A method and a system for determining a jet pump suction pressure

Abstract

The present invention discloses a method and a system for determining a pump suction pressure value of a jet pump in a wellbore. The method comprises receiving (302) a value for one or more parameters representing characteristics of the wellbore. A plurality of candidate pump suction pressure values are generated (304) based on the value of the one or more parameters and an iterative value of the productivity index of the wellbore. Furthermore, a plurality of values for the one or more parameters are generated (306) based on each of the plurality of candidate pump suction pressure values. The pump suction pressure value is then determined (308) by selecting at least one candidate pump suction pressure value from the plurality of candidate pump suction pressure values based on the one or more generated values of the one or more parameters matching a selection criteria, wherein the selection criteria is based on a measure of similarity between the received value of the one or more parameters and the generated value of the one or more parameters.

Description

A METHOD AND A SYSTEM FOR DETERMINING A JET PUMP SUCTION PRESSURETechnical field

[0001] The present invention relates to a method and a system for determining a jet pump suction pressure, and more particularly relates to the method and the system for determining the suction pressure of a jet pump without deploying any downhole physical sensor or gauge in a wellbore.Background

[0002] In the domain of oil well operations, the accurate determination of downhole pump intake pressure is pivotal for optimizing performance and understanding reservoir dynamics. Traditionally, downhole pump intake pressure is often measured using downhole pressure gauges or sensors installed within the wellbore as shown in Figure 1. These devices are strategically placed at specific depths to capture pressure data during the pumping process. However, the utilization of physical sensors and gauges comes with certain drawbacks. One significant limitation is the inherent difficulty in installing and maintaining these sensors in the harsh downhole environment. The installation process can be complex and time-consuming, and the sensors may be prone to wear and tear over time, requiring frequent interventions for replacements or repairs.

[0003] Moreover, during installation or retrieval of these gauges / sensors, the oil well needs to be shut down, which defers oil production and has an undesirable economic impact on the oil producing company. This operational constraint further compounds the challenges associated with traditional pressure measurement methods, as each intervention not only incurs direct costs but also results in lost production time.Summary:

[0004] In accordance with a first aspect of the present invention, there is provided a method for determining a pump suction pressure value of a jet pump in a wellbore. The method comprises receiving a value for one or more parameters representing characteristics of the wellbore, generating a plurality of candidate pump suction pressure values based on the one or more parameters and an iterative value of productivity index of the wellbore, generating a plurality of values for the one or more parameters based on each of the plurality of candidate pump suction pressure values, and determining the pump suction pressure value by selecting at least one candidate pump suction pressure value from the plurality of candidate pump suction pressure values based on the one or more generated values of the one or more parameters matching a selection criteria, wherein the selection criteria is based on a measure of similarity between the received value of the one ormore parameters and generated value of the one or more parameters. This method offers the advantage of accurately determining the pump suction pressure value, leading to optimized pump performance and improved operational efficiency.

[0005] In some exemplary embodiments of the present invention, the method further includes calculating the measure of similarity as the difference between the received value of the one or more parameters and the generated value of the one or more parameters. This approach enhances the accuracy of selecting the pump suction pressure value by minimizing discrepancies.

[0006] In some exemplary embodiments of the present invention, the method further includes calculating the measure of similarity as a statistical correlation between the received value of the one or more parameters and the generated value of the one or more parameters. This method provides a robust measure of similarity, ensuring a more reliable determination of the pump suction pressure value.

[0007] In some exemplary embodiments of the present invention, the method further includes generating the plurality of candidate pump suction pressure values using the formula: Pump Suction Pressure value = Reservoir Pressure at Pump Depth - (Measured Liquid Rate / Productivity index). This formula allows for precise generation of candidate pump suction pressure values, improving the overall accuracy of the method.

[0008] In some exemplary embodiments of the present invention, the method further includes determining the iterative value of productivity index by iterating through values between 0 and 100. This iterative approach ensures a comprehensive assessment of potential productivity index values, enhancing the accuracy of the final determination.

[0009] In some exemplary embodiments of the present invention, the method further includes increasing the iterative value of productivity index by an increment within the range of 0 to 100. This step-by-step iteration improves the precision of the productivity index assessment, leading to a more accurate determination of the pump suction pressure value.

[0010] In some exemplary embodiments of the present invention, the method further includes using one or more parameters such as flowing tubing head pressure (fthp), annulus power fluid pumping pressure, jet pump size details, gas oil ratio, jet pump setting depth, jet pump completion diagram, deviation data, power fluid rate, liquid rate, oil cut, and water cut. Including these parameters ensures a thorough evaluation of the wellbore characteristics, enhancing the reliability of the method.

[0011] In some exemplary embodiments of the present invention, the method further includes determining the generated value of 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 as received input with jet pump setting depth parameter, Ps is Jet Pump suction pressure as determined using, (Kn) is nozzle loss coefficient.

[0012] In some exemplary embodiments of the present invention, the method further includes determining the received value of the power fluid rate by using a flowmeter.

[0013] In some exemplary embodiments of the present invention, the method further includes generating the value of the oil cut as a factor of 1 using:Oil cut = (measured oil rate) / (measured liquid rate - power fluid rate).

[0014] In some exemplary embodiments of the present invention, the method further includes generating the water cut as a factor of 1 using: water cut = (measured liquid rate - power fluid rate - measured oil rate) / (measured liquid rate - power fluid rate).

[0015] In accordance with a second aspect of the present invention, there is provided a system for determining a pump suction pressure value of a jet pump in a wellbore. The system comprises a control unit comprising a memory, and one or more processors coupled with the memory. The processor is configured to receive a value for one or more parameters representing characteristics of the wellbore, generate a plurality of candidate pump suction pressure values based on the one or more parameters and an iterative value of productivity index of the wellbore, generate a plurality of values for the one or more parameters based on each of the plurality of candidate pump suction pressure values, and select the pump suction pressure value from the plurality of candidate pump suction pressure values based on the one or more generated values of the one or more parameters matching a selection criteria for determining pump suction pressure, wherein the selection criteria is based on a measure of similarity between the received value of the one or more parameters and generated value of the one or more parameters. This system offers the advantage of automated and precise determination of pump suction pressure values for jet pumps in wellbores without using any physical sensor. By utilizing a control unit with memory and processors, the system efficiently processes data and calculations, leading to accurate selection of pump suction pressure values. This automated approach reduces the need for manual intervention and minimizes the risk of errors, ultimately improving the efficiency and reliability of wellbore operations.

[0016] In some exemplary embodiments of the present invention, the system further includes calculating the measure of similarity as the difference between the received value of the one or moreparameters and the generated value of the one or more parameters. This method enhances the accuracy of parameter matching, leading to better system performance.

[0017] In some exemplary embodiments of the present invention, the system further includes calculating the measure of similarity as a statistical correlation between the received value of the one or more parameters and the generated value of the one or more parameters. This approach ensures a robust measure of similarity, improving the reliability of the system.

[0018] In some exemplary embodiments of the present invention, the system further includes the control unit determining the plurality of candidate pump suction pressure values using: Pump suction pressure = reservoir pressure at pump depth - (measured liquid rate / productivity index).

[0019] In some exemplary embodiments of the present invention, the system further includes the control unit receiving one or more parameters such as flowing tubing head pressure (fthp), annulus power fluid pumping pressure, jet pump size details, gas oil ratio, jet pump setting depth, jet pump completion diagram, deviation data, power fluid rate, liquid rate, oil cut, and water cut. Including these parameters ensures a comprehensive evaluation of wellbore characteristics, improving the system's effectiveness.

[0020] In some exemplary embodiments of the present invention, the system further includes the control unit determining the power fluid rate using well modeling software.

[0021] In some exemplary embodiments of the present invention, the system further includes the control unit receiving the power fluid rate from a flowmeter. This ensures precise measurement of the power fluid rate, contributing to the overall accuracy of the system.

[0022] In some exemplary embodiments of the present invention, the system further includes the control unit determining the oil cut as a factor of 1 using: Oil cut = (measured oil rate) / (measured liquid rate - power fluid rate).

[0023] In some exemplary embodiments of the present invention, the system further includes the control unit determining the water cut as a factor of 1 using: water cut = (measured liquid rate - power fluid rate - measured oil rate) / (measured liquid rate - power fluid rate).

[0024] In some exemplary embodiments of the present invention, the system further includes the control unit receiving the oil cut and water cut from a multiphase flowmeter.Brief Description of Drawings

[0025] 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 reference numerals represent like elements and in which:

[0026] FIG. 1 illustrates a cross sectional view of a conventional oil wellbore.

[0027] FIG. 2 illustrates a block diagram of a system for determining a jet pump suction pressure, in accordance with an exemplary embodiment of the present invention.

[0028] FIG. 3 illustrates a non-limiting example of a method for determining jet pump suction pressure, in accordance with an exemplary embodiment of the present invention.

[0029] FIG. 4 illustrates a graphical representation of comparative experimental outcomes obtained from the method of present invention and field measured data.Reference NumeralsDescription:

[0030] The embodiments and implementations of the claimed subject matter 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 matter 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.

[0031] An embodiment of the present invention discloses a method and a system for determining jet pump suction pressure. The determination of jet pump suction pressure is required for assessing the efficiency and functionality of the jet pump system, which enables the extraction of liquids from the well. The determination allows for immediate insights into the suction conditions within the well, enabling operators to make decisions for optimizing pump performance. The jet pump, as a component in oil extraction, relies on high-pressure fluid to create a low-pressure zone in the intake section of Jet Pump, facilitating the extraction of liquids.

[0032] FIG. 1 illustrates a cross sectional view of a conventional 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 pressure of the power fluid injection at the surface being pumped into the jet pump or wellbore, flowing tubing head pressure, liquid rate and power fluid surface injection rate. For example, power fluid surface injection rate is determined using power fluid pressure sensor (104) such as power fluid flow meter and liquid rate using pressure sensor (110) such as surface liquid flow meter. Further, conventionally the wellbore includes a pump suction pressure sensor (112) positioned below the jet pump (102) to measure the pump suction pressure. The figure illustrates the flow of fluid stream from the wellbore to the surface wherein the fluid stream (108) contains power fluid (106), oil, and water drawn from the wellbore.

[0033] FIG. 2 illustrates a system (200) for determining a jet pump suction pressure in real time without using a pump suction pressure sensor. In one exemplary embodiment of the present invention, the system (200) may include a control unit (214) that serves as a central component for overseeing and managing the operations of the system. The control unit (214) may be implemented as either a general-purpose computer or a dedicated circuit. In some exemplary embodiments of the present invention, the control unit (214) may be configured to receive parameters for defining the wellbore characteristics. Specifically, the control unit (214) may receive, as input, the parameters such as flowing tubing head pressure (FTHP), 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 (202), measured oil rate at well pad (multiphase flowmeter) or measured oil rate at surface the wellbore and measured total water rate or water cut as a factor of 1 (reservoir water and power fluid water) at well pad multiphase flow meter or measured oil rate or oil cut at surface of the wellbore or the like.

[0034] In some exemplary embodiments of the present invention, the control unit (214) may include components, such as a central processing unit (CPU) or processors (220), memory (218), and input / output devices (216). The inclusion of a CPU or processors (220) may enable the control unit (214) to execute complex algorithms and process data in real-time. The memory may be located either in the cloud or internally within the system, and 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.

[0035] In some exemplary embodiments of the present invention, the control unit may feature user- friendly input / output devices, providing an intuitive and interactive interface for users. The interface may include a display screen (212), 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.

[0036] A memory (218) may be any form of storage either within or outside the control unit. 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, randomaccess memory (RAM), read-only memory (ROM), compact disc read-only memory (CDROM), electro- optical memory like compact 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 orcarry 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.

[0037] A display (212) 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.

[0038] An Input / Output interface devices (216) (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 may also 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.

[0039] In some exemplary embodiment of the present invention, the control unit (214) may determine pump suction pressure, reservoir water cut, reservoir oil cut and power fluid rate for each iteration by iterating the values of parameters that determine reservoir water cut, reservoir oil cut and power fluid rate.

[0040] In some exemplary embodiments of the present invention, the system may include a jet pump (202) to receive the extracted oil. The jet pump may be positioned in an uphole portion of the wellbore.

[0041] 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. The 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. It is a widely adopted and practical tool in the oil and gas industry, playing a vital role in enhancing overall productivity.

[0042] In some exemplary embodiment of the present invention, the system may include a plurality of sensors (204). In some exemplary embodiments of the present invention, the system may include a pressure sensor transmitter at the tubing head for measuring flowing tubing head pressure, for the determination of jet pump intake pressure and a comprehensive assessment of performance of the well.

[0043] In some exemplary embodiments of the present invention, the system may include a multiphase flowmeter to measure oil rate or oil cut at surface wellbore. Measured 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 or water cut at the wellbore.

[0044] Generally, in oil and gas production, water rate or water cut serves as a factor used to assess well performance. Water cut represents the fraction of water in the total liquid output from a well. A water cut of 1 (or 100%) indicates that the well produces only water. As water cut increases, it affects production economics due to water handling and disposal needs. Field operators monitor water cut to inform decisions about well operations, potential interventions, and overall field management strategies. The water cut trend over time can provide insights into reservoir behavior and the stage of field maturity.

[0045] Generally, in the oil and gas sector, oil rate or oil cut is a metric used to evaluate the proportion of oil in a well's total liquid production. It is calculated as the ratio of oil volume to the total volume of liquids (oil and water) produced from a well. An oil cut of 1 (or 100%) indicates that the well is producing pure oil with no water. As a field matures, oil cut typically decreases over time. This factor helps in assessing well performance, estimating reserves, and making operational decisions. Monitoring oil cut allows operators to track changes in reservoir behavior and optimize production strategies throughout the life cycle of an oil field.

[0046] In the field of oil extraction, total water rate, which includes both reservoir water and power fluid water, holds significance as a metric in evaluating well performance. The total water rate provides acomprehensive measure of the water content within the extracted fluids, offering insights into the fluid dynamics of the reservoir. The metric plays a role in assessing the overall efficiency of oil extraction processes, as it quantifies the volume of water produced alongside hydrocarbons.

[0047] In some exemplary embodiments of the present invention, the control unit (214) may receive jet pump size details as input parameters. In some exemplary embodiments of the present invention, the control unit (214) may receive annulus power fluid pumping pressure as an input parameter. In some exemplary embodiments of the present invention, the control unit (214) 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.

[0048] In some exemplary embodiments of the present invention, the system may include a power fluid pumping pressure sensor transmitter at annulus to measure power fluid pumping pressure, which may optimize pump suction pressure calculations and ensure a comprehensive assessment of the impact of power fluid on the overall well performance.

[0049] In some exemplary embodiments of the present invention, the control unit (214) may receive jet pump setting depth and completion diagrams as an input parameter. These parameters define the spatial placement of the jet pump and its completion configuration.

[0050] In some exemplary embodiments of the present invention, the control unit (214) 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. Generally, deviation data of the wellbore is required for understanding the trajectory of a drilled well. Wellbore deviation refers to the deviation of the wellbore from its intended vertical or horizontal path. This deviation can occur due to various factors, such as geological formations, drilling conditions, and directional drilling techniques. Accurate wellbore deviation data is necessary for optimizing drilling operations, ensuring the well reaches the targeted reservoir, and enabling proper placement of production equipment.

[0051] In some exemplary embodiments of the present invention, the control unit (214) may receive a value of the power fluid rate at the surface as an input parameter. Power fluid rate injection is a factor influencing the power fluid dynamics within the well.

[0052] In some exemplary embodiments of the present invention, the system may include a power fluid injection rate measuring flow meter to measure power fluid injection rate at the surface of the wellbore, ensuring accurate measurement and incorporation of the parameter.

[0053] In some exemplary embodiments of the present invention, the control unit (214) may determine pump suction pressure based on reservoir pressure at pump depth, measured liquid rate and productivity index.

[0054] Generally, in the field of oil and gas extraction, the well 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 PI indicates better reservoir performance and efficient fluid production.

[0055] In some exemplary embodiments of the present invention, the control unit (214) may determine pump suction pressure for each iteration value of productivity index (PI). In the realm of oil wellbores, pump suction pressure ('PS') is a vital parameter that provides insights into the suction conditions within the well. It denotes 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.

[0056] In some exemplary embodiments of the present invention, the control unit (214) may increase the value of PI with every iteration. In some exemplary embodiment of the present invention, the control unit (214) may determine pump suction pressure for each value of PI by substituting the values of reservoir pressure at pump depth, measured liquid rate and the value of PI at each iteration in below: Pump suction pressure = reservoir pressure at pump depth - (measured liquid rate / productivity index)- (1)

[0057] In some exemplary embodiments of the present invention, the control unit (214) may determine power fluid rate. In some exemplary embodiments of the present invention, the control unit (214) may determine the production fluid (PF) rate for each iteration by iterating values of Kn and PI. 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.

[0058] In some exemplary embodiments of the present invention, the control unit may determine power fluid rate substituting the value of each nozzle areas, power fluid nozzle equation, value of the iteration of jet pump nozzle loss coefficient and pump suction pressure for each iteration of productivity index in the below:

[0059] In the context of oil extraction, power fluid rate is a fundamental parameter that signifies the rate at which power fluid is injected into the wellbore to facilitate the extraction of oil and other fluids. The power fluid rate is one of the key factors 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. Controlling and optimizing the power fluid rate is essential for ensuring a reliable and productive oil extraction process in various operational scenarios.

[0060] 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 may regulates the flow dynamics of fluids, influencing the overall efficiency and performance of the power fluid injected into the wellbore. Engineers and operators closely monitor and calculate the nozzle area to optimize the jet pump system and enhance fluid lifting capabilities.

[0061] Power fluid nozzle entry pressure, also known as 'PF' is a significant factor in oil well operations, signifying 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 power fluid nozzle entry pressure is a determinant of the effectiveness of the jet pump system, directly impacting fluid dynamics, lift efficiency, and the overall success of the oil extraction process.

[0062] In some exemplary embodiments of the present invention, the control unit (214) may estimate reservoir water cut based on nozzle area (An), power fluid nozzle entry pressure and PS for each value of PI.

[0063] In the field of oil extraction, reservoir water cut is a parameter for assessing the composition of fluid produced from a well. The metric represents the proportion of water content present in the total liquid production, offering insights into the reservoir's fluid dynamics. The reservoir water cut is determined by dividing the water volume by the total liquid volume, where the liquid includes both oil and water.

[0064] In some exemplary embodiments of the present invention, the control unit (214) may determine reservoir water cut 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 (214) may determine the value of reservoir water cut rate for each iteration of Kn. In some exemplary embodiment of the present invention, the control unit (214) may determine Reservoir water cut for each value of PI and Kn bysubstituting the values of measured water rate, measured liquid rate and the value of power fluid at the current iteration below:Reservoir water cut rate = (measured liquid rate - power fluid rate - measured oil rate) / (measured liquid rate - power fluid rate) - (3)

[0065] In some exemplary embodiments of the present invention, the control unit (214) may determine reservoir oil cut based on nozzle area (An), power fluid nozzle entry pressure and PS for each value of PI.

[0066] In some exemplary embodiments of the present invention, the control unit (214) may determine reservoir oil cut 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 (214) may determine the value of reservoir oil cut rate for each iteration of Kn. In some exemplary embodiment of the present invention, the control unit (214) may determine oil water cut for each value of PI and Kn by substituting the values of measured water rate, measured liquid rate and the value of power fluid at the current iteration below:Reservoir oil cut rate= (measured oil rate) / (measured liquid rate - power fluid rate) - (4)

[0067] In some exemplary embodiments of the present invention, the measured values may refer to the values obtained from the sensors. In some exemplary embodiments of the present invention, determined values may be the values of pump suction pressure, power fluid rate, water cut rate and oil cut rate for each iteration.

[0068] In some embodiments of the present invention, the control unit (214) may receive as input all the parameters, measured values and determined values to process them using a well performance software.

[0069] Well performance software operates by integrating specific algorithms and models tailored to the oil and gas industry. It employs 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.

[0070] In some embodiments of the present invention, the control unit (214) may filter data received by the well performance software based on specific conditions.

[0071] Reference is made to Fig. 3 illustrating a non-limiting example of a method for determining a jet pump suction pressure in oil well operations. At step 302, the method includes receiving, by a control unit, a value for one or more parameters representing characteristics of the wellbore. In an exemplary embodiment of the present invention, the parameters may include flowing tubing head pressure (FTHP), 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, measured oil rate at well pad (multiphase flowmeter) or measured oil rate at surface the wellbore and measured total water rate (reservoir water and power fluid water) at well pad multiphase flow meter or measured oil rate at surface of the wellbore or the like.

[0072] At step 304, the method includes generating a plurality of candidate pump suction pressure values based on one or more parameters and an iterative value of productivity index of the wellbore. In an exemplary embodiment of the present invention, the parameters may include flowing tubing head pressure (FTHP), 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, measured oil rate at well pad (multiphase flowmeter) or measured oil rate at surface the wellbore and measured total water rate (reservoir water and power fluid water) at well pad multiphase flow meter or measured oil rate at surface of the wellbore or the like.

[0073] In some exemplary embodiment of the present invention, the plurality of the candidate pump suction pressure values may be dependent on the plurality of the iterative values of the productivity index. The method may 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 PI may be 1. In some exemplary embodiment of the present invention, the maximum value of PI may be 500. In some exemplary embodiment of the present invention, the minimum and maximum value may be a subset of any 2 numbers between 1-500 respectively. In some exemplary embodiment of the present invention, the PI may increase by a number between 0.1 to 500 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.

[0074] In some exemplary embodiment of the present invention, the method may determine pump suction pressure based on the tubing deposition pressure loss. In some exemplary embodiment of the presentinvention, the method may determine pump suction pressure based on the jet pump nozzle loss coefficient (Kn).

[0075] In some exemplary embodiment of the present invention, pump suction pressure may be a function of reservoir pressure at pump depth, measured liquid rate and productivity index.

[0076] In some exemplary embodiments of the present invention, measured total liquid rate may be derived from devices, for example, multiphase flow meter (MPFP).

[0077] In some exemplary embodiment of the present invention, pump suction pressure may be determined by substituting the values of reservoir pressure at pump depth, measured liquid rate and an iterative value of productivity index in the below equation:Pump suction pressure = reservoir pressure at pump depth - (measured liquid rate / productivity index)

[0078] 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 the diffuser section of the jet pump.

[0079] In some exemplary embodiments of the present invention, the measured power fluid rate may be obtained by a flow meter (124).

[0080] In some exemplary embodiments of the present invention, the method may utilize independent variables for determining pump suction pressure. 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 variable, which may be the main objective of the quantification process.

[0081] At step 306, the method includes generating a plurality of values for the one or more parameters based on each of the plurality of candidate pump suction pressure values. In an exemplary embodiment of the present invention, the parameters may include flowing tubing head pressure (FTHP), 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, measured oil rate at well pad (multiphase flowmeter) or measured oil rate at surface the wellbore and measured total water rate (reservoir water and power fluid water) at well pad multiphase flow meter or measured oil rate at surface of the wellbore or the like.

[0082] In some exemplary embodiments of the present invention, the method may further include determining the value of power fluid rate by the control unit.

[0083] In some exemplary embodiments of the present invention, the method may further include determining, by the control unit, the power fluid (PF) Rate for each iteration value of Kn and PI.

[0084] In some exemplary embodiments of the present invention, the power fluid rate may be determined by substituting the value of each nozzle areas, power fluid nozzle equation, value of the iteration of Jet Pump nozzle loss coefficient and pump suction pressure for each iteration of productivity index in the below by the control unit.where, An is nozzle area as received as input with jet pump setting depth parameter, PF is Power fluid nozzle entry pressure as received as input with jet pump setting depth parameter, Ps is Jet Pump suction pressure, (Kn) is nozzle loss coefficient.

[0085] 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 rate, commencing with a minimum value.

[0086] 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 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 within the range of 0.01-0.05.

[0087] 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 innerdiameter of the tubing, causing increased pressure losses. Regular monitoring and assessment of deposition pressure loss are for maintaining optimal well performance.

[0088] In some exemplary embodiments of the present invention, the method may further determine the reservoir oil cut based on the values of power fluid rate obtained by iterating PS and Kn. In some exemplary embodiments of the present invention, the oil cut rate may be determined by substituting the value of total oil rate measured at surface, total liquid rate measured at surface and the value of power fluid based on the iteration of Jet Pump nozzle loss coefficient and pump suction pressure for each iteration of productivity index in the below.Oil cut rate = total oil rate measured at surface / (total liquid rate at surface - calculated power fluid rate) -(4)

[0089] In some exemplary embodiments of the present invention, the reservoir water cut may be determined by the control unit. In some exemplary embodiments of the present invention, the method may further determine the reservoir water cut based on the values of power fluid rate obtained by iterating Ps and Kn.

[0090] In some exemplary embodiments of the present invention, the water cut rate may be determined by substituting the value of total oil rate measured at surface, total liquid rate measured at surface and the value of power fluid based on the iteration of jet pump nozzle loss coefficient and pump suction pressure for each iteration of productivity index in the below.Reservoir water cut = (Measured liquid rate - power fluid rate - measured oil rate) / (Measured liquid rate - power fluid rate) -(3)

[0091] At step 308, the method includes determining the pump suction pressure value by selecting at least one candidate pump suction pressure value from the plurality of candidate pump suction pressure values based on the one or more generated values of the one or more parameters matching a selection criteria, wherein the selection criteria is based on a measure of similarity between the received value of the one or more parameters and generated value of the one or more parameters.

[0092] In some exemplary embodiments of the present invention, the method may further include providing each of the parameters, measured 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.

[0093] In some exemplary embodiments of the present invention, the method may include one or more filtering conditions or the selection criteria to ensure the iteration process may converge and provide reliable solutions.

[0094] In some exemplary embodiment of the present invention, determined values may be the value obtained by the method of the present invention. In some exemplary embodiment of the present invention, measured values or received values may be the value obtained by the physical sensors.

[0095] In some exemplary embodiments of the present invention, the selection criteria may include a statistical correlation between the received value of the one or more parameters and the generated value of the one or more parameters. In some exemplary embodiments of the present invention, the selection criteria may include a difference between the received value of the one or more parameters and the generated value of the one or more parameters.

[0096] In some exemplary embodiments of the present invention, the selection criteria may include a statistical correlation between the received value of the one or more parameters and the generated value of the one or more parameters, wherein the statistical correlation may be determined by calculating a difference between a determined or generated value of the oil rate and a measured or received value of the oil rate at the wellbore, and evaluating whether the calculated difference falls within a predefined range, for example 10-200 barrels of oil per day (BPD).

[0097] In some exemplary embodiments of the present invention, the statistical correlation may be determined by calculating a difference between a determined or generated value of the total water rate and a measured or received value of the total water rate, and evaluating whether the calculated difference falls within a user-specified range, for example 10-200 barrels per day (BPD).

[0098] In some exemplary embodiments of the present invention, the statistical correlation may be determined by calculating a difference between a determined or generated value of the power fluid rate and a measured or received value of the power fluid rate, and evaluating whether the calculated difference falls within a user-specified range, such as 5-100 barrels per day (BPD).

[0099] In some exemplary embodiments of the present invention, the results may be filtered if conditions of parameters such as power fluid rate, total water rate, and oil rate are matched.

[0100] 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.

[0101] 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), tubingpressure loss or the like. The iterative approach may enhance the accuracy and reliability of the quantification process in different operational scenarios.

[0102] In some exemplary embodiments of the present invention, the method may determine PS, reservoir water cut, power fluid rate for each value of PI iteratively. In some exemplary embodiments of the present invention, the method may determine PS, reservoir water cut, power fluid rate for each value of Kn iteratively. In some exemplary embodiments of the present invention, the method may determine PS, reservoir water cut, power fluid rate for each value of tubing pressure loss iteratively.

[0103] In some exemplary embodiments of the present invention, the process of iteration may be completed when at least one filtered result is obtained i.e. the desired pump suction pressure value from the plurality of the candidate pump suction pressure values.

[0104] FIG. 4 illustrates a graphical representation of experimental outcomes, showcasing a comprehensive comparison between the calculated or determined pump suction pressure (PS) and power fluid (PF) derived using the present invention against the field data collected through conventional physical sensors. The data spans a timeframe of 5 months, providing a robust evaluation of the performance of the invention. Examining the graph reveals a close alignment between the determined or generated values and the measured or received values obtained from the physical sensors, with the lines representing these datasets nearly overlapping. The congruence signifies the accuracy and reliability of the present invention in quantifying essential parameters. Furthermore, the iterative nature of the invention allows for potential refinement by minimizing differences between successive iterations of variables such as productivity index (PI), jet pump nozzle loss coefficient (Kn), and tubing deposition loss. The fine-tuning capability enhances the precision of the quantification process, ensuring the obtained information closely mirrors real-world measurements.Table 1

[0105] The above Table 1 is experimental data showing different values of productivity index (PI), nozzle loss coefficient (Kn) and effective tubing deposition loss corresponding to different dates. For each of these values, a corresponding value for measured or received values (Meas Ps) of pump suction pressure obtained from conventional sensors and a value for the determined pump suction pressure (Mod Ps) obtained using the method as disclosed in the present invention. Further, a value of measured or received power fluid rate (Meas PF) is also depicted along with the value of determined power fluid rate (Mod PF) obtained using the method as disclosed in the present invention. Table 1 compares the determined values of pump suction pressure and power fluid rate using the present invention with the values of pump suction pressure and power fluid rate obtained from conventional physical sensors.

[0106] Using the method as described in the present invention and the values received by the control unit for PI, Kn, tubing deposition as 12.1, 0.22 and 37, respectively. The determined value of PS is obtained as 793 and the determined value of power fluid is obtained as 6041.28.

[0107] Using the method as described in the present invention and the values received by the control unit for PI, Kn, tubing deposition as 11.3, 0.21 and 35, respectively. The determined value of PS is obtained as 776 and the determined value of power fluid is obtained as 6040.

[0108] Using the method as described in the present invention and the values received by the control unit for PI, Kn, tubing deposition as 11, 0.22 and 49, respectively. The determined value of PS is obtained as 779 and the determined value of power fluid is obtained as 6040.

[0109] Using the method as described in the present invention and the values received by the control unit for PI, Kn, tubing deposition as 10.4, 0.23 and 35, respectively. The determined value of PS is obtained as 773 and the determined value of power fluid is obtained as 6040.

[0110] Using the method as described in the present invention and the values received by the control unit for PI, Kn, tubing deposition as 10.9, 0.28 and 29, respectively. The determined value of PS is obtained as 788 and the determined value of power fluid is obtained as 5889.

[0111] Using the method as described in the present invention and the values received by the control unit for PI, Kn, tubing deposition as 10.1, 0.28 and 40, respectively. The determined value of PS is obtained as 788 and the determined value of power fluid is obtained as 5889.

[0112] Using the method as described in the present invention and the values received by the control unit for PI, Kn, tubing deposition as 10, 0.28 and 46, respectively. The determined value of PS is obtained as 788 and the determined value of power fluid is obtained as 5889.

[0113] Using the method as described in the present invention and the values received by the control unit for PI, Kn, tubing deposition as 10.4, 0.3 and 24, respectively. The determined value of PS is obtained as 782 and the determined value of power fluid is obtained as 5889.

[0114] Using the method as described in the present invention and the values received by the control unit for PI, Kn, tubing deposition as 10, 0.29 and 51, respectively. The determined value of PS is obtained as 792 and the determined value of power fluid is obtained as 5889.

[0115] Using the method as described in the present invention and the values received by the control unit for PI, Kn, tubing deposition as 10.6, 0.23 and 130, respectively. The determined value of PS is obtained as 817 and the determined value of power fluid is obtained as 5889.

[0116] Using the method as described in the present invention and the values received by the control unit for PI, Kn, tubing deposition as 10.6, 0.23 and 110, respectively. The determined value of PS is obtained as 809 and the determined value of power fluid is obtained as 5889.

[0117] As can be observed from the above data, the comparison of the determined values of the pump suction pressure and power fluid rate corresponding to the different values of the one or more parameters such as productivity index (PI), nozzle loss coefficient (Kn) and effective tubing deposition loss, and the received or observed values of the pump suction pressure and power fluid rate represents the accuracy of the method and system as disclosed in the present invention.

Claims

AMENDED CLAIMS received by the International Bureau on 02 April 2026 (02.04.2026)

1. A method for determining a pump suction pressure value of a jet pump in a wellbore comprising: receiving (302) a value for one or more parameters representing characteristics of the wellbore; generating (304) a plurality of candidate pump suction pressure values based on the value of the one or more parameters and an iterative value of productivity index of the wellbore, wherein the plurality of candidate pump suction pressure values is dependent on the iterative value of the productivity index; generating (306) a plurality of values for the one or more parameters based on each of the plurality of candidate pump suction pressure values; and determining (308) the pump suction pressure value by selecting at least one candidate pump suction pressure value from the plurality of candidate pump suction pressure values based on the one or more generated values of the one or more parameters matching a selection criteria, wherein the selection criteria is based on a measure of similarity between the received value of the one or more parameters and generated value of the one or more parameters.

2. The method as claimed in claim 1, wherein the measure of similarity is a calculated difference between the received value of the one or more parameters and the generated value of the one or more parameters.

3. The method as claimed in claim 1, wherein the measure of similarity is a statistical correlation between the received value of the one or more parameters and the generated value of the one or more parameters.

4. The method as claimed in claim 1, wherein the plurality of candidate pump suction pressure values are generated using: pump suction pressure value = reservoir pressure at pump depth - (measured liquid rate / productivity index).

5. The method as claimed in claim 1, wherein the iterative value of productivity index is determined by iterating through values between 0 and 100.

6. The method as claimed in claim 5, wherein each iteration increases the iterative value of productivity index by an increment within the range of 0 to 100.25

7. The method as claimed in claim 1, wherein the one or more parameters include at least one of flowing tubing head pressure (fthp), annulus power fluid pumping pressure, jet pump size details, gas oil ratio, jet pump setting depth, jet pump completion diagram, deviation data, power fluid rate, liquid rate, oil cut, and water cut.

8. The method as claimed in claim 1, wherein the generated value of power fluid rate is determined 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.

9. The method as claimed in claim 7, wherein the received value of the power fluid rate is determined by a flowmeter.

10. The method as claimed in claim 7, wherein the generated value of the oil cut is determined using: oil cut = (measured oil cut) / (measured liquid rate - power fluid rate).

11. The method as claimed in claim 7, wherein the generated water cut is determined using: water cut = (measured liquid rate - power fluid rate - measured oil cut) / (measured liquid rate - power fluid rate).

12. The method as claimed in claim 7, wherein the received value of oil cut and received value of water cut are determined by a multiphase flowmeter.

13. A system for determining a pump suction pressure value of a jet pump in a wellbore comprising: a control unit (214) including a memory (218); and one or more processors (220) coupled with the memory (218), the processor (220) configured to: receive a value for one or more parameters representing characteristics of the wellbore; generate a plurality of candidate pump suction pressure values based on the one or more parameters and an iterative value of productivity index of the wellbore, wherein the plurality of candidate pump suction pressure values is dependent on the iterative value of the productivity index;generate a plurality of values for the one or more parameters based on each of the plurality of candidate pump suction pressure values; and select the pump suction pressure value from the plurality of candidate pump suction pressure values based on the one or more generated value of the one or more parameters matching a selection criterion for determining pump suction pressure, wherein the selection criteria is based on a measure of similarity between the received value of the one or more parameters and the generated value of the one or more parameters.

14. The system as claimed in claim 13, wherein the measure of similarity is a calculated difference between the received value of the one or more parameters and the generated value of the one or more parameters.

15. The system as claimed in claim 13, wherein the measure of similarity is a statistical correlation between the received value of the one or more parameters and the generated value of the one or more parameters.

16. The system as claimed in claim 13, wherein the control unit (214) determines the plurality of candidate pump suction pressure values using:Pump Suction Pressure = Reservoir Pressure at Pump Depth - (Measured Liquid Rate / Productivity index).

17. The system as claimed in claim 13, wherein the one or more parameters received by the control unit (214) include any one of flowing tubing head pressure (fthp), annulus power fluid pumping pressure, jet pump size details, gas oil ratio, jet pump setting depth, jet pump completion diagram, deviation data, power fluid rate, liquid rate, oil cut, and water cut.

18. The system as claimed in claim 17, wherein the power fluid rate generated by the control unit (214) is determined using a well modeling software.

19. The system as claimed in claim 17, wherein the power fluid rate received by the control unit (214) is received from a flowmeter.

20. The system as claimed in claim 17, wherein the oil cut generated by the control unit (214) is determined using: oil cut = (measured oil cut) / (measured liquid rate - power fluid rate).

21. The system as claimed in claim 17, wherein the water cut generated by the control unit (214) is determined using: water cut = (measured liquid rate - power fluid rate - measured oil cut) / (measured liquid rate - power fluid rate).

22. The system as claimed in claim 17, wherein the oil cut and water cut received by the control unit (214) are received from a multiphase flowmeter.28

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