A method and a system for determining fluid flow rate of a wellbore

Abstract

The present invention discloses a method (400) and system (300) for determining the fluid flow rate of a wellbore. The method (400) comprises receiving predefined values of one or more parameters defining the characteristics of the wellbore (402), generating a plurality of candidate fluid flow rates based on these predefined values and an iterative value of the productivity index of the wellbore (404), generating corresponding values of the one or more parameters for the plurality of candidate fluid flow rates (406), determining a level of similarity between each of the generated values and the received predefined values of the parameters (408), and selecting a fluid flow rate from the plurality of candidate fluid flow rates based on the similarity level satisfying a predefined threshold (410). This process ensures accurate determination of the fluid flow rate, optimizing wellbore performance.

Description

A METHOD AND A SYSTEM FOR DETERMINING FLUID FLOW RATE OF A WELLBORETechnical field

[0001] The present invention relates to a method and a system for determining fluid flow rate of a wellbore, and more particularly relates to the method and the system for determining fluid flow rate or surface liquid rate at the surface of the oil well of the fluid extracted using pumps such as jet pump, electrical submersible pump (ESP), etc., with complex debris deposition characteristics, including pumps with challenging flow conditions caused by debris accumulation.Background

[0002] In the realm of oil well operations, accurately determining fluid flow rate or liquid rate holds paramount importance for optimizing performance and comprehending reservoir dynamics. The liquid rate is generally the combined rate of all the fluids such as oil, power fluid and water at the surface of the wellbore. Traditionally, liquid rate is often assessed using various measurement techniques and equipment deployed within the wellbore. These methods typically involve multiphase flow meters or flow rate sensors strategically positioned to capture data during production operations. However, reliance on physical measurement devices presents challenges. Installation and maintenance of these instruments in the harsh downhole environment can prove cumbersome and timeconsuming. Moreover, these sensors are susceptible to wear and degradation over time, necessitating frequent interventions for upkeep and potential replacements.Summary:

[0003] In accordance with a first aspect of the present invention, there is provided a method for determining a fluid flow rate of a wellbore. The method comprises receiving predefined values of one or more parameters defining characteristics of the wellbore; generating aplurality of candidate fluid flow rates based on the predefined values of the one or more parameters and an iterative value of the productivity index of the wellbore; generating a plurality of values of the one or more parameters corresponding to the plurality of candidate fluid flow rates; determining a level of similarity between each of the plurality of generated values of the one or more parameters and the received predefined values of the one or more parameters; and selecting a fluid flow rate from the plurality of candidate fluid flow rates based on the level of similarity between the generated values of the one or more parameters and the received values of the one or more parameters satisfying a similarity threshold. This method provides the advantage of improving the accuracy and reliability of fluid flow rate determination in wellbores.

[0004] In some exemplary embodiments of the present invention, the method further includes defining the one or more parameters to include at least one of tubing head pressure, annulus power fluid pumping pressure, pump details, gas oil ratio, pump depth, pump intake pressure, pump discharge pressure, pump suction pressure, power fluid rate, oil rate, and water rate.

[0005] In some exemplary embodiments of the present invention, the method further includes generating the plurality of candidate fluid flow rates based on the predefined values of the one or more parameters, specifically including pump depth and at least one of pump intake pressure, pump discharge pressure, and pump suction pressure.

[0006] In some exemplary embodiments of the present invention, the method further includes generating the candidate fluid flow rate using the formula: (received pump depth - received pressure) * productivity index (PI), wherein the value of productivity index (PI) is changed / regressed in steps of 0.01-0.1 barrels per day (BPD) / psi, and wherein the received pressure includes at least one of pump intake pressure, pump discharge pressure, and pump suction pressure.

[0007] In some exemplary embodiments of the present invention, the method further includes generating the plurality of values for the one or more parameters to include at leastone of power fluid rate, pump intake pressure, pump discharge pressure, and pump suction pressure.

[0008] In some exemplary embodiments of the present invention, the method further includes selecting the fluid flow rate from the plurality of candidate fluid flow rates based on at least one of the level of similarity between the generated value of pump intake pressure and the received value of pump intake pressure satisfying a similarity threshold, and the level of similarity between the generated pump discharge pressure and a received pump discharge pressure satisfying a similarity threshold.

[0009] In some exemplary embodiments of the present invention, the method further includes generating a plurality of fluid flow rates based on at least one of the generated pump discharge pressure and generated pump intake pressure with a level of similarity satisfying the corresponding similarity threshold with received pump discharge pressure and received pump intake pressure, respectively.

[0010] The method further includes determining a plurality of shortlisted fluid flow rates from the plurality of candidate fluid flow rates, wherein the shortlisted fluid flow rates are the candidate fluid flow rates when level of similarity between at least one of the generated value of pump discharge pressure and the generated value of pump intake pressure, and received value of pump discharge pressure and, the received value of pump intake pressure, corresponding to more than one candidate fluid flow rate satisfies the similarity threshold, determining the level of similarity between each of the plurality of generated fluid flow rates and the plurality of shortlisted fluid flow rates from the plurality of candidate fluid flow rate; and selecting the fluid flow rate from the plurality of shortlisted fluid flow rates based on the level of similarity between the generated fluid flow rates and the shortlisted fluid flow rates satisfying a similarity threshold, wherein the similarity threshold is in the range of 30-50 barrels per day (BPD) of total fluid >5000 BPD (giving error of less than

[0011] In some exemplary embodiments of the present invention, the method further,,.,, • <,, PF rate = 857 Ps) includes generating the power fluid rate using the formula:where An is nozzle area received as input with jet pump setting depth parameter, PF is power fluid nozzle entry pressure received as input with jet pump setting depth parameter, Ps is jet pump suction pressure and (Kn) is nozzle loss coefficient.

[0012] In some exemplary embodiments of the present invention, the method further includes generating the power fluid rate by iterating the value ofwhere An is nozzle area received as input with jet pump setting depth parameter, PF is power fluid nozzle entry pressure received as input with jet pump setting depth parameter, Ps is jet pump suction pressure and (Kn) is nozzle loss coefficient.

[0013] In some exemplary embodiments of the present invention, the method further includes selecting the fluid flow rate from the plurality of candidate fluid flow rates based on the level of similarity satisfying a similarity threshold between the generated power fluid rate and the received power fluid rate.

[0014] In some exemplary embodiments of the present invention, the method further includes determining the received value of the power fluid rate by a flowmeter.

[0015] In some exemplary embodiments of the present invention, the method further includes selecting the fluid flow rate from the plurality of candidate fluid flow rates based on the level of similarity between the generated pump suction pressure and a received pump suction pressure satisfying a similarity threshold.

[0016] In some exemplary embodiments of the present invention, the method further includes determining the pump suction pressure using the formula: pump suction pressure value = reservoir pressure at pump depth - (received liquid rate / productivity index).

[0017] In some exemplary embodiments of the present invention, the method further includes determining the iterative value of the productivity index by iterating between 0- 100, wherein each iteration increases the iterative value of the productivity index by a user defined number between 0-100.

[0018] In some exemplary embodiments of the present invention, the method further includes determining the iterative value of the productivity index by iterating between 0.01- 0.1 barrels per day (BPD) / psi.

[0019] In accordance with another exemplary embodiment of the present invention, a system is provided for determining a fluid flow rate of a wellbore. The system comprises a control unit including a memory, and one or more processors coupled with the memory. The processor is configured to receive predefined values for one or more parameters defining characteristics of the wellbore; generate a plurality of candidate fluid flow rates based on the predefined values of the one or more parameters and an iterative value of the productivity index of the wellbore; generate a plurality of values for the one or more parameters corresponding to the plurality of candidate liquid rate values; determine a level of similarity between each of the plurality of generated values for the one or more parameters and the received predefined values of the one or more parameters; and select a fluid flow rate from the plurality of candidate fluid flow rates based on the level of similarity between the generated values for the one or more parameters and the received values of the one or more parameters satisfying a similarity threshold.

[0020] In some exemplary embodiments of the present invention, the system further includes a control unit that determines the one or more parameters, which include at least one of tubing head pressure (THP), annulus power fluid pumping pressure, pump size details, gas oil ratio, pump depth, pump completion diagram, pump intake pressure, pump discharge pressure, pump suction pressure, deviation data, power fluid rate, oil rate, and water rate.

[0021] In some exemplary embodiments of the present invention, the system further includes a control unit that generates the plurality of candidate fluid flow rates based on predefined values of the one or more parameters, including pump depth and at least one of pump intake pressure, pump discharge pressure, and pump suction pressure.

[0022] In some exemplary embodiments of the present invention, the system further includes a control unit that generates the candidate fluid flow rate using the formula: (received pump depth - received pressure) * productivity index (PI), wherein the value of productivity index (PI) is changed / regressed in steps of 0.01-0.1 barrels per day (BPD) / psi, and wherein the received pressure includes at least one of pump intake pressure, pump discharge pressure, and pump suction pressure.

[0023] In some exemplary embodiments of the present invention, the system further includes a control unit that generates the plurality of values for the one or more parameters, including at least one of power fluid rate, pump intake pressure, pump discharge pressure, and pump suction pressure.

[0024] In some exemplary embodiments of the present invention, the system further includes a control unit that selects the fluid flow rate from the plurality of candidate fluid flow rates based on at least one of the level of similarity between the generated value of pump intake pressure and the received value of pump intake pressure satisfying a similarity threshold, and the level of similarity between the generated pump discharge pressure and a measured pump discharge pressure satisfying a similarity threshold.

[0025] In some exemplary embodiments of the present invention, the system further includes a control unit that determines a plurality of shortlisted fluid flow rates from the plurality of candidate fluid flow rates. The shortlisted fluid flow rates are the candidate fluid flow rates when the level of similarity between at least one of the generated values of pump discharge pressure and the generated values of pump intake pressure, and the received values of pump discharge pressure and the received values of pump intake pressure, corresponding to more than one candidate fluid flow rate, satisfies the similaritythreshold. The control unit determines the level of similarity between each of the plurality of generated fluid flow rates and the plurality of shortlisted fluid flow rates from the plurality of candidate fluid flow rates, and selects the fluid flow rate from the plurality of shortlisted fluid flow rates based on the level of similarity between the generated fluid flow rates and the shortlisted fluid flow rates satisfying a similarity threshold, wherein the similarity threshold is in the range of 30-50 barrels per day (BPD).

[0026] In some exemplary embodiments of the present invention, the system further includes a control unit that generates the power fluid rate using the formula:PF ste = 857JA^('O) Ps) where An is nozzle area received as input with jet pump setting depth parameter, PF is power fluid nozzle entry pressure received as input with jet pump setting depth parameter,Ps is jet pump suction pressure and (Kn) is nozzle loss coefficient.

[0027] In some exemplary embodiments of the present invention, the system further includes a control unit that generates the power fluid rate by iterating the value of Kn, wherein the value of Kn lies between 0.01-0.05.

[0028] In some exemplary embodiments of the present invention, the system further includes a control unit that selects the fluid flow rate from the plurality of candidate fluid flow rates based on the level of similarity satisfying a similarity threshold between the generated power fluid rate and the received power fluid rate.

[0029] In some exemplary embodiments of the present invention, the system further includes a control unit where the received value of the power fluid rate is determined by a flowmeter.

[0030] In some exemplary embodiments of the present invention, the system further includes a control unit that selects the fluid flow rate from the plurality of candidate fluid flow rates based on the level of similarity between the generated pump suction pressure and a received pump suction pressure satisfying a similarity threshold.

[0031] In some exemplary embodiments of the present invention, the system further includes a control unit where the pump suction pressure is determined using the formula: pump suction pressure value = reservoir pressure at pump depth - (received liquid rate / productivity index).

[0032] In some exemplary embodiments of the present invention, the system further includes a control unit where the iterative value of the productivity index is determined by iterating between 0-100, and each iteration increases the iterative value of the productivity index by a number between 0-100.BRIEF DESCRIPTION OF DRAWINGS

[0033] The novel features and characteristics of the disclosure are set forth in the appended claims. The disclosure itself, however, as well as a preferred mode of use, further objectives, and advantages thereof, will best be understood by reference to the following detailed description of an illustrative embodiment when read in conjunction with the accompanying figures. One or more embodiments are now described, by way of example only, with reference to the accompanying figures wherein like reference numerals represent like elements and in which:

[0034] FIG. 1 illustrates a cross sectional view of a conventional oil wellbore with a jet pump.

[0035] FIG. 2 illustrates a cross sectional view of a conventional oil wellbore with an electrical submersible pump.

[0036] FIG. 3 illustrates a block diagram of a system for determining a fluid flow rate of a pump.

[0037] FIG. 4 illustrates a non-limiting example of a method for determining fluid flow rate of a pump in oil wellbore operations.

[0038] The summary above, as well as the following detailed description of illustrative embodiments, is better understood when read in conjunction with the appended drawings.

[0039] For the purpose of illustrating the present disclosure, exemplary constructions of the disclosure are shown in the drawings. However, the disclosure is not limited to specific methods and instrumentalities disclosed herein. Moreover, those in the art will understand that the drawings are not to scale. Wherever possible, like elements have been indicated by identical numbers.Reference NumeralsDetailed Description:

[0040] Detailed embodiments and implementations of the claimed subject matters are disclosed herein in detail with the technical matters, structural features, achieved objects, and effects with reference to the accompanying drawings as follows. It shall be understood that the disclosed embodiments and implementations are merely illustrative of the claimed subject matters which may be embodied in various forms. The present disclosure may, however, be embodied in many different forms and should not be construed as limited to the exemplary embodiments and implementations set forth herein. Rather, these exemplary embodiments and implementations are provided so that description of the present disclosure is thorough and complete and will fully convey the scope of the present disclosure to those skilled in the art. Specifically, the terminologies in the embodiments of the present disclosure are merely for describing the purpose of the certain embodiment, but not to limit the disclosure. In the description below, details of well-known features and techniques may be omitted to avoid unnecessarily obscuring the presented embodiments and implementations.

[0041] In the following specification, it should be appreciated by those skilled in the art that the terms "received values" and "measured values" refer to the same concept and may be used interchangeably. Similarly, the terms "fluid flow rate" and "liquid rate" also refer to the same concept and may be used interchangeably. These interchangeable terms allow for flexibility in describing various embodiments and modifications for carrying out the purposes of the present invention.

[0042] In the following specification, it should be understood that the term "surface of the oil well" refers to the top surface of the wellbore. This includes the interface where the wellbore opens at ground level, providing access to the subsurface equipment and operations involved in oil extraction. This definition clarifies the context in which measurements, adjustments, and interactions occur at the uppermost point of the wellbore system.

[0043] An embodiment of the present invention discloses a method and a system for determining fluid flow rate or liquid rate in an oil well or wellbore. The determination ofliquid rate is required for assessing the efficiency and functionality of the pump system, which enables the extraction of liquids from the well. This real-time determination allows for immediate insights into the liquid flow conditions within the well, enabling operators to make decisions for optimizing pump performance.

[0044] FIG. 1 illustrates a cross sectional view of an oil wellbore. The wellbore, as shown in FIG 1, discloses a passage or pathway for the flow of the fluid stream. The wellbore comprises a jet pump (102) to enable suction of liquids from the wellbore. A plurality of sensors are arranged in the wellbore to measure well parameters such as pump suction pressure, power fluid rate. For example, power fluid rate is determined using power fluid rate sensor (104) and pump suction pressure using pump suction pressure sensor (110). Further, conventionally the wellbore includes a fluid flow rate sensor (100) to measure the fluid flow rate. The figure illustrates the flow of fluid stream from the wellbore to the surface wherein the fluid stream (108) contains power fluid (106), oil, water or the like drawn from the wellbore.

[0045] FIG. 2 illustrates a cross sectional view of an oil wellbore. The wellbore, as shown in FIG 2, discloses a passage or pathway for the flow of the fluid stream. The wellbore comprises an electrical submersible pump or ESP (202) to enable suction of liquids from the wellbore. A plurality of sensors are arranged in the wellbore to measure well parameters such as pump intake pressure, pump discharge pressure. For example, pump intake pressure is determined using pump intake pressure sensor (220) and pump discharge pressure using pump discharge pressure sensor (212). Further, conventionally the wellbore includes a fluid flow rate sensor (200) to measure the fluid flow rate. The figure illustrates the flow of fluid stream from the wellbore to the surface wherein the fluid stream (208) contains oil, water or the like drawn from the wellbore.

[0046] FIG. 3 illustrates a system (300) for determining fluid flow rate in a wellbore. In one exemplary embodiment of the present invention, the system may include a control unit (314) that serves as a central component for overseeing and managing the operations of the system. The control unit may be implemented as either a general-purpose computer or adedicated circuit. In some exemplary embodiments of the present invention, the control unit may be configured to receive parameters for defining the wellbore characteristics. Specifically, the control unit may receive as input parameters including but not limited to tubing head pressure (THP), annulus power fluid pumping pressure, jet pump size details, gas oil ratio, jet pump setting depth and completion diagram, deviation data, power fluid rate at surface which enters the jet pump, measured oil rate at wellbore surface measured using multiphase flowmeter and measured total water rate (i.e. including the water in the reservoir and power fluid) using multiphase flow meter or measured oil rate at surface of the wellbore.

[0047] In some exemplary embodiments of the present invention, the control unit may include components, such as a central processing unit (CPU) or a processor (324), memory, and input / output devices. The inclusion of a CPU or processor may enable the control unit to execute complex algorithms and process data in real-time. The memory may be located either in the cloud or internally within the system, may store relevant data, including user preferences, well characteristic data history, safety protocols etc. The ability to store relevant data may ensure continuity and efficiency during multiple sessions, as the system may retrieve and compare different wellbore configurations.

[0048] In some exemplary embodiments of the present invention, the control unit may feature user-friendly input / output devices (316), providing an intuitive and interactive interface for users. The interface may include a display screen, buttons, touch panels, or other intuitive input methods. Using the input / output device, users may conveniently input parameters regarding wellbore characteristics. The display screen may provide real-time feedback and display determined unknown parameters.

[0049] A memory (326) may be any form of storage either within or outside the device.The memory may include a database. In some embodiments of the present disclosure, the memory may also be a combination of one or more storage available internally or externally. For example, flash memory, random-access memory (RAM), read-only memory (ROM), compact disc read-only memory (CDROM), electro-optical memory likecompact disk or digital versatile disk (DVD), smart card magneto-optical memory, erasable programmable read-only memory (EPROM), and electrically-erasable programmable read-only memory (EEPROM), or the like. In some embodiments of the present disclosure, the memory may store or carry the source code or instruction for executing required tasks. In some embodiments of the present disclosure, a carrier wave may carry content or data including those used in transmitting and receiving electronic data such as electronic mail (e-mail) or in accessing a computer network such as the Internet or a local area network (LAN). In some embodiments of the present disclosure, the memory may be a cloud storage or the like that may be accessible via the internet.

[0050] A display (322) may be a touch-sensitive or presence-sensitive display. In some embodiments of the present disclosure, the display includes an input / output interface module (I / O interface module). In some embodiments of the present disclosure, the display may provide an output to the user, for example, display contents, including without limitation, an image or a video image or the like. In some embodiments of the present disclosure, the display may include or be integrated with a touch screen or touch sensitive overlay for receiving touch input from the user. In some embodiments of the present disclosure, the display may also be capable of receiving a user input from a stylus, fingertip, or other means of gesture input. In some embodiments of the present disclosure, the display may be a computer monitor, for example, a personal computer, with an internal or external display operatively connected. In yet another exemplary embodiment, the display may be a display device, such as an LCD TV or projector or the like.

[0051] An Input / Output interface module (I / O interface module) refers to any means or set of commands or menus through which a user may communicate with the device. In some embodiments of the present disclosure, the I / O interface module may be a virtual keyboard or any other means through which a user may input information to the device. The I / O interface module may enable the device to communicate with the user for exchanging data or for establishing connection with the devices. The I / O interface module may enable the device to connect with various I / O peripherals. The peripherals for example may include keyboard, mouse, camera, touch screen (e.g., display), a microphone, and mayalso include one or more output devices such as a display screen (e.g., display) and a speaker. The I / O interface module may enable the user to navigate, view, edit and perform several other operations to notification banners, badges, application program interface (API), files and documents such as portable document format (PDF) files, word files, spreadsheets, powerpoint presentations, screenshots, JPEG (Joint Photographic Experts Group), PNG (Portable Network Graphics), GIF (Graphics Interchange Format), SVG (Scalable Vector Graphics), MP4 (Moving Picture Experts Group) or the like.

[0052] In the field of oil extraction, fluid rate or liquid liquid rate is a parameter used for defining the quantity of fluid produced from a well. The metric represents the total liquid production, offering insights into the reservoir's fluid dynamics. The fluid flow rate is determined by dividing the water volume by the total fluid volume, where the fluid includes both oil and water. The fluid flow rate represents the total number of barrels extracted from the wellbore over the period of a day.

[0053] In some exemplary embodiment of the present invention, the control unit may determine liquid rate or fluid flow rate, for each iteration by iterating the values of parameters that determine liquid rate.

[0054] In some exemplary embodiments of the present invention, the system may include a pump (302) to extract the fluid or oil from the wellbore. In some exemplary embodiments of the present invention, the system may include a jet pump to extract the fluid or oil from the wellbore, as can be seen in FIG. 1. The jet pump may be positioned in an uphole portion of the wellbore.

[0055] A jet pump is a component employed in oil extraction, utilizing high-pressure fluid to create a low-pressure zone for extracting liquid from the well. This device operates based on fluid dynamics, relying on the energy of pressurized fluid to induce a suction effect that draws liquid, primarily oil, from the reservoir to the surface. The functionality of the jet pump is essential for efficient well operations, contributing significantly to the extraction and production of hydrocarbons.

[0056] In some exemplary embodiment of the present invention, the system may include a plurality of sensors (318), the plurality of sensors in the system may include a plurality of pressure sensors to measure pump suction pressure, pump intake pressure or pump discharge pressure or the like.

[0057] In some exemplary embodiments of the present invention, the plurality of sensors in the system may include a multiphase flowmeter to measure oil rate at the surface of the wellbore. The measured / received oil rate is a parameter reflecting the actual oil production from the well. In some exemplary embodiments of the present invention, the multiphase flowmeter may be used to measure total water rate at the wellbore.

[0058] In the field of oil extraction, total water rate, which includes both water in the reservoir and power fluid, is important in evaluating well performance. The total water rate provides a comprehensive measure of the water content within the extracted fluids, offering insights into the fluid dynamics of the reservoir. This metric plays a role in assessing the overall efficiency of oil extraction processes, as it quantifies the volume of water produced alongside hydrocarbons.

[0059] In some exemplary embodiments of the present invention, the control unit may receive jet pump details as input parameters. Jet pump details may include jet pump size details or information / specification of the jet pump for e.g. volume occupied by the pump or the power consumption of the pump, etc.

[0060] In some exemplary embodiments of the present invention, the control unit may receive power fluid pumping pressure as an input parameter. The power fluid pumping pressure defines the pressure at which the power fluid is pumped into the wellbore.

[0061] In some exemplary embodiments of the present invention, the system may include a power fluid pumping pressure sensor at annulus to measure power fluid pumpingpressure, which may optimize fluid flow rate calculations and ensure a comprehensive assessment of the impact of power fluid on the overall well performance.

[0062] In some exemplary embodiments of the present invention, the control unit may receive gas oil ratio (GOR) as an input parameter. GOR is an indicator of production characteristics of the well, reflecting the ratio of gas to oil in the extracted fluid from the wellbore.

[0063] In some exemplary embodiments of the present invention, the control unit may receive a jet pump setting depth and completion diagram as an input parameter. The jet pump setting depth may be defined as the measured depth from the surface at which the jet pump is positioned for the extraction of the fluid from the wellbore. The completion diagram is one of the parameters that defines the arrangement and configuration of the wellbore components, including the placement of the casing, tubing, packing and other tools like perforations, sensors etc. These parameters define the spatial placement of the jet pump and its completion configuration. The completion configuration includes the arrangement of various downhole equipment and components used in the well, such as the casing, tubing, packers, perforations, and other completion tools. This configuration determines how fluids are received from the reservoir by the pump and transported to the surface, ensuring optimal flow and isolation of production zones.

[0064] In some exemplary embodiments of the present invention, the control unit may receive deviation data as an input parameter. Deviation data provides insights into the trajectory of the wellbore, allowing the method to account for deviations from verticality. For example, the wellbore may be vertical or inclined at a particular angle from the vertical axis. In some cases, the wellbore may be horizontal. These deviations are accounted as a parameter defining deviation data for determining the fluid flow rate.

[0065] In some exemplary embodiments of the present invention, the system may include a power fluid rate measuring flow meter to measure the power fluid rate at the surface of the wellbore, ensuring accurate measurement and incorporation of the parameter. Themeasurement of the power fluid rates provides the accuracy in the liquid rate or fluid flow rate calculations and ensures a reliable assessment of the impact of power fluid on the overall well performance.

[0066] In some exemplary embodiments of the present invention, the control unit may determine fluid flow rate based on reservoir pressure at pump depth, measured pump suction pressure and productivity index. In some exemplary embodiments of the present invention, the control unit may determine fluid flow rate for each iteration value of productivity index (PI). In some exemplary embodiments of the present invention, the control unit may increase the value of productivity index (Pl)with every iteration.

[0067] Generally, in the field of oil and gas extraction, the productivity index (PI) is a metric used to evaluate the effectiveness of a well. It is calculated by dividing the production rate of the well by the pressure drawdown at the reservoir. A higher productivity index (Pl)indicates better reservoir performance and efficient fluid production.

[0068] In some exemplary embodiment of the present invention, the control unit may determine fluid flow rate for each value of productivity index (PI)by substituting the values of reservoir pressure at pump depth, measured pump suction pressure and the value of productivity index (PI)at each iteration in below:

[0069] Candidate fluid flow rate = (reservoir pressure at pump depth - measured pump suction pressure * productivity index - (1)

[0070] In some exemplary embodiment of the present invention, the control unit may determine pump suction pressure for each value of productivity index (PI) by substituting the values of reservoir pressure at pump depth, determined fluid flow rate and the value of productivity index (PI) at each iteration in below:

[0071] Pump suction pressure = reservoir pressure at pump depth - (determined fluid flow rate / productivity index) - (2)

[0072] In the realm of oil wellbores, pump suction pressure ('Ps') is a vital parameter that provides insights into the suction conditions within the well. The pump suction pressure ('Ps') defines the pressure at the inlet of the jet pump, playing a key role in assessing the efficiency and performance of the pump system during oil extraction operations. Engineers and operators monitor jet pump suction pressure closely to make informed decisions about pump optimization, fluid lifting, and overall well productivity.

[0073] In some exemplary embodiments of the present invention, the control unit may determine power fluid rate using:-(3)

[0074] where An is nozzle area of the jet pump that may be provided as input with jet pump setting depth parameter, PF is power fluid nozzle entry pressure received as input with jet pump setting depth parameter, Ps is jet pump suction pressure and (Kn) is nozzle loss coefficient.

[0075] In some exemplary embodiments of the present invention, the control unit may determine the power fluid (PF) rate for each iteration by iterating values of Kn and PI.

[0076] Jet pump nozzle loss coefficient (Kn) is a parameter generally used to quantify losses in pressure associated with the fluid passing through the nozzle of a jet pump. Kn is determined through empirical testing or simulations. A higher Kn value indicates higher losses and may impact the efficiency of fluid lifting in the well.

[0077] In some exemplary embodiments of the present invention, the control unit may determine power fluid (PF) rate by substituting the value of each nozzle areas, power fluid nozzle coefficient, value of the iteration of jet pump nozzle loss coefficient and pump suction pressure (Ps) for each iteration of productivity index in the below-

[0078] In some exemplary embodiments of the present invention, the control unit may determine fluid flow rate for each value of pump suction pressure determined for iteration value of productivity index. In some exemplary embodiments of the present invention, the control unit may determine the value of fluid flow rate for each iteration of Kn.

[0079] In the context of oil extraction, power fluid rate is a fundamental parameter that defines the rate at which power fluid is injected into the wellbore to facilitate the extraction of oil and other fluids. The rate is a factor in determining the overall efficiency and performance of the jet pump system. Power fluid rate directly influences the fluid dynamics within the well, impacting the lift efficiency and successful extraction of oil.

[0080] In the field of oil wellbores, the term 'nozzle area' refers to the specific cross- sectional area of the nozzle within a jet pump system. The area plays a critical role in regulating the flow dynamics of fluids, influencing the overall efficiency and performance of the power fluid injected into the wellbore.

[0081] Power fluid nozzle entry pressure, also known as 'Ppf is a factor in oil well operations, defining the pressure at which the power fluid is introduced into the well through the nozzle. The pressure is dependent on the depth at which the pump is positioned. The pressure is a crucial determinant of the effectiveness of the jet pump system, directly impacting fluid dynamics, lift efficiency, and the overall success of the oil extraction process.

[0082] In some exemplary embodiments of the present invention, the control unit may determine fluid flow rate based on nozzle area (An), power fluid nozzle entry pressure (Ppf) and pump suction pressure (PS) for each value of productivity index (PI).

[0083] In some exemplary embodiments of the present invention, received values may refer to the values of pump suction pressure, pump intake pressure, pump discharge pressure obtained from the sensors (318) such as pump suction pressure sensor, pump intake pressure sensor, pump discharge pressure sensor respectively or the like.

[0084] In some exemplary embodiments of the present invention, determined values may be the values of parameters such as pump suction pressure, power fluid rate, water cut rate and oil cut rate for each iteration of Kn, productivity index (PI) and pump suction pressure Ps.

[0085] In some exemplary embodiments of the present invention, the pump of the system may include an electrical submersible pump (ESP) to extract fluid from the wellbore as can be seen in FIG 2. The electrical submersible pump may be positioned in an uphole portion of the wellbore.

[0086] An electrical submersible pump (ESP) is a component in oil extraction, utilizing electrical power to drive a pumping mechanism submerged deep within the well. The electrical submersible pump (ESP) operates by converting electrical energy into mechanical energy, which in turn moves fluid from the reservoir to the surface. The ESP relies on its submerged position to efficiently lift liquid, including oil, through the wellbore. Its functionality is integral to optimizing well performance, significantly enhancing hydrocarbon extraction and production efficiency.

[0087] In some exemplary embodiments of the present invention, the control unit may determine the intake pressure of an electrical submersible pump (ESP) based on reservoir pressure at pump depth, received intake pressure as measured by the sensor, and productivity index (PI).

[0088] In the context of electrical submersible pump (ESP) operations, intake pressure is a parameter that provides insights into the conditions at the pump inlet. Intake pressuredefines the pressure of the fluid at the inlet of the electrical submersible pump (ESP), influencing the efficiency and effectiveness of fluid lifting from the reservoir to the surface.

[0089] In some exemplary embodiments of the present invention, the control unit may determine the discharge pressure of an electrical submersible pump (ESP) based on reservoir pressure at pump depth, received discharge pressure as measured by the sensor, and productivity index (PI).

[0090] In the context of ESP operations, discharge pressure is a parameter that provides insights into the conditions at the pump outlet. Discharge pressure defines the pressure at the point where fluids exit the ESP, impacting the overall efficiency and effectiveness of fluid lifting from the reservoir to the surface.

[0091] In some embodiments of the present invention, the control unit may receive as input values of all the parameters including measured / received values and determined / generated values to process these values using a well performance software.

[0092] Well performance software operates by integrating specific algorithms and models tailored to the oil and gas industry. Well performance software includes advanced mathematical formulations and computational methodologies to simulate the intricate behavior of oil wells under varying conditions. The software considers a multitude of factors, including reservoir properties, fluid dynamics, and downhole equipment specifications, to predict the performance of the well accurately. Through iterative calculations, the software refines its predictions, offering a detailed understanding of how changes in parameters impact production rates and pressure profiles. It essentially acts as a virtual testing ground, allowing engineers and operators to assess different scenarios and optimize operational strategies for enhanced efficiency. The ability of the software to simulate real-world conditions makes it a valuable tool for decision-making in the dynamic field of oil and gas extraction.

[0093] In some embodiments of the present invention, the control unit may filter data received from well performance software based on specific conditions. The specificconditions are the conditions that the user may provide to the software as per the requirements.

[0094] Fig. 4 illustrating a non-limiting example of a method for determining a fluid flow rate of a wellbore. In an exemplary embodiment of the present invention, the method (400), at step 402, comprises receiving predefined values for one or more parameters defining characteristics of the wellbore. In an exemplary embodiment of the present invention, the parameters that are received may include but not limited to tubing head pressure (THP), annulus power fluid pumping pressure, jet pump size details, gas oil ratio, jet pump setting depth and completion diagram, deviation data, power fluid rate injection at surface which enters the jet pump, or measured oil rate at surface the wellbore and measured total water rate (i.e. including the water in the reservoir and power fluid) at wellbore using multiphase flow meter. In some exemplary embodiments of the present invention, measured power fluid rate may be obtained by power fluid rate measuring flow meter. In some exemplary embodiments of the present invention, the methods may utilize independent variables for determining fluid flow rate. In some exemplary embodiments of the present invention, the independent variables may include:a) Tubing Pressure Loss: The method may involve reducing the effective tubing inner diameter (ID) and increasing the pressure loss in tubing in steps of 1 to 10 psi, as per the user-input value of steps. The additional tubing pressure loss may be reflected in the increase of jet pump discharge pressure, leading to an increase in pump suction pressure and a reduction in Power-fluid rate.b) Jet Pump Nozzle Loss Coefficient (Kn): The nozzle loss coefficient variable may be employed in the equation for power fluid calculation. The coefficient may impact the overall efficiency of the jet pump system.c) Productivity Index (PI): PI may serve as the third independent variable. Pump suction pressure may be the dependent variable based on the independent variableproductivity index (PI), which may be the main objective of the quantification process.d) Pump Wear Factor: Another independent variable considered in the iterative process is the pump wear factor. An increase in the pump wear factor indicates a decrease in the pump's efficiency, resulting in reduced head generation and lower fluid flow rates from the reservoir. By accounting for variations in pump wear, the estimation model can adjust its calculations accordingly, ensuring accuracy in the final results.

[0095] In some exemplary embodiment of the present invention, measured values may be the value obtained by the physical sensors such as pump intake pressure sensor, pump discharge pressure sensor or the like.

[0096] At step 404, the method includes generating a plurality of candidate fluid flow rates based on the predefined values of the one or more parameters and an iterative value of the productivity index of the wellbore. For example, the present invention receives parameters and iterative values of the productivity index. For each iteration i, the invention generates a candidate fluid flow rate Ci using the function Ci = (Pr - Ps) * PI_i. For instance. Cl = (Pr - Ps) * PI 1, C2 = (Pr - Ps) * PI 2, and so on. The productivity index (PI) is adjusted in each iteration to produce different fluid flow rates, essentially making educated guesses about the potential fluid flow rate based on this relationship.

[0097] For example, the present invention generates corresponding parameter values for each candidate fluid flow rate Ci. The method herein works backwards, generating the reservoir pressure and pump suction pressure needed to produce the fluid flow rate, given the current PI_i. Using functions gl() and g2(), the invention generates values for reservoir pressure (Pr_i) and pump suction pressure (Ps i) respectively. For example, Pr_l = gl(Cl, PI_1), Ps i = g2(Cl, PI_1), and so forth for each candidate, giving sets of generated values of the wellbore characteristics.

[0098] In some exemplary embodiment of the present invention, fluid flow rate may be dependent on the well productivity index. In some exemplary embodiment of the present invention, the method may determine fluid flow rate based on the tubing deposition pressure loss. In some exemplary embodiment of the present invention, the method may determine fluid flow rate based on the jet pump nozzle loss coefficient (Kn). In some exemplary embodiment of the present invention, fluid flow rate may be a function of reservoir pressure at pump depth, measured pump suction pressure (Ps) and productivity index (PI).

[0099] In some exemplary embodiments of the present invention, received pump suction pressure, pump intake pressure, pump discharge pressure may be derived from sensors, for example, pump suction pressure sensor, pump intake pressure sensor, pump discharge pressure sensor respectively or the like. In some exemplary embodiment of the present invention, liquid rate may be determined by substituting the values of reservoir pressure at pump depth, received pump suction pressure (Ps) of jet pump and an iterative value of productivity index (PI) in the below equation:Candidate fluid flow rate = (reservoir pressure at pump depth - measured pump suction pressure) * productivity index -(1)

[0100] In some exemplary embodiment of the present invention, fluid flow rate may be determined by substituting the values of reservoir pressure at pump depth, measured pump intake pressure for ESP and an iterative value of productivity index in the below equation:Candidate fluid flow rate = (reservoir pressure at pump depth - measured pump intake pressure) * productivity index - (1)

[0101] In some exemplary embodiments of the present invention, a constant value of 0.1 may be assigned to the jet pump throat loss coefficient (Kt). In some exemplary embodiments of the present invention, a constant value of 0.1 may be assigned to the jet pump diffuser loss coefficient (Kd). The coefficient accounts for pressure losses in thediffuser section of the jet pump. The jet pump diffuser loss coefficient represents the proportion of pressure lost due to friction and turbulence as fluid passes through the diffuser section. The diffuser section of the wellbore is the part of the jet pump where the fluid velocity decreases and pressure increases, facilitating the efficient transfer of fluid from the wellbore to the surface. The accurate assignment of the diffuser loss coefficient is essential for estimating the pump performance and overall fluid flow rate accurately.

[0102] In some exemplary embodiments of the present invention, the method may further include assuming the well productivity index (PI) as a first iteration value, equivalent to a minimum value. In some exemplary embodiments of the present invention, the assumed value of productivity index may vary between a minimum and maximum value in each iteration. In some exemplary embodiment of the present invention, the minimum value of productivity index (PI) may be 1. In some exemplary embodiment of the present invention, the maximum value of productivity index (PI) may be 100. In some exemplary embodiment of the present invention, the minimum and maximum value may be a subset of any 2 numbers between 1-100 respectively. In some exemplary embodiment of the present invention, the productivity index (PI) may increase by a number between 0.1 to 100 in each of the iterations. The smaller the increase in the value of productivity index in every iteration the more accurate will be the value of determined PS.

[0103] At step 406, the method further comprises generating a plurality of values for the one or more parameters corresponding to the plurality of candidate liquid rate values. In some exemplary embodiments of the present invention, the method may further include determining the value of power fluid rate by the control unit using:

[0104] where An is nozzle area of the j et pump that may be provided as input with j et pump setting depth parameter, PF is power fluid nozzle entry pressure received as input with jet pump setting depth parameter, Ps is jet pump suction pressure and (Kn) is nozzle loss coefficient.

[0105] In some exemplary embodiments of the present invention, the method may further include determining by the control unit the power fluid rate for each iteration value of Kn and PI. In some exemplary embodiments of the present invention, the method may further include determining by the control unit the pump suction pressure for each iteration value of Kn and PI.

[0106] In some exemplary embodiments of the present invention, the method may further include assuming the value of jet pump nozzle coefficient as a first iteration value to determine power fluid (PF) rate, commencing with a minimum value. In some exemplary embodiments of the present invention, the method may further include assuming the value of tubing loss as a first iteration value to determine power fluid (PF) rate, commencing with a minimum value. In some exemplary embodiments of the present invention, tubing deposition pressure loss may be assumed within the range of 5-15 psi. In some exemplary embodiments of the present invention, jet pump nozzle loss coefficient (Kn) may be assumed within the range of 0.01-0.05 for 1stiteration

[0107] Generally, tubing deposition pressure loss becomes significant when deposits, such as scale or other materials, accumulate on the inner walls of the tubing. These deposits reduce the effective inner diameter of the tubing, causing increased pressure losses. Regular monitoring and assessment of deposition pressure loss are for maintaining optimal well performance.

[0108] In some exemplary embodiments of the present invention, the method may further determine the reservoir oil rate based on the values of power fluid (PF) rate obtained by iterating pump suction pressure (Ps) and Kn. In some exemplary embodiments of the present invention, the oil rate may be determined by substituting the value of total oil rate measured at surface, the value of power fluid (PF) based on the iteration of jet pump nozzle loss coefficient and pump suction pressure for each iteration of productivity index in the below.Oil rate = total oil rate measured at surface / (total fluid flow rate at surface - calculated PF rate) -(4)

[0109] In some exemplary embodiments of the present invention, the method may further determine the fluid flow rate based on the values of power fluid (PF) rate obtained by iterating pump suction pressure (Ps) and Kn.

[0110] For example, the present invention determines the level of similarity between the generated values of the wellbore characteristics and the measured values of the wellbore characteristics. The present invention determines a similarity score for each set of generated parameters. For each candidate i, the invention computes a score Si using a function h() that considers the absolute differences between measured values and generated values. For instance, Si = h(|Pr - Pr_i|, |Ps - Ps_i|). Higher similarity scores indicate closer matches between generated values and measured values.

[0111] At step 408, the method includes determining a level of similarity between each of the plurality of generated values for the one or more parameters and the received predefined values of the one or more parameters

[0112] In some exemplary embodiments of the present invention, the method may further include selecting the fluid flow rate from the plurality of candidate fluid flow rates based on at least one of: the level of similarity between the generated value of pump intake pressure and the received value of pump intake pressure satisfying a similarity threshold, and the level of similarity between the generated pump discharge pressure and a measured pump discharge pressure satisfying a similarity threshold.

[0113] In some exemplary embodiments of the present invention, the method includes generating a plurality of fluid flow rates based on at least one of the generated pump discharge pressure and generated pump intake pressure with the level of similarity satisfying the corresponding similarity threshold with received pump discharge pressure and received pump intake pressure, respectively.

[0114] In some exemplary embodiments of the present invention, the method may include determining a plurality of shortlisted fluid flow rates from the plurality of candidate fluid flow rates. The shortlisted fluid flow rates are the candidate fluid flow rates when level of similarity between at least one of the generated value of pump discharge pressure and the generated value of pump intake pressure, and received value of pump discharge pressure and the received value of pump intake pressure, corresponding to more than one candidate fluid flow rate satisfies the similarity threshold.

[0115] In some exemplary embodiments of the present invention, the method includes determining a level of similarity between each of the plurality of generated fluid flow rates and the plurality of shortlisted fluid flow rates from the plurality of candidate fluid flow rates, and selecting a fluid flow rate from the plurality of shortlisted fluid flow rates based on the level of similarity between the generated fluid flow rate and the selected candidate values of fluid flow rate satisfying a similarity threshold, wherein the similarity threshold may be in the range of 30-50 barrels per day (BPD) of total fluid >5000 BPD (giving error of less than 1% )..

[0116] As an example, the present invention selects the fluid flow rate by choosing the candidate Ci with the highest similarity score Si that exceeds a predefined similarity threshold T. If, for example, S2 is the highest score and S2 > T, the candidate C2 is selected as the estimated fluid flow rate. This approach enables to estimate the fluid flow rate indirectly, using the reservoir pressure, pump suction pressure, and productivity index, iteratively refining the estimate until the best match is found between the generated values and the measured values of wellbore conditions.

[0117] At step 410, the method includes selecting a fluid flow rate from the plurality of candidate fluid flow rate based on the level of similarity between the generated values for the one or more parameters and the received values of the one or more parameters satisfying a similarity threshold.

[0118] In some exemplary embodiments of the present invention, the method may further include providing each of the parameters, measured / received values and determined values into a well performance software. In another embodiment of the present invention, the method may further include filtering the data obtained from well performance software. In some exemplary embodiments of the present invention, the method may include one or more filtering conditions to ensure the iteration process may converge and provide reliable solutions. In some exemplary embodiment of the present invention, determined values may be the value obtained by the method of the present invention.

[0119] In some exemplary embodiments of the present invention, the condition for filtering the results may be the difference between the determined and measured pump suction pressure at the wellbore or, for example, may fall within a user-defined range, for example, 10-20 psi.

[0120] In some exemplary embodiments of the present invention, the condition for filtering the results may be that the difference between the determined and generated fluid flow rate falls within a user specified range, such as 30-100 bpd.

[0121] In some exemplary embodiments of the present invention, the condition for filtering the results may be that the difference between the determined and measured power fluid rate falls within a user-specified range, for example 10-200 barrels per day (bpd).

[0122] In some exemplary embodiments of the present invention, the condition for filtering the results may be that the difference between the determined and measured pump intake pressure falls within a user-specified range, for example 10-20 psi.

[0123] In some exemplary embodiments of the present invention, the condition for filtering the results may be that the difference between the determined and measured pump discharge pressure falls within a user-specified range, for example 10-20 psi.

[0124] In some exemplary embodiments of the present invention, the results may be filtered if conditions of parameters such as pump intake pressure, pump discharge pressure, and fluid flow rate are matched. In some exemplary embodiments of the present invention, the method may further include iterating over the values of dependent variables until a filtered result is obtained. In some exemplary embodiments of the present invention, the iterative process involves adjusting parameters such as well productivity index (PI), jet pump nozzle loss coefficient (Kn), tubing pressure loss. The iterative approach may enhance the accuracy and reliability of the quantification process in different operational scenarios.

[0125] In some exemplary embodiments of the present invention, the method may determine PS, fluid flow rate, power fluid (PF) rate for each value of productivity index (PI) iteratively. In some exemplary embodiments of the present invention, the method may determine PS, fluid flow rate, power fluid (PF) rate for each value of Kn iteratively. In some exemplary embodiments of the present invention, the method may determine PS, fluid flow rate, power fluid (PF) rate for each value of tubing pressure loss iteratively. In some exemplary embodiments of the present invention, the process of iteration may be completed when at least one filtered result is obtained.

[0126] In some exemplary embodiments of the present invention, the method may match the filtered value of productivity index with the last known value of productivity index. In some exemplary embodiments of the present invention, the filtered value of pump suction pressure (Ps) and power fluid rate may be matched.

[0127] Initially, the method involves the assumed fluid flow rate based on iteration values of the productivity index (PI). The calculation incorporates parameters such as reservoir pressure, pump depth, and measured pump suction pressure (Ps) to derive an initial estimate of the fluid flow rate within the well using the equation:Fluid flow rate = (reservoir pressure at pump depth - measured pump suction pressure) * PI (iteration) -(2)

[0128] Subsequently, the method proceeds to generate the power fluid (PF) rate using iteration values of the jet pump nozzle loss coefficient (Kn) and the measured pump suction pressure (Ps). This accounts for various factors influencing the power fluid rate and serves as a crucial component in the overall estimation process.

[0129] Following the generation of the power fluid rate, the method executes well models with steps involving tubing deposition pressure loss and the jet pump nozzle loss coefficient (Kn). These simulations are essential for accurately replicating the conditions within the well and generating reliable estimation results.

[0130] Upon completion of the well models, the method includes a selecting the results, ensuring that only data meeting specific criteria are considered for further analysis. These criteria include verifying that the generated power fluid rate falls within a predefined range of the measured surface power fluid rate and that the generated fluid flow rate aligns with the assumed fluid flow rate.

[0131] The method includes matching the filtered-out well model results with pressure (Ps) and measured power fluid rate. This matching process facilitates the identification of well behavior parameters, including the assumed or generated liquid rate as the live well production rate, along with other relevant parameters such as power fluid rate, tubing head pressure (THP), and power fluid pressure.

[0132] In the iterative process outlined in the flowchart, the estimations are refined until the convergence is achieved, ensuring that generated values closely align with measured values. This iterative refinement is important for enhancing the accuracy and reliability of the estimation process, as it allows for adjustments to be made based on discrepancies between generated and measured values. The algorithm filters out model results based on simultaneous conditions being met, ensuring accuracy in the estimation process. For example, the algorithm may filter out results when the generated power fluid rate falls within a specified range of the measured power fluid rate, and the generated suction pressure closely matches the last known suction pressure value.

[0133] As an example, the present invention selects the fluid flow rate by choosing the candidate Ci with the highest similarity score Si that exceeds a predefined similarity threshold T. If, for example, S2 is the highest score and S2 > T, the invention would select C2 as the estimated fluid flow rate. This approach allows the present invention to estimate the flow rate indirectly, using other measurable wellbore characteristics and iteratively refining the estimate until it finds the best match between the candidate value and the measured wellbore conditions.

[0134] In some exemplary embodiments of the present invention, the method may determine the fluid flow rate by comparing the determined pump intake pressure (PIP) with the measured PIP. If the absolute difference between the determined and measured pump intake pressure (PIP) exceeds a predefined threshold (5 to 10 psi), the method may adjust the productivity index (PI) of the well. The productivity index (PI) may be incrementally decreased or increased in steps of 0.05 to 0.2 bpd / psi, depending on the direction of the deviation. The estimation process may then be reiterated to ensure the pump intake pressure (PIP) matches.

[0135] In some exemplary embodiments of the present invention, upon achieving a match between pump intake pressure (PIP) and fluid flow rate, the method may compare the determined fluid flow rate with the measured fluid flow rate. If the absolute difference between these values exceeds a predefined threshold (10 to 50 bpd), the method may adjust the pump wear factor. The wear factor may be incrementally increased or decreased in steps of 0.005 to 0.1, depending on the direction of the deviation. The estimation process may then be re-initiated to reassess both the pump intake pressure (PIP) and fluid flow rate.

[0136] In some exemplary embodiments of the present invention, if more than one value satisfies either the pump intake pressure (PIP) match or the fluid flow rate match, the method may proceed to compare the pump discharge pressure (PDP). The method may compare the determined pump discharge pressure (PDP) with the measured pump discharge pressure (PDP) and adjust the tubing internal diameter of the well if the absolute difference exceeds the predefined threshold (5 to 10 psi). The tubing internal diameter maybe incrementally increased or decreased in steps of 0.001 to 0.1 inches, depending on the direction of the deviation. After these adjustments, the estimation process may reiterate to ensure matches in pump intake pressure (PIP), fluid flow rate, and pump discharge pressure (PDP).

[0137] For example, a plurality of candidate fluid flow rates may be generated based on the generated pump discharge pressure and generated pump intake pressure. For instance, the plurality of the fluid flow rates may be C1, C2 and C3, which may be generated as C1 = f(Pd_1, Pi_1), C2 = f(Pd_2, Pi_2), and C3 = f(Pd_3, Pi_3), where Pd_i and Pi_i are the generated pump discharge and generated intake pressures, respectively, and f() is a function relating these pressures to fluid flow rate. The level of similarity’ may be determined between these generated pressure values i.e. generated pump discharge pressure and generated pump intake pressure, and the received pressures values i.e. received pump discharge pressure and received pump intake pressure. For example, the similarity scores SI, S2 and S3 may be determined as SI = h(|Pd - Pd 1 j, |Pi - Pi __1 j), S2 = h(jPd - Pd__2|, |Pi - Pi_2i), and S3 = h(jPd - Pd_ 3|, |Pi - Pi__3|), where Pd and Pi are the received pump discharge and pump intake pressures, and h(_) is a similarity function. Thereafter, a plurality of shortlisted fluid flow rates may be determined based on the determined similarity scores. For instance, if SI and S3 exceed the similarity’ threshold, Cl and C3 may be considered as a shortlisted fluid flow rates. The shortlisted fluid flow rates Cl and C3 may represent the candidate fluid flow rates where the corresponding generated pressure values closely matches the received pressures values.

[0138] The plurality of candidate fluid flow rates may be generated using: Ci = (Pr - Ps) * PI_i, where Pr is the reservoir pressure at pump depth, Ps is the measured pump intake pressure, and PI_i is the productivity index for each iteration. The level of similarity between each of these generated candidate fluid flow rates and the shortlisted fluid flow rates may be determined. The level of similarity may be determined by determining the similarity scores like T1 = j(|C1 - C1'|) and T3 = j(|C3 - C3'|), where C1' and C3' are the generated flow rates corresponding to the shortlisted C1 and C3, and j() is another similarity function. The desired fluid flow rate may be selected from the shortlisted fluid flow rates based on these similarity scores. For example, if T1 is higher than T3 andexceeds the similarity threshold (which is in the range of 30-50 BPD), the candidate fluid flow rate Cl may be selected as the desired fluid flow rate. In some exemplary embodiments of the present invention, the variations in the method may include adjustments to filtering criteria or thresholds to accommodate different operational scenarios or well conditions. These variations may involve modifying the range of acceptable deviation for the power fluid rate or suction pressure to optimize the accuracy of the estimation process. Additionally, variations may include alternative algorithms or computational techniques for processing input data, depending on the specific requirements of the well operations.

[0139] In some exemplary embodiments of the present invention, the method may be implemented using computational tools or software designed to handle the iterative calculations and filtering processes efficiently. These tools may offer customization options to incorporate additional features or functionalities, further enhancing the accuracy and reliability of the estimation process. Overall, the method provides a systematic approach to estimating surface fluid flow rate in the wellbores using jet pump and / or ESP, contributing to improved monitoring and optimization of oil and gas extraction operations.

Claims

AMENDED CLAIMS received by the International Bureau on 28 April 2026 (28.04.2026)1. A method (400) for determining a fluid flow rate of a wellbore, the method comprising: receiving (402) predefined values of one or more parameters defining characteristics of the wellbore; generating (404) a plurality of candidate fluid flow rate based on the predefined values of the one or more parameters and an iterative value of the productivity index of the wellbore, wherein the candidate fluid flow rate is generated for each iterative value of the productivity index; generating (406) a plurality of values of the one or more parameters corresponding to the plurality of candidate fluid flow rate values; determining (408) a level of similarity between each of the plurality of generated values of the one or more parameters and the received predefined values of the one or more parameters; and selecting (410) a fluid flow rate from the plurality of candidate fluid flow rate based on the level of similarity between the generated values of the one or more parameters and the received values of the one or more parameters satisfying a similarity threshold.

2. The method as claimed in claim 1, wherein the one or more parameters include at least one of tubing head pressure, annulus power fluid pumping pressure, pump details, gas oil ratio, pump depth, pump intake pressure, pump discharge pressure, pump suction pressure, power fluid rate, liquid rate, oil rate, and water rate.

3. The method as claimed in claim 1, wherein generating the plurality of candidate fluid flow rate based on the predefined values of the one or more parameters43includes pump depth and at least one of pump intake pressure, pump discharge pressure, pump suction pressure.

4. The method as claimed in claim 1, wherein the candidate fluid flow rate is generated using:(received pump depth - received pressure)*productivity index(PI), wherein the value of PI is changed in steps of 0.01-0.1 barrels per day(BPD) / psi, and wherein the received pressure includes at least one of pump intake pressure, pump discharge pressure, pump suction pressure.

5. The method as claimed in claim 1, wherein generating the plurality of values of the one or more parameters include at least one of power fluid rate, pump intake pressure, pump discharge pressure, pump suction pressure.

6. The method as claimed in claim 1, wherein selecting the fluid flow rate from the plurality of candidate fluid flow rates is based on, at least one of: a. the level of similarity between the generated value of pump intake pressure and the received value of pump intake pressure satisfying a similarity threshold; and b. the level of similarity between the generated pump value of discharge pressure and a received value of pump discharge pressure satisfying a similarity threshold.

7. The method as claimed in claim 6, wherein the method includes generating a plurality of fluid flow rates based on at least one of the generated pump discharge pressure and generated pump intake pressure with level of similarity satisfying the corresponding similarity threshold with received pump discharge pressure and received pump intake pressure, respectively, determining a plurality of shortlisted fluid flow rates from the plurality of candidate fluid flow rates, wherein the shortlisted fluid flow rates are the candidate fluid flow rates when level of similarity between at least one of the44generated value of pump discharge pressure and the generated value of pump intake pressure, and received value of pump discharge pressure and the received value of pump intake pressure, corresponding to more than one candidate fluid flow rate satisfies the similarity threshold, determining the level of similarity between each of the plurality of generated fluid flow rates and the plurality of shortlisted fluid flow rates from the plurality of candidate fluid flow rate; and selecting the fluid flow rate from the plurality of shortlisted fluid flow rates based on the level of similarity between the generated fluid flow rates and the shortlisted fluid flow rates satisfying a similarity threshold, wherein the similarity threshold is in the range of 30-50 barrels per day(BPD).

8. The method as claimed in claim 5, wherein power fluid rate is generated using:where An is nozzle area received as input with jet pump setting depth parameter, PF is power fluid nozzle entry pressure received as input with jet pump setting depth parameter, Ps is jet pump suction pressure and (Kn) is nozzle loss coefficient.

9. The method as claimed in claim 8, wherein the power fluid rate is generated by iterating the value of Kn inwhere An is nozzle area received as input with jet pump setting depth parameter, PF is power fluid nozzle entry pressure received as input with jet pump setting depth parameter, Ps is jet pump suction pressure, Kn is nozzle loss coefficient, and, wherein the value of kn lies between 0.01-0.05.

10. The method as claimed in claim 1, wherein selecting the fluid flow rate from the plurality of candidate fluid flow rates is based on the level of similarity45satisfying a similarity threshold between the generated power fluid rate and the received power fluid rate.

11. The method as claimed in claim 10, wherein the received value of the power fluid rate is determined by a flowmeter.

12. The method as claimed in claim 1, wherein selecting the fluid flow rate from the plurality of candidate fluid flow rates is based on the level of similarity between the generated pump suction pressure and a received pump suction pressure satisfying a similarity threshold.

13. The method as claimed in claim 12, wherein the pump suction pressure is determined using: pump suction pressure value = reservoir pressure at pump depth - (received fluid flow rate / productivity index).

14. The method as claimed in claim 1, wherein the iterative value of productivity index is determined by iterating between 0-100, and wherein each iteration increases the iterative value of productivity index by a number between 0-100.

15. The method as claimed in claim 14, wherein the iterative value of productivity index is determined by iterating between 0.01-0.1 BPD / psi.

16. A system (300) for determining a fluid flow rate of a wellbore comprising: a control unit (314) including a memory (326); and one or more processors (324) coupled with the memory, the processor configured to: receive predefined values of one or more parameters defining characteristics of the wellbore;generate a plurality of candidate fluid flow rate based on the predefined values of the one or more parameters and an iterative value of the productivity index of the wellbore, wherein the candidate fluid flow rate is generated for each iterative value of the productivity index; generate a plurality of values of the one or more parameters corresponding to the plurality of candidate liquid rate values; determine a level of similarity between each of the plurality of generated values of the one or more parameters and the received predefined values of the one or more parameters; and select a fluid flow rate from the plurality of candidate fluid flow rate based on the level of similarity between the generated values of the one or more parameters and the received values of the one or more parameters satisfying a similarity threshold.

17. The system as claimed in claim 16, wherein the control unit generates the one or more parameters including at least one of tubing head pressure (FTHP), annulus power fluid pumping pressure, pump size details, gas oil ratio, pump depth, pump completion diagram, pump intake pressure, pump discharge pressure, pump suction pressure, deviation data, power fluid rate, oil rate, and water rate.

18. The system as claimed in claim 16, wherein the control unit generates the plurality of candidate fluid flow rates based on predefined values of the one or more parameters including pump depth and at least one of pump intake pressure, pump discharge pressure, pump suction pressure.

19. The system as claimed in claim 16, wherein the control unit generates the candidate fluid flow rate using:Candidate fluid flow rate = (received pump depth - received pressure)*productivity index(PI),wherein the value of PI is changed in steps of 0.01-0.1 barrels per day (BPD) / psi, and wherein the received pressure includes at least one of pump intake pressure, pump discharge pressure, pump suction pressure.

20. The system as claimed in claim 16, wherein the control unit generates the plurality of values of the one or more parameters including at least one of power fluid rate, pump intake pressure, pump discharge pressure, pump suction pressure.

21. The system as claimed in claim 16, wherein the control unit selects the fluid flow rate from the plurality of candidate fluid flow rates based on at least one of: a. the level of similarity between the generated value of pump intake pressure and the received value of pump intake pressure satisfying a similarity threshold; and b. the level of similarity between the generated value of pump discharge pressure and received value of pump discharge pressure satisfying a similarity threshold.

22. The system as claimed in claim 21, wherein the control unit generates a plurality of fluid flow rates based on at least one of the generated pump discharge pressure and generated pump intake pressure, with the level of similarity satisfying the corresponding similarity threshold with received pump discharge pressure and received pump intake pressure, respectively; determines a plurality of shortlisted fluid flow rates from the plurality of candidate fluid flow rates, wherein the shortlisted fluid flow rates are the candidate fluid flow rates when level of similarity between at least one of the generated value of pump discharge pressure and the generated value of pump intake pressure, and received value of pump discharge pressure and, the received value of pump intake pressure, corresponding to more than one candidate fluid flow rate satisfies the similarity threshold;48determines the level of similarity between each of the plurality of generated fluid flow rates and the plurality of shortlisted fluid flow rates from the plurality of candidate fluid flow rate; and selects the fluid flow rate from the plurality of shortlisted fluid flow rates based on the level of similarity between the generated fluid flow rates and the shortlisted fluid flow rates satisfying a similarity threshold, wherein the similarity threshold is in the range of 30-50 barrels per day(BPD).

23. The system as claimed in claim 20, wherein the control unit generates the power fluid rate using:where An is nozzle area received as input with jet pump setting depth parameter, PF is power fluid nozzle entry pressure received as input with jet pump setting depth parameter, Ps is jet pump suction pressure, (Kn) is nozzle loss coefficient.

24. The system as claimed in claim 23, wherein the control unit generates the power fluid rate by iterating the value of Kn in:where An is nozzle area received as input with jet pump setting depth parameter, PF is power fluid nozzle entry pressure received as input with jet pump setting depth parameter, Ps is jet pump suction pressure, Kn is nozzle loss coefficient, and, wherein the value of kn lies between 0.01-0.05.

25. The system as claimed in claim 16, wherein the control unit selects the fluid flow rate from the plurality of candidate fluid flow rates based on the level of similarity satisfying a similarity threshold between the generated power fluid rate and the received power fluid rate.4926. The system as claimed in claim 25, wherein the received value of the power fluid rate is determined by a flowmeter.

27. The system as claimed in claim 16, wherein the control unit selects the fluid flow rate from the plurality of candidate fluid flow rates based on the level of similarity between the generated pump suction pressure and the received pump suction pressure satisfying a similarity threshold.

28. The system as claimed in claim 27, wherein the pump suction pressure is determined using: pump suction pressure value = reservoir pressure at pump depth - (received fluid flow rate / productivity index).

29. The system as claimed in claim 16, wherein the iterative value of the productivity index is determined by iterating between 0-100, and each iteration increases the iterative value of the productivity index by a number between 0- 100.

30. The system as claimed in claim 16, wherein the iterative value of the productivity index is determined by iterating between 0.01-0.1 BPD / psi.50

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