbore. For example, an ESP system or artificial lift system may be implemented in the wellbore and may include various components for generating artificial lift to lift production fluids to the surface. Over time these components wear and may eventually fail. Accurately predicting when downhole components will need replacing, as well as proactively designing ESP systems for implementing downhole to continue artificial lifting operations can reduce downtime and increase production.SUMMARY

[0004] In some embodiments, a method of designing an artificial lift system for producing fluid from a wellbore includes receiving wellbore data indicating configuration specifications and production specifications for the wellbore and identifying a plurality of candidate electrical submersible pump (ESP) designs for implementing in the wellbore based on the wellbore data. The method further includes determining a design score for each of the plurality of candidate ESP designs, the candidate ESP designs each indicating a collection of downhole components defining an ESP system. The design score is based on inventory data for an inventory of available downholeIS24.1121-WO-PCT components and historical wellbore data, the historical wellbore data indicating historical conditions for the wellbore and historical production performance for the wellbore. The method further includes selecting an ESP design from the plurality of candidate ESP designs based on an associated design score best fulfilling one or more criteria. In some embodiments, the method is performed by a computer system. In some embodiments, the method is performed as instructions stored on a computer-readable storage medium.

[0005] This summary is provided to introduce a selection of concepts that are further described in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. Additional features and aspects of embodiments of the disclosure will be set forth herein, and in part will be obvious from the description, or may be learned by the practice of such embodiments.BRIEF DESCRIPTION OF THE DRAWINGS

[0006] In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

[0007] FIG. 1-1 is an example of a downhole system, according to at least one embodiment of the present disclosure;

[0008] FIG. 1-2 is an example of a production system for producing a downhole fluid, according to at least one embodiment of the present disclosure;

[0009] FIG. 2-1 illustrates an example environment in which an ESP design system is implemented, according to at least one embodiment of the present disclosure;

[0010] FIG. 2-2 illustrates an example implementation of an ESP design system as described herein, according to at least one embodiment of the present disclosure;IS24.1121-WO-PCT

[0011] FIG. 3 illustrates a flow diagram for a method or a series of acts for designing an artificial lift system for producing fluid from a wellbore, according to at least one embodiment of the present disclosure.

[0012] FIG. 4 illustrates certain components that may be included within a computing system.BRIEF DESCRIPTION OF THE APPENDIX

[0013] Appendix A includes additional reference materials, the entireties of which, are hereby incorporated by reference. This document provides examples of one or more of the features described herein including, for example, evaluating various ESP designs.DETAILED DESCRIPTION

[0014] This disclosure generally relates to systems and methods for designing artificial lift systems for producing downhole fluids at a wellbore. A computer implemented ESP design system may facilitate identifying one or more best-fit or optimal ESP designs for implementing at a wellbore. For example, the ESP design system may receive information related to the configuration of the wellbore and production requirements for the wellbore, and based on this information may identify one or more, and in some cases all, possible ESP designs that may be implemented in the wellbore based on the specific configuration and production requirements.

[0015] The ESP design system may rank and / or filter one or more candidate ESP designs in order to identify those designs that may be most beneficial or may provide a highest value proposition for implementing at the wellbore. For example, the ESP design system may determine a weighted design score for each of the candidate ESP designs. The design score may be based on a variety of factors, such as flowrate, price, efficiency, motor load factor, output power, C02 emissions, risk, life cycle, or any other key performance indicator. The candidate ESP designs may be ranked or evaluated based on weights applied to the various factors or categories of the design scores, which may reflect the real -world objectives, priorities, preferences, or operational plans for a wellbore implementation. In this way, the ESP design system may generate and identify those ESP designs that may be most beneficial for a given production operation.

[0016] The ESP design system may also facilitate identifying or predicting when a current ESP system may need replacing. For example, the ESP design system may receive historical data associated with the wellbore, as well as historical data associated with other, related wellbores.IS24.1121-WO-PCTThe wellbores may be related in that they implement the same or similar downhole equipment or components. The wellbores may be similar based on the wellbores being similar in size, shape, trajectory, or by traversing or accessing the same or similar formation or reservoir. In this way, the ESP design system may identify the relationship and effect of environmental and downhole conditions on various, specific components, as well as the relationship and operational effect between various components. For example, the ESP design system may implement machine learning techniques to train models to learn these various relationships. In this way, the ESP design system may facilitate identifying or predicting when an ESP system may fail or degrade such that a new ESP system may be designed, ordered, distributed, etc. and may be readily available for timely implementation in the wellbore, minimizing downtime.

[0017] Additionally, the ESP design system may incorporate inventory data to the generating and ranking of ESP designs. For example, the ESP design system may have access to inventories of an operator, supplier, or other entities in order to identify which downhole components are readily available, and which may require lead time for manufacturing. The ESP design system may fdter or weigh designs according to availability of components in order to not only identify the best-fit design for a specific application, but a design that has available components that can be allocated and acquired in a timely manner.

[0018] In this way the ESP design system may facilitate efficiently and effectively generating ESP designs for production operations, including sourcing downhole components, in order that an ESP system may be timely implemented at a wellbore. This may be in contrast to, for example, traditional techniques, which may typically involve significant manual efforts, and through numerous entities operating based on independent silos of information. For example, typically, ESP design is a reactive process, and is performed in response to an ESP system failing. The process of implementing a new ESP system in the wellbore typically involves an engineer designing the ESP system, a supplier sourcing components, and the operator providing their requirements, objectives, preferences, etc. The process may delay significantly based on repeated communication between the various entities each having independent information before settling on an ESP design. Even still, based on the independent, siloed nature of the various entities involved, the ESP design may not be optimal or best-fit for the operator and their specific needs. Even further, the ESP design does not account for historical information for ensuring that design is optimal based on observable, historical data. Thus, by implementing the ESP design system, anIS24.1121-WO-PCTESP design may be generated and selected to meet the operator’s specific requirements, while also providing an optimal ESP design based on insight learned from a robust historical data set. The ESP design system may also facilitate designing an ESP system and acquiring necessary componentry as a proactive, rather than a reactive, exercise, for example, before a current ESP system failure, based on the ESP system predicting tool life of current ESP components.

[0019] Additional details will now be provided regarding systems described herein in relation to illustrative figures portraying example implementations. For example, FIG. 1-1 shows one example of a downhole system 100 for drilling an earth formation 101 to form a wellbore 102. The downhole system 100 includes a drill rig 103 used to turn a drilling tool assembly 104 which extends downward into the wellbore 102. The drilling tool assembly 104 may include a drill string 105, a bottomhole assembly (“BHA”) 106, and a bit 110 attached to the downhole end of the drill string 105.

[0020] The drill string 105 may include several joints of drill pipe 108 connected end-to-end through tool joints 109. The drill string 105 transmits drilling fluid through a central bore and transmits rotational power from the drill rig 103 to the BHA 106. In some embodiments, the drill string 105 further includes additional downhole drilling tools and / or components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid discharges through selected-size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, and for lifting cuttings out of the wellbore 102 as it is being drilled.

[0021] The BHA 106 may include the bit 110, other downhole drilling tools, or other components. An example BHA 106 may include additional or other downhole drilling tools or components (e.g., coupled between the drill string 105 and the bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing.

[0022] In general, the downhole system 100 may include other downhole drilling tools, components, and accessories such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the downhole system 100 may be considered aIS24.1121-WO-PCT part of the drilling tool assembly 104, the drill string 105, or a part of the BHA 106, depending on their locations in the downhole system 100.

[0023] The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials. For instance, the bit 110 may be a drill bit suitable for drilling the earth formation 101. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to the surface or may be allowed to fall downhole. The bit 110 may include one or more cutting elements for degrading the earth formation 101.

[0024] The BHA 106 may further include a rotary steerable system (RSS). The RSS may include directional drilling tools that change a direction of the bit 110, and thereby the trajectory of the wellbore. At least a portion of the RSS may maintain a geostationary position relative to an absolute reference frame, such as one or more of gravity, magnetic north, or true north. Using measurements obtained with the geostationary position, the RSS may locate the bit 110, change the course of the bit 110, and direct the directional drilling tools on a projected trajectory. The RSS may steer the bit 110 in accordance with or based on a trajectory for the bit 110. For example, a trajectory may be determined for directing the bit 110 toward one or more subterranean targets such as an oil or gas reservoir.

[0025] The downhole system 100 may be implemented as shown and described as part of a drilling and / or wellbore forming configuration of the downhole system 100. In some cases, the downhole system 100 may be implemented as a completion and / or production configuration having a different configuration of downhole components. For instance, a production system 111 is representative of an alternate or later implementation of at least a portion of the downhole system 100 having a combination of downhole components for a production phase of the downhole system 100. In some cases, after the wellbore 102 has been formed, one or more production or completion components may be installed or implemented in the wellbore 102 for facilitating the production and removal of a production fluid 144 from a reservoir 142. For instance, in some cases an electrical submersible pump (ESP) 140 may be implemented in the wellbore 102 for providingIS24.1121-WO-PCT supplemental pressure and / or flow to the production fluid 144, for example, above that which the reservoir 142 provides. In this way the ESP 140 may be an ESP system or artificial lift system configured to facilitate the production fluid 144 flowing to the surface.

[0026] FIG. 1-2 is an example of the production system 111 for producing the production fluid 144, according to at least one embodiment of the present disclosure. For example, one or more of the components of the production system 111 shown in FIG. 1-2 may be implemented in conjunction with, or in place of, one or more of the components of the downhole system 100 as shown in FIG. 1-1 after some or all of the wellbore 102 has been formed.

[0027] The production system 111 may include a collection of components for flowing and / or lifting the production fluid 144 from the reservoir 142, into the wellbore 102, and to the surface. For example, the production system 111 may include various surface equipment, such as wellhead equipment 160 for controlling and directing the flow of the production fluid 144 at the surface. The surface equipment may include electrical components such as a variable speed drive 161, set up transformer 162, etc., for providing electrical energy to one or more downhole components at a specific frequency and / or voltage. The production system 111 may include various components implemented within the wellbore such as a downhole motor 163 for driving the ESP 140; a protector 164 for shielding the motor 163 from wellbore fluids, pressure, and contaminants; and the ESP 140 having an intake, bolt on head 165, and various sections of tubing 166. The production system 111 may include a sliding sleeve 167 for facilitating the opening and closing of fluid ports in the tubing 16; a landing nipple 168 for setting and retrieving various downhole tools or devices; a packer 169 for sealing off the annulus of the wellbore 102; a vent valve 170 for allowing gas or air to escape from the tool string; a tubing retrievable safety valve 171 for shutting off fluid flow in case of emergency or failure; and one or more transmission and / or communication cables 172 for transmitting electrical power and / or data signals between the surface and downhole components. The production system 111 may be implemented with fewer and / or additional components to those shown and described here in order to facilitate the production of the production fluid 144. Additionally, the production system 111 may include multiple of one or more components, such as multiple ESPs 140 driven by the same motor 163.

[0028] In some embodiments, the ESP 140 may be instrumented and / or may be associated with one or more downhole sensors for providing measurements of one or more downhole parameters. For instance, one or more pressure sensors may indicate an input pressure to the ESP 140IS24.1121-WO-PCT associated with a flow of the production fluid 144 to the ESP (e.g., downhole of the ESP 140). The input pressure may often be associated with and / or provided via the subsurface reservoir 142, such as an inflow performance relationship (IPR). For example, a reservoir pressure may cause the production fluid 144 to flow from the reservoir 142 to the wellbore bottom hole at an input pressure. In some cases, one or more pressure sensors may indicate an output pressure from the ESP 140 associated with a flow of the production fluid 144 from the ESP 140, for example, uphole and to the surface. The output pressure may often be associated with a vertical lifting performance (VLP) relationship, or a pressure required to lift the production fluid 144 at a given flowrate to the surface. For instance, the ESP 140 may provide a pump effect, boost effect, or otherwise may make up a pressure differential between the input pressure (IPR) and the output pressure (VLP).

[0029] The various components of the production system 111 may be positioned downhole and in many cases as considerable depth. One or more of these components (e.g., ESP 140, motor 163, etc.) may experience wear and may have a life cycle. When one or more components fails or otherwise experiences degradation in performance, it may detrimentally effect a production operation of the wellbore 102. In various circumstances, it may be costly and time consuming to replace one or more components, or as is generally the case, the entire ESP system. For example, acquiring replacement components from a supplier can take weeks or months, and can come at a considerable expense. Further, in some cases a supplier may not have suitable components in inventory that meet production and other technical requirements of the production system 111, or else those in inventory may not be optimal for the requirements and objectives of a given operations. Still further, manufacturing various components can come at a considerable delay. Accordingly, it may be advantageous to not only predict and proactively replace or update components of the production system 111, but it may be advantageous to optimize, increase, or otherwise select the components to comprise an ESP system based on various constraints and performances metrics.

[0030] As shown in FIG. 1-1, the downhole system 100 may include or may be associated with a client device 112 with an ESP design system 120 implemented thereon (e.g., or with a client application implemented thereon for accessing the ESP design system 120 as described herein). The ESP design system 120 may facilitate designing a collection of downhole components for an ESP system. As described herein, the ESP design system 120 may generate an ESP design based on, among other considerations, historical data for the wellbore 102 in order to identify a bestIS24.1121-WO-PCT design for the constraints and objectives of the production system 1 11. Further, the ESP design may be based on an operator and / or supplier inventory to ensure that the downhole components of the design are timely available for quickly implementing downhole to minimize downtime.

[0031] FIG. 2-1 illustrates an example environment 200 in which the ESP design system is implemented in according with one or more embodiments described herein. As shown in FIG. 2- 1, the environment 200 may include a ESP design system 120 implemented on the server device 114. While shown on the server device 114, the ESP design system 120 may be implemented wholly or in part on the client device 112, across the server device 114 and the client device 112, or on or across one or more additional devices, such that different portions or components of the ESP design system 120 are implemented on different computing devices in the environment 200. The client device 112 may include a client application 118. The client application 118 may include an application or interface for interacting with and / or receiving the features of the ESP design system 120 as described herein. In some embodiments, one or more of the functionalities or features of the ESP design system 120 may be carried out or performed on or by the client application 118. In this way, the environment 200 may be a cloud computing environment, and the ESP design system 120 may be implemented across one or more devices of the cloud computing environment in order to leverage the processing capabilities, memory capabilities, connectivity, speed, etc., that such cloud computing environments offer in order to facilitate the features and functionalities described herein.

[0032] FIG. 2-2 illustrates an example implementation of the ESP design system 120 as described herein, according to at least one embodiment of the present disclosure. The ESP design system 120 may include a data manager 122, an ESP design engine 124, and a ranking manager 126. The ESP design system 120 may also include a data storage 130 having wellbore data 132, inventory data 134, ESP designs 136, and design scores 138 stored thereon. While one or more embodiments described herein describe features and functionalities performed by specific components 122-126 of the ESP design system 120, it will be appreciated that specific features described in connection with one component of the ESP design system 120 may, in some examples, be performed by one or more of the other components of the ESP design system 120.

[0033] By way of example, one or more of the data receiving, gathering, or storing features of the data manager 122 may be delegated to other components of the ESP design system 120. As another example, while ESP designs may be generated by the ESP design engine 124, in some instances,IS24.1121-WO-PCT some or all of these features may be performed by the ranking manager 126 (or other component of the ESP design system 120). Indeed, it will be appreciated that some or all of the specific components may be combined into other components and specific functions may be performed by one or across multiple components 122-126 of the ESP design system 120.

[0034] Additionally, while FIG. 1, for example, depicts the ESP design system 120 implemented on a client device 112 of the downhole system, it should be understood that some or all of the features and functionalities of the ESP design system 120 may be implemented on or across multiple client devices 112 and / or server devices 114. For example, data may be input and / or received by the data manager 122 on a (e.g., local) client device, and ESP designs may be generated and / or ranked on one or more of a remote, server, or cloud device. Indeed, it will be appreciated that some or all of the specific components 122-126 may be implemented on or across multiple client devices 112 and / or server devices 114, including individual functions of a specific component being performed across multiple devices.

[0035] As mentioned above, the ESP design system 120 includes a data manager 122. The data manager 122 may receive a variety of types of data associated with the downhole system and may store the data to the data storage 130. The data manager 122 may receive the data from a variety of sources, such as from sensors, surveying tools, downhole tools, other (e.g., client) devices, libraries, databases, user input, etc.

[0036] In some embodiments, the data manager 122 receives wellbore data associated with a target wellbore, subject wellbore, or wellbore of interest. In some cases, the wellbore data 132 includes information associated with a configuration specification of the wellbore. For instance, the wellbore data 132 may indicate a length, depth, orientation, inclination, azimuth, trajectory, and other similar data for the wellbore. The wellbore data 132 may indicate a gauge or diameter of the wellbore at one or more measurement depths of the wellbore. The wellbore data 132 may indicated one or more completion components implemented in the wellbore, such as casing, packers, plugs, hangars, etc. as well as their location.

[0037] In some embodiments, the wellbore data 132 indicates a configuration of downhole components or tools implemented in the wellbore. For example, the wellbore data 132 may indicate a current ESP design that is implemented and / or currently producing fluid from the wellbore. The current ESP design may include a number, type, position, and / or configuration of a collection of downhole components that may comprise the an ESP system implemented in theIS24.1121-WO-PCT wellbore. For example, the ESP design may include one or more motors, protectors, intakes, outlets, pumps, cables, gas handlers or separators, sensors, or other components and combinations thereof. The wellbore data 132 may indicate a type and / or size of the various components, including an indication of their capability with other components. For example, the wellbore data 132 may identify part numbers and / or serial numbers for the various components and / or may indicate technical ratings or specifications for one or more components. In some cases, the wellbore data 132 includes information associated with a tool life of one or more components, such as an installation date, total and / or average run times, total and / or average production amounts, average and / or expected tool life, etc. In this way, the wellbore data 132 may include a variety of information associated with the configuration of the wellbore, including the components implemented within the wellbore.

[0038] In some embodiments, the wellbore data 132 includes information associated with a production of reservoir fluids or other downhole and / or production fluids (e.g., hydrocarbons). For example, the wellbore data 132 may indicate a current and / or historical production from the wellbore, such as flowrates of production fluid produced from the wellbore. In some cases, the data manager 122 may access live and / or real time (or near real time) data and the wellbore data 132 may indicate the current and / or recent production information. The wellbore data 132 may also include historical wellbore information, such as totals, averages, trends, and other statistical information associated with the production of fluids from the wellbore.

[0039] In some embodiments, the wellbore data 132 may indicate various conditions associated with the wellbore. For example, the wellbore data 132 may indicate a location and / or depth of a reservoir, such as the depth of a target or production zone. The wellbore data 132 may indicate temperatures and / or pressures at various locations in the wellbore. For example, the wellbore data 132 may indicate a reservoir pressure, an ESP input pressure (e.g., IPR), an ESP output pressure (e.g., VLP), a surface pressure, etc. In some cases, the wellbore data 132 indicates conditions of the production fluid, such as the presence and quantity of sand, salt, gas, or other compositions of the production fluid. The wellbore data 132 may indicate present and historical states of the various conditions. In this way, the wellbore data 132 may characterize various properties and behaviors of the wellbore, reservoir, etc.

[0040] In some embodiments, the various configuration information and / or condition information may be associated with a target wellbore. In some embodiments the wellbore data 132 may includeIS24.1121-WO-PCT the various information discussed herein with respect to one or more (or many) other wellbores. For example, the wellbore data 132 may include data associated with other wellbore having the same or similar configuration of ESP design implemented therein. In some cases, the wellbore data 132 may include data associated with wellbores that are similar in one or more respects, such as by having similar size, length, and / or trajectory, and / or that traverse similar formations or access the same or similar reservoirs. As discussed herein, the wellbore data 132 in this way may facilitate identifying or predicting life cycles or failure events of one or more components.

[0041] In some embodiments, the data manager 122 may predict or estimate a future state of one or more wellbore and / or reservoir conditions. For example, the data manager 122 may access survey data or other measurement data for determining wellbore a condition. For instance, the data manager 122 may perform or may access sensitivity analyses which may indicate past, present, and / or changing conditions of the wellbore and / or reservoir, and may infer or predict how the conditions may change for one or more future time intervals. In some embodiments the data manager 122 predicts conditions using machine learning techniques. For example, one or more machine learning models may be trained based on historical conditions of other wellbores that are related (e.g., to each other and / or to a target wellbore) and may be trained to predict based on an input of current and / or historical condition data for a target wellbore, how those conditions may change in the future. In this way, the predicted, future conditions may serve as a basis for determining ESP designs as described herein, rather than relying wholly on presently observable conditions which may be subject to change.

[0042] In some cases, the data manager 122 may predict or estimate tool life and / or failure of one or more components of a current ESP design. For example, as mentioned, the data manager 122 may have access to historical data for other or offset wellbores, including information that may identify specific components implemented in these wellbores and their specific use metrics. The data manager 122 may access or determine averages, means, medians, and other statistical values associated with the useful life of the various components, including when components fail and / or degrade. Accordingly, the data manager 122 may estimate (e.g., based on mean time to failure) a useful tool life and / or future failure of one or more components and / or the ESP design as a whole. In this way, the data manager 122 may identify, as a proactive or preemptive measure, that an ESP system implemented in a target wellbore is likely to fail. As described herein, this may facilitateIS24.1121-WO-PCT designing, ordering, and / or having components on hand to replace a current ESP design in a timely manner, before failure or at the point of failure.

[0043] In some cases, the data manager 122 may predict tool life and / or failure of one or more components by implementing machine learning techniques. For example, one or more machine learning models may be trained based on failure information for a plurality of offset wellbores and based on the various downhole components and ESP designs implanted in those wellbores. Additionally, the machine learning models may be trained based on the specific wellbore, reservoir, and / or fluid conditions associated with those wellbores. Leveraging machine learning in this way may provide a more reliable and accurate prediction of tool life. For example, the machine learning models may learn the delicate interplay between the various components that my be implemented in an ESP design, and how some components may affect the operation and wear of other components. In another example, the machine learning modes may learn how certain components behave and / or wear when exposed to certain downhole conditions. Accordingly, based on an input of a current ESP design, as well as inputting information associated with a target wellbore (e.g., including current conditions and configurations), the machine learning model(s) may predict when the various components of a target wellbore may experience failure or degradation.

[0044] In some embodiments, the data manager 122 receives inventory data 134. The inventory data 134 may indicate a variety of downhole components that are available for implementing in an ESP design. For example, the inventory data 134 may indicate which downhole components are in an operator’s inventory. For instance, an operator may be an individual, group, or organization that owns and / or operates a wellbore to produce production fluids. The operator’s inventory may include various components, parts, tools, etc. that are available and / or at the disposal of the operator, such as located at a wellsite, at a warehouse of other facility, or otherwise are allocated to the operator. In some embodiments, the inventory data 134 indicates which downhole components are in a supplier’s inventory. For example, the supplier may be a manufacturer, distributor, or other entity which may broker or deal in downhole components. The supplier’s inventory may include the various components which are available for purchase, shipping, or otherwise for allocation to an operator, such as physical components that are already manufactured and are physically available. In some embodiments, the inventory data 134 may indicate one orIS24.1121-WO-PCT more components that are scheduled or soon to be manufactured, repaired, or otherwise available, including a timeframe for availability.

[0045] The inventory data 134 may indicated technical details and / or specifications for the various components. For example, the inventory data 134 may indicate recommended or rated values or ranges for operating the various components, such as flow rates, pressures, temperatures, power outputs, power consumption, efficiency, or other measures. The inventory data 134 may indicate a sizing and / or standardization of the various components, such as providing an indication of compatibility between the various components. For instance, the inventory data 134 may identify a gauge or diameter of the various components, indicating a compatibility and / or suitability for the various components to be implemented in a wellbore of a given diameter. As an example, the inventory data 134 may indicate a housing size or diameter for an ESP as well as a size of a lens. In some cases, the inventory data 134 may indicate a pricing for the various components.

[0046] In some embodiments, the data manager 122 receives user input. The data manager 122 may receive the user input, for example, via any of the client devices 112 and / or server devices 114. Any of the data described herein may be input or augmented via the user input. For example, in some instances, some or all of the inventory data 134 is input and / or manipulated by user input. The user input may be received in association with one or more functions or features of the ESP design system 120, such as part of determining design scores 138 and / or ranking candidate ESP designs as described herein, or any other feature.

[0047] As mentioned above, the ESP design system 120 includes an ESP design engine 124. The ESP design engine 124 may facilitate generating various ESP designs, or various collections of downhole components that may be assembled as an ESP system and implemented in a wellbore to extract production fluids. The ESP design engine 124 may generate a plurality of candidate ESP designs and store them to the data storage 130 as ESP designs 136. For example, based on the wellbore data 132, the ESP design engine 124 may determine various collections of downhole components that may be assembled in order to meet the needs and requirements of a given wellbore. The candidate ESP designs may be potential ESP designs for implementing in a wellbore and may be evaluated as described herein based on various criteria.

[0048] In some examples, the ESP design engine 124 identifies candidate ESP designs based on configuration specifications for the wellbore. For instance, the ESP design engine 124 may identify candidate ESP designs that comprise components that may be configurable and / or compatible withIS24.1121-WO-PCT one another to form an ESP system. To elaborate, the candidate ESP designs may be identified based on collections of components that are a same gauge or diameter, as well as being interoperable with one another. The ESP design engine 124 may additionally consider the sizing (e.g., diameter) and other configurations of the wellbore (e.g., diameter) in order to identify candidate ESP designs. For example the candidate ESP designs may include components that have a same or smaller diameter to that of the wellbore.

[0049] In some cases, the ESP design engine 124 identifies candidate ESP designs based on production specifications for the wellbore. For example, a wellbore may have a production requirement or objective, such as producing fluids at a certain flowrate at the surface, often measured in barrels per day. The candidate ESP designs may be generated in order that they facilitate producing a specified flowrate for the production fluids. In other cases, the candidate ESP designs may be determined based on other specifications for providing artificial lift of productions fluids. For example, the candidate ESP designs may be generated to provide sufficient artificial lift to production fluids at a certain depth of a reservoir or production zone of a wellbore, with a given input pressure from a reservoir pressure (e.g., IPR), having a given output or wellbore pressure (e.g., VLP), or other production specifications for a wellbore.

[0050] In this way, various candidate ESP designs may be determined in order that fulfill or meet the specific needs and objectives of a given wellbore. In some cases the ESP design engine 124 determines all possible candidate ESP designs. That is, the ESP design engine 124 may identify all possible collections or iterations of downhole components that may both be compatible (e.g., with each other and with the wellbore), as well as provide the desired production specifications for producing fluids at the surface of the wellbore. In some cases, the ESP design engine 124 may identify less than all possible candidate ESP designs, such as a determining a set number of candidate ESP designs, or operating for a set amount of time to determine candidate ESP designs.

[0051] As an illustrative example, a wellbore may have a diameter of 12 inches at a production zone that is located at a depth of 900 feet. It may be desirable to identify candidate ESP designs that may be implemented in the wellbore for producing fluids from the production zone at a rate of 1500 barrels per day. The ESP design engine 124 may generate a first candidate ESP design that includes a first ESP that is capable of producing 1300-2000 barrels per day, and at the given depth. The first ESP design may include various other components associated with implementing the first ESP, including a downhole motor for driving the first ESP. the ESP design engine 124IS24.1121-WO-PCT may also generate a second candidate ESP design that includes a second ESP that is capable of producing 1100-1600 barrels per day at the 900 ft depth, including various components for facilitating the second ESP. In this way, the ESP design engine 124 identifies different combinations of downhole components that may fulfill the needs of the wellbore, but may have different technical specifications, advantages, capabilities, etc. For example, while the first and second ESPs may each provide the specified flowrate of 1500 barrels per day, they may each operate at that flowrate on different parts of their respective motor curves, at different efficiencies etc., resulting in different power consumptions, levels of wear, etc. Accordingly, these candidate ESP designs may be evaluated based on this (and other) criteria in order to differentiate the designs and determine a design that is best suited for the specific objectives, constraints, performance indicators, etc. of a given operation.

[0052] As mentioned above, the ESP design system 120 includes a ranking manager 126. The ranking manager 126 facilitates evaluating the candidate ESP designs 136 based on various criteria in order to identify and / or select an ESP design that is a best fit for a given wellbore and production operation.

[0053] In some embodiments, the ranking manager 126 evaluates the candidate ESP designs based on determining design scores 138 for each of the candidate ESP designs. The design scores may be determined based on a cost function, and may represent a value proposition or opportunity value for the candidate ESP designs with respect to the specific objectives and requirements of a given production operation.

[0054] In some embodiments, the design scores 138 may characterize the value of the candidate ESP designs based on a variety of factors. In some cases, the design scores 138 incorporate a production factor, such as evaluating how high or how close to a target value a flowrate of the design is. In some examples, the design scores 138 incorporate a price factors for purchasing, distributing, and / or implementing the collection of components of a design. The design scores 138 may be determined based the operation of the ESP and / or downhole motor. For example, the design scores 138 may quantify a power efficiency and / or power consumption of an ESP (e.g., via a downhole motor), a load factor or percent of motor capacity required to operate the ESP(s), and / or an output power (e.g., horsepower) of a motor-pump(s) combination. In some embodiments, the design scores 138 may be based on the average or expected C02 emissions of a given design.IS24.1121-WO-PCT

[0055] In some cases, the ranking manager 126 determines the design scores 138 based on life cycle factor. For example, the ranking manager 126 may receive or may determine as described herein, an expected life cycle or time to failure for a given design, or more specifically, for each of (or the collection of) the components of a given design. In some cases, the ranking manager 126 may determine a risk score for incorporating into the design score. For example, the ranking manager 126 may determine a level of suitability or risk of a given design associated with implementing the specific components of the design in a wellbore given the production requirements and / or (present or future predicted) conditions associated with the wellbore. For example, the ranking manager 126 may determine that, given a sand or salinity content of the production fluid, that one or more of the components of a design is not particularly suited to withstanding such conditions, and may accordingly assign a higher risk (or lower suitability) score to the design, which may negatively affect the overall design score 138. The ranking manager 126 may evaluate life cycle and / or risk associated with a given design based on historical configuration, production, and / or condition information for a plurality of wellbores (including a target wellbore), for example, based on past performance and behavior of similar component and / or wellbores. For example, the ranking manager 126 may incorporate machine learning techniques to learn relationship between various implemented ESP design configurations, wellbore conditions etc., to accurately predict how a give design will perform. The design scores 138 may include and / or may be determined based on any other factor, category, criteria, key performance indicator, etc.

[0056] The ranking manager 126 may determine the design scores 138 based on assigning values to each factor and based on a normalized scale. For example, each factor may be assigned a value between 0 and 1, 0 and 10 or other normalized scale, based on the design’s strength for a given factor or category. In some cases, the value assigned for a given factor may be based on how high or how much of that factor a given design achieves. For example, a design with a higher efficiency may be assigned a higher value for an efficiency factor. Similarly, a design with a lower price may be assigned a higher value for a price factor. In some case, the value assigned for a given factor may be based on a target value, and how close the design comes to that target value. For example, an operation may dictate a target flow rate of 480 barrels per day, and designs coming closer to that flow rate may be assigned higher values while designs that far exceed or fall short of the target value may be assigned lower values for a production metric. In this way, the sum total of all theIS24.1121-WO-PCT values may quantify the value proposition of each design given the specific criteria and objectives for a given production operation.

[0057] In some embodiments, the ranking manager 126 ranks the candidate ESP designs based on the design scores 138. For example, the ranking manager 126 may present one (or several) best-fit ESP designs that had a highest design score 138. In some embodiments, the ranking manager 126 may select a best-fit ESP design for presenting, for providing to another system or user, and / or for implementing in the wellbore. In some embodiments, the ranking manager 126 ranks the candidate ESP designs based on scores from a specific factor or category. For example, the ranking manager 126 may identify several candidate ESP designs that had highest design scores 138, and may further rank or differentiate the candidate ESP designs based on their individual scores in one or more categories. As an example, the ranking manager 126 may identify 10 candidate ESP designs that all had high or highest design scores 138 (e g., the same design score or similar within a threshold), and may further rank, differentiate, or identify those designs from the 10 high scoring candidate ESP designs that scored highest in an efficiency category, in a price category, in a production category, or another category. In this way, the ranking manager 126 may identify one or more ESP designs that may be suitable, valuable, advantageous, or otherwise desirable for implementing in the wellbore.

[0058] In some cases, the ranking manager 126 may determine the design scores 138 and rank the candidate ESP designs based on weighting one or more factors or categories. The weightings may be determined based on the objectives or requirements of a given operations, such as being user or client-defined. For example, in some cases, it may be advantageous to identify candidate ESP designs that have a lower level of risk and / or a longer expected life cycle over, for example, ESP designs that have a lower price. The design scores 138 may weighted accordingly to reflect the relative preference or importance of these factors. In another example, it may be desirable to identify candidate ESP designs that are highly efficient and have lower C02 emissions, and the design scores 138 may accordingly be weighted to advantageously identify these preferences.

[0059] In some embodiments, the ranking manager 126 may facilitate adjusting or modifying the weights (e.g., and therefore the rankings) of the design scores 138 to facilitate identify candidate ESP designs corresponding with different objectives, preferences, or operational plans for a wellbore. For example, the ranking manager 126 may receive user input for modifying and / orIS24.1121-WO-PCT adjusting the weights one or more times to present different rankings of candidate ESP designs to facilitate conceptualizing which ESP designs may be best applicable for different scenarios.

[0060] In some cases, the ranking manager 126 may filter out, eliminate, or penalize one or more designs based on the inventory data 134. For example, as mentioned above, the inventory data 134 may indicate an availability and / or stock of various components in an operator’s inventory and / or a suppliers inventory. The ranking manager 126 may identify candidate ESP designs that include components that are not available and / or not in one or more (or all) inventories and may filter these designs. For example, the ranking manager 126 may remove these designs such that the candidate ESP design rankings only include those designs which can be readily and / or timely purchased, distributed, and / or implemented at a wellbore in a timely manner. In some cases, the ESP ranking manager 126 may penalize designs having one or more unavailable components but may nevertheless include these designs in the rankings. In some embodiments, the ranking manager 126 may filter and / or penalize designs having one or more unavailable components based on a lead time for when the components may become available. For example, designs having a longer lead time may be more heavily penalized. In this way, the ranking manager 126 may identify one or more ESP designs for implementing in a wellbore and for optimally fulfilling certain objectives or criteria for the wellbore, but may also advantageously incorporate the inventory data to identify high-value ESP designs with an eye toward availability and timely implementation.

[0061] FIG. 3 illustrates a flow diagram for a method 300 or a series of acts for designing an artificial lift system for producing fluid form a wellbore as described herein, according to at least one embodiment of the present disclosure. While FIG. 3 illustrates acts according to one embodiment, alternative embodiments may add to, omit, reorder, or modify any of the acts of FIG. 3. In some embodiments, series of acts is performed as a method. In some embodiments, the series of acts is performed by a computer system. In some embodiments, the series of acts is performed as instructions stored on a computer-readable storage medium.

[0062] In some embodiments, the method 300 includes an act 310 of receiving wellbore data indicating configuration specifications and production specifications for the wellbore.

[0063] In some embodiments, the method 300 includes an act 320 of identifying a plurality of candidate electrical submersible pump (ESP) designs for implementing in the wellbore based on the wellbore data.IS24.1121-WO-PCT

[0064] In some embodiments, the method 300 includes an act 330 of determining a design score for each of the plurality of candidate ESP designs, the candidate ESP designs each indicating a collection of downhole components defining an ESP system; wherein the design score is based on inventory data for an inventory of available downhole components and historical wellbore data, the historical wellbore data indicating historical conditions for the wellbore and historical production performance for the wellbore.

[0065] In some embodiments, the method 300 includes an act 340 of selecting an ESP design from the plurality of candidate ESP designs based on an associated design score best fulfilling one or more criteria.

[0066] In some embodiments, the configuration specifications indicate one or more of a diameter of the wellbore at one or more depths, a depth of the wellbore, a current ESP system implemented in the wellbore including a collection of downhole components of the current ESP system; a casing configuration; or production component configuration.

[0067] In some embodiments, the production specifications for the wellbore include one or more of a desired surface flowrate for the wellbore, or a depth of a production zone of the wellbore.

[0068] In some embodiments, the historical conditions for the wellbore include one or more of a reservoir pressure or inflow performance relationship for the wellbore, a wellbore pressure loss or vertical lifting pressure relationship for the wellbore, or production fluid conditions for the wellbore.

[0069] In some embodiments, the historical production performance includes one or more of a historical surface flowrate for the wellbore, a power output of an ESP of the wellbore, or a power consumption of a downhole motor.

[0070] In some embodiments, the inventory data indicates one or more of downhole components available in an operator inventory, or downhole components available in a supplier inventory.

[0071] In some embodiments, the design score for each candidate ESP design is further based on one or more of implementation cost, production specification, efficiency, motor load factor, ESP power, fluid condition capability, a lifecycle estimate, or C02 emissions.

[0072] In some embodiments, selecting the ESP design based on the one or more criteria includes determining the design score for each of the candidate ESP designs based on weighting in accordance with the one or more criteria.IS24.1121-WO-PCT

[0073] In some embodiments, the one or more criteria includes one or more of a price constraint, an efficiency constraint, a surface flowrate constraint, or a C02 emissions constraint.

[0074] In some embodiments, the collection of downhole components of each of the candidate ESP designs includes one or more of a downhole motor, an ESP, a protector, an intake, electrical cables, sensors, gas handlers, or gas separators.

[0075] In some embodiments, the method includes predicting a tool life of a current ESP system of the wellbore based on the historical wellbore data and the configuration specification, and wherein receiving, identifying, determining and selecting is based on predicting the tool life.

[0076] In some embodiments, the method includes predicting tool life using a tool life machine learning model that is trained based on training data that includes failure information for a plurality of ESP system configurations and wellbore condition information for a plurality of wellbores, and that is trained to predict a target tool life for a target wellbore based on target wellbore condition information and ESP system configuration.

[0077] In some embodiments, the one or more criteria are based on user input.

[0078] In some embodiments, the method includes providing at least some of the collection of downhole components of the selected ESP design for implementing in the wellbore.

[0079] In some embodiments, the method includes implementing the collection of downhole components of the selected ESP design for producing the fluid from the wellbore.

[0080] In some embodiments, implementing includes assembling the collection of downhole components as an ESP system, conveying the ESP system into the wellbore, and operating the ESP system to produce the fluid from the wellbore.

[0081] In some embodiments, selecting the ESP design includes fdtering one or more of the candidate ESP designs based on the filtered candidate ESP designs not fulfilling one or more of the one or more criteria.

[0082] In some embodiments, the design score for each of the plurality of candidate ESP designs is further determined based on predicting a future condition for the wellbore.

[0083] Turning now to FIG. 4, this figure illustrates certain components that may be included within a computer system 400. One or more computer systems 400 may be used to implement the various devices, components, and systems described herein.

[0084] The computer system 400 includes a processor 401. The processor 401 may be a general- purpose single- or multi-chip microprocessor (e.g., an Advanced RISC (Reduced Instruction SetIS24.1121-WO-PCTComputer) Machine (ARM)), a special purpose microprocessor (e.g., a digital signal processor (DSP)), a microcontroller, a programmable gate array, etc. The processor 401 may be referred to as a central processing unit (CPU). Although just a single processor 401 is shown in the computer system 400 of FIG. 4, in an alternative configuration, a combination of processors (e.g., an ARM and DSP) could be used.

[0085] The computer system 400 also includes memory 403 in electronic communication with the processor 401. The memory 403 may include computer-readable storage media and can be any available media that can be accessed by a general purpose or special purpose computer system. Computer-readable media that store computer-executable instructions are non-transitory computer-readable media (device). Computer-readable media that carry computer-executable instructions are transmission media. Thus, by way of example and not limitations, embodiment of the present disclosure can comprise at least two distinctly different kinds of computer-readable media: non-transitory computer-readable media (devices) and transmission media.

[0086] Both non-transitory computer-readable media (devices) and transmission media may be used temporarily to store or carry software instructions in the form of computer readable program code that allows performance of embodiments of the present disclosure. Non-transitory computer- readable media may further be used to persistently or permanently store such software instructions. Examples of non-transitory computer-readable storage media include physical memory (e.g., RAM, ROM, EPROM, EEPROM, etc ), optical disk storage (e.g., CD, DVD, HDDVD, Blu-ray, etc ), storage devices (e.g., magnetic disk storage, tape storage, diskette, etc.), flash or other solid- state storage or memory, or any other non-transmission medium which can be used to store program code in the form of computer-executable instructions or data structures and which can be accessed by a general purpose or special purpose computer, whether such program code is stored or in software, hardware, firmware, or combinations thereof.

[0087] Instructions 405 and data 407 may be stored in the memory 403. The instructions 405 may be executable by the processor 401 to implement some or all of the functionality disclosed herein. Executing the instructions 405 may involve the use of the data 407 that is stored in the memory 403. Any of the various examples of modules and components described herein may be implemented, partially or wholly, as instructions 405 stored in memory 403 and executed by the processor 401. Any of the various examples of data described herein may be among the data 407IS24.1121-WO-PCT that is stored in memory 403 and used during execution of the instructions 405 by the processor 401.

[0088] A computer system 400 may also include one or more communication interfaces 409 for communicating with other electronic devices. The communication interface(s) 409 may be based on wired communication technology, wireless communication technology, or both. Some examples of communication interfaces 409 include a Universal Serial Bus (USB), an Ethernet adapter, a wireless adapter that operates in accordance with an Institute of Electrical and Electronics Engineers (IEEE) 802.11 wireless communication protocol, a Bluetooth® wireless communication adapter, and an infrared (IR) communication port.

[0089] The communication interfaces 409 may connect the computer system 400 to a network. A “network” or “communications network” may generally be defined as one or more data links that enable the transport of electronic data between computer systems and / or modules, engines, or other electronic devices, or combinations thereof. When information is transferred or provided over a communication network or another communications connection (either hardwired, wireless, or a combination of hardwired or wireless) to a computing device, the computing device properly views the connection as a transmission medium. Transmission media can include a communication network and / or data links, carrier waves, wireless signals, and the like, which can be used to carry desired program or template code means or instructions in the form of computer-executable instruction or data structures and which can be accessed by a general purpose or special purpose computer.

[0090] A computer system 400 may also include one or more input devices 411 and one or more output devices 413. Some examples of input devices 411 include a keyboard, mouse, microphone, remote control device, button, joystick, trackball, touchpad, and lightpen. Some examples of output devices 413 include a speaker and a printer. One specific type of output device that is typically included in a computer system 400 is a display device 415. Display devices 415 used with embodiments disclosed herein may utilize any suitable image projection technology, such as liquid crystal display (LCD), light-emitting diode (LED), gas plasma, electroluminescence, or the like. A display controller 417 may also be provided, for converting data 407 stored in the memory 403 into one or more of text, graphics, or moving images (as appropriate) shown on the display device 415.IS24.1121-WO-PCT

[0091] The various components of the computer system 400 may be coupled together by one or more buses, which may include one or more of a power bus, a control signal bus, a status signal bus, a data bus, other similar components, or combinations thereof. For the sake of clarity, the various buses are illustrated in FIG. 4 as a bus system 419.

[0092] The techniques described herein may be implemented in hardware, software, firmware, or any combination thereof, unless specifically described as being implemented in a specific manner. Any features described as modules, components, or the like may also be implemented together in an integrated logic device or separately as discrete but interoperable logic devices. If implemented in software, the techniques may be realized at least in part by a non-transitory processor-readable storage medium comprising instructions that, when executed by at least one processor, perform one or more of the methods described herein. The instructions may be organized into routines, programs, objects, components, data structures, etc., which may perform particular tasks and / or implement particular data types, and which may be combined or distributed as desired in various embodiments.

[0093] Further, upon reaching various computer system components, program code in the form of computer-executable instructions or data structures can be transferred automatically or manually from transmission media to non-transitory computer-readable storage media (or vice versa). For example, computer executable instructions or data structures received over a network or data link can be buffered in memory (e.g., RAM) within a network interface module (NIC), and then eventually transferred to computer system RAM and / or to less volatile non-transitory computer- readable storage media at a computer system. Thus, it should be understood that non-transitory computer-readable storage media can be included in computer system components that also (or even primarily) utilize transmission media.INDUSTRIAL APPLICABILITY

[0094] The following description from

[0095] —

[0114] includes various embodiments that, where feasible, may be combined in any permutation. For example, the embodiment of

[0095] may be combined with any or all embodiments of the following paragraphs. Embodiments that describe acts of a method may be combined with embodiments that describe, for example, systems and / or devices. Any permutation of the following paragraphs is considered to be hereby disclosed for the purposes of providing “unambiguously derivable support” for any claim amendment based on theIS24.1121-WO-PCT following paragraphs. Furthermore, the following paragraphs provide support such that any combination of the following paragraphs would not create an “intermediate generalization.”

[0095] In some embodiments, a method of designing an artificial lift system for producing fluid from a wellbore includes receiving wellbore data indicating configuration specifications and production specifications for the wellbore, identifying a plurality of candidate electrical submersible pump (ESP) designs for implementing in the wellbore based on the wellbore data, determining a design score for each of the plurality of candidate ESP designs, the candidate ESP designs each indicating a collection of downhole components defining an ESP system; wherein the design score is based on inventory data for an inventory of available downhole components and historical wellbore data, the historical wellbore data indicating historical conditions for the wellbore and historical production performance for the wellbore, and selecting an ESP design from the plurality of candidate ESP designs based on an associated design score best fulfilling one or more criteria.

[0096] In some embodiments, the configuration specifications indicate one or more of a diameter of the wellbore at one or more depths, a depth of the wellbore, a current ESP system implemented in the wellbore including a collection of downhole components of the current ESP system, or combinations thereof; one or more casing configurations; or one or more production component configurations; or combinations thereof.

[0097] In some embodiments, the production specifications for the wellbore include one or more desired surface flowrates for the wellbore, one or more depths of a production zone of the wellbore, or combinations thereof.

[0098] In some embodiments, the historical conditions for the wellbore include one or more of a reservoir pressure and / or one or more of an inflow performance relationship for the wellbore, one or more of a wellbore pressure loss and / or one or more of a vertical lifting pressure relationship for the wellbore, one or more of production fluid conditions for the wellbore, or combinations thereof.

[0099] In some embodiments, the historical production performance includes one or more of a historical surface flowrate for the wellbore, a power output of an ESP of the wellbore, or a power consumption of a downhole motor.

[0100] In some embodiments, the inventory data indicates one or more of downhole components available in an operator inventory, or downhole components available in a supplier inventory.IS24.1121-WO-PCT

[0101] In some embodiments, the design score for each candidate ESP design is further based on one or more of implementation cost, production specification, efficiency, motor load factor, ESP power, fluid condition capability, a lifecycle estimate, or C02 emissions, and combinations thereof.

[0102] In some embodiments, selecting the ESP design based on the one or more criteria includes determining the design score for each of the candidate ESP designs based on weighting in accordance with the one or more criteria.

[0103] In some embodiments, the one or more criteria includes one or more of a price constraint, an efficiency constraint, a surface flowrate constraint, or a C02 emissions constraint, and combinations thereof.

[0104] In some embodiments, the collection of downhole components of each of the candidate ESP designs includes one or more of a downhole motor, an ESP, a protector, an intake, electrical cables, sensors, gas handlers, or gas separators, and combinations thereof.

[0105] In some embodiments, the method includes predicting a tool life of a current ESP system of the wellbore based on the historical wellbore data and the configuration specification. In some embodiments, one or more of receiving, identifying, determining or selecting is based on predicting the tool life.

[0106] In some embodiments, the method includes predicting tool life using a tool life machine learning model that is trained based on training data that includes failure information for a plurality of ESP system configurations and / or wellbore condition information for a plurality of wellbores. In some embodiments, the machine learning model is trained to predict a target tool life for a target wellbore based on target wellbore condition information and / or ESP system configuration.

[0107] In some embodiments, the one or more criteria are based on user input.

[0108] In some embodiments, the method includes providing at least some of the collection of downhole components of the selected ESP design for implementing in the wellbore.

[0109] In some embodiments, the method includes implementing the collection of downhole components of the selected ESP design for producing the fluid from the wellbore.

[0110] In some embodiments, implementing includes one or more of assembling the collection of downhole components as an ESP system, conveying the ESP system into the wellbore, or operating the ESP system to produce the fluid from the wellbore.IS24.1121-WO-PCT

[0111] In some embodiments, selecting the ESP design includes filtering one or more of the candidate ESP designs based on the filtered candidate ESP designs not fulfilling one or more of the one or more criteria.

[0112] In some embodiments, the design score for each of the plurality of candidate ESP designs is further determined based on predicting a future condition for the wellbore.

[0113] In some embodiments, the method is performed by a computer system.

[0114] In some embodiments, the method is performed as instructions stored on a computer- readable storage medium.

[0115] The embodiments of the ESP design system have been primarily described with reference to wellbore drilling operations; the ESP design system described herein may be used in applications other than the drilling of a wellbore. In other embodiments, the ESP design system according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources. For instance, the ESP design system of the present disclosure may be used in a borehole used for placement of utility lines. Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.

[0116] One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodimentspecific decisions will be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

[0117] Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein areIS24.1121-WO-PCT intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.

[0118] A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

[0119] The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements. Additionally, as used herein, the term “and / or” includes any and all combinations of one or more of the associated listed items.

[0120] The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather thanIS24.1121-WO-PCT by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.

Claims

IS24.1121-WO-PCTCLAIMSWhat is claimed is:

1. A method of designing an artificial lift system for producing fluid from a wellbore, comprising: receiving wellbore data indicating one or more configuration specifications and one or more production specifications for the wellbore; identifying a plurality of candidate electrical submersible pump (ESP) designs for implementing in the wellbore based on the wellbore data; determining a design score for each of the plurality of candidate ESP designs, the candidate ESP designs each indicating a collection of downhole components defining an ESP system; wherein the design score is based on inventory data for an inventory of available downhole components and historical wellbore data, the historical wellbore data indicating historical conditions for the wellbore and historical production performance for the wellbore; and selecting an ESP design from the plurality of candidate ESP designs based on an associated design score best fulfilling one or more criteria.

2. The method of claim 1, wherein the configuration specifications indicate one or more of a diameter of the wellbore at one or more depths, a depth of the wellbore, a current ESP system implemented in the wellbore including a collection of downhole components of the current ESP system; a casing configuration; or production component configuration.

3. The method of claim 1, wherein the production specifications for the wellbore include one or more of a desired surface flowrate for the wellbore, or a depth of a production zone of the wellbore.

4. The method of claim 1, wherein the historical conditions for the wellbore include one or more of a reservoir pressure or inflow performance relationship for the wellbore, a wellbore pressure loss or vertical lifting pressure relationship for the wellbore, or production fluid conditions for the wellbore.IS24.1121-WO-PCT5. The method of claim 1, wherein the historical production performance includes one or more of a historical surface flowrate for the wellbore, a power output of an ESP of the wellbore, or a power consumption of a downhole motor.

6. The method of claim 1, wherein the inventory data indicates one or more of downhole components available in an operator inventory, or downhole components available in a supplier inventory.

7. The method of claim 1, wherein the design score for each candidate ESP design is further based on one or more of implementation cost, production specification, efficiency, motor load factor, ESP power, fluid condition capability, a lifecycle estimate, or C02 emissions.

8. The method of claim 1, wherein selecting the ESP design based on the one or more criteria includes determining the design score for each of the candidate ESP designs based on weighting in accordance with the one or more criteria.

9. The method of claim 8, wherein the one or more criteria includes one or more of a price constraint, an efficiency constraint, a surface flowrate constraint, or a C02 emissions constraint.

10. The method of claim 1, wherein the collection of downhole components of each of the candidate ESP designs includes one or more of a downhole motor, an ESP, a protector, an intake, electrical cables, sensors, gas handlers, or gas separators.

11. The method of claim 1, further comprising predicting a tool life of a current ESP system of the wellbore based on the historical wellbore data and the configuration specification, and wherein receiving, identifying, determining and selecting is based on predicting the tool life.

12. The method of claim 11, further comprising predicting tool life using a tool life machine learning model that is trained based on training data that includes failure information for a plurality of ESP system configurations and wellbore condition information for a plurality of wellbores, andIS24.1121-WO-PCT that is trained to predict a target tool life for a target wellbore based on target wellbore condition information and ESP system configuration.

13. The method of claim 1, wherein the one or more criteria are based on user input.

14. The method of claim 1, further comprising providing at least some of the collection of downhole components of the selected ESP design for implementing in the wellbore.

15. The method of claim 1, further comprising implementing the collection of downhole components of the selected ESP design for producing the fluid from the wellbore.

16. The method of claim 15, wherein implementing includes assembling the collection of downhole components as an ESP system, conveying the ESP system into the wellbore, and operating the ESP system to produce the fluid from the wellbore.

17. The method of claim 1, wherein selecting the ESP design includes fdtering one or more of the candidate ESP designs based on the filtered candidate ESP designs not fulfilling one or more of the one or more criteria.

18. The method of claim 1, wherein the design score for each of the plurality of candidate ESP designs is further determined based on predicting a future condition for the wellbore.

19. A system for designing an artificial lift system for producing fluid from a wellbore, comprising: at least one processor; memory in electronic communication with the at least one processor; and instructions stored in the memory, the instructions being executable by the at least one processor to: receive wellbore data indicating one or more configuration specifications and one or more production specifications for the wellbore;IS24.1121-WO-PCT identify a plurality of candidate electrical submersible pump (ESP) designs for implementing in the wellbore based on the wellbore data; determine a design score for each of the plurality of candidate ESP designs, the candidate ESP designs each indicating a collection of downhole components defining an ESP system; wherein the design score is based on inventory data for an inventory of available downhole components and historical wellbore data, the historical wellbore data indicating historical conditions for the wellbore and historical production performance for the wellbore; and select an ESP design from the plurality of candidate ESP designs based on an associated design score best fulfilling one or more criteria.

20. A computer-readable storage medium including instructions that, when executed by at least one processor, cause the processor to: receive wellbore data indicating one or more configuration specifications and one or more production specifications for the wellbore; identify a plurality of candidate electrical submersible pump (ESP) designs for implementing in the wellbore based on the wellbore data; determine a design score for each of the plurality of candidate ESP designs, the candidate ESP designs each indicating a collection of downhole components defining an ESP system; wherein the design score is based on inventory data for an inventory of available downhole components and historical wellbore data, the historical wellbore data indicating historical conditions for the wellbore and historical production performance for the wellbore; and select an ESP design from the plurality of candidate ESP designs based on an associated design score best fulfilling one or more criteria.

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