A method and a system for determining characteristics of oil wells

Abstract

The present invention discloses a method and system for determining desired oil well characteristics which involves receiving invariant values for first parameters associated with the characteristics of the oil well, and receiving first and second values for second parameters at two distinct time intervals after the well is shut in. The method further includes defining the changes in the characteristics of the oil well by analyzing variations between the first and second values of the second parameters. Based on these received values, a third value for third parameters is determined, representing the desired oil well characteristics. This method enables accurate assessment and prediction of oil well behavior over time, enhancing the decision-making process for oil well management and optimization.

Description

A METHOD AND A SYSTEM FOR DETERMINING CHARACTERISTICS OF OIL WELLSTechnical Field:

[0001] The present invention relates to a method and a system for determining characteristics of oil wells or wellbores, and more particularly relates to the method and the system for determining characteristics including but not limited to reservoir pressure, productivity index, fluid column rise trend within the well annulus, pump intake pressure, oil decrease rate and liquid loss volume in oil wells over time.Background:

[0002] Oil wells serve as conduits for extracting resources such as oil and gas from underground reservoirs. The efficiency and effectiveness of these oil wells may be determined using characteristics of oil wells. These characteristics may be used for optimizing oil and gas extraction processes. However, traditional methods often require prolonged shut-in periods especially in tight oil & gas wells and costly hardware for determining reservoir characteristics, leading to delays and hindering production optimization efforts. Further, traditional methods present additional challenges like reducing operational efficiency of the oil well due to prolonged shut-in periods. These issues may result in suboptimal production rates and decreased profitability for oil and gas companies.Summary:

[0003] In accordance with a first aspect of the present invention, there is provided a method for determining at least one desired oil well characteristic. The method comprises receiving a value for one or more first parameters associated with characteristics of the oil well. The one or more parameters associated with the characteristics of the oil well are an invariant representation of said characteristic. The method further includes receiving a first value for one or more second parameters defining characteristics of the oil well at a first-time intervalafter the well is shut in, and receiving a second value for the one or more second parameters defining characteristics of the oil well at a second time interval when the well is shut in. The method further involves determining the change in the characteristics of the oil well based on the variations of the second value relative to the first value for each of the one or more second parameters. Finally, the method includes determining a third value for one or more third parameters defining the desired characteristics of the oil well based on the received values of the first parameters and the first and second values of the second parameters at the specified time intervals. By utilizing data from multiple time intervals, the method may predict future well behavior more reliably. Additionally, the ability to determine desired well characteristics based on historical data enables better decision-making in well management and optimization, potentially improving production efficiency and reducing operational costs.

[0004] In some exemplary embodiments of the present invention, the method may further include that the one or more first parameters may comprise at least one of the density of the fluid column in the oil well and the total capacity of the oil well.

[0005] In some exemplary embodiments of the present invention, the method may further include that the one or more second parameters may comprise at least one of the height of the fluid column in a well annulus, casing head pressure, and hydrostatic pressure of a gas column in the well annulus at the first-time interval and the second time interval.

[0006] In some exemplary embodiments of the present invention, the method may further include determining the height of the fluid column in the well annulus using an echoshot gun.

[0007] In some exemplary embodiments of the present invention, the method may further include determining the casing head pressure using a pressure gauge.

[0008] In some exemplary embodiments of the present invention, the method may further include defining the third parameters as one or more of reservoir pressure, productivity index, and height of the fluid column in the well annulus. The desired oil well characteristics are defined by the following relationship:H(t) = (•?»• . CUP .pa<- +

[0009] Here, H(t) represents the final height of the fluid column in the well annulus at the shut-in time (ft), p denotes the well fluid density (psi / ft), Pr represents the reservoir pressure (psi), CHP represents the casing head pressure (psi), Pgc denotes the gas column hydrostatic pressure (psi), Hi represents the pump submergence or initial column height (ft), J denotes the productivity index (bpd / psi), T represents the shut-in time (days), and c represents the well capacity (bbl / ft). By incorporating reservoir pressure, productivity index, and fluid column height into the analysis, the method ensures a detailed and accurate characterization of the performance of the well.

[0010] In some exemplary embodiments of the present invention, the method may further include defining the third parameter as pump intake pressure (PIP) which is defined by the following relationship:Here,PIP(t) represents the pump intake pressure at the shut-in time (psi),Pr denotes the reservoir pressure (psi),J represents the productivity index (bpd / psi),t represents the shut-in time (days),pf denotes the well fluid density (psi / ft),c represents the well capacity (bbl / ft),Hi represents the pump submergence or column height (ft),CHP denotes the casing head pressure (psi), andPgc represents the gas column hydrostatic pressure (psi).

[0011] In some exemplary embodiments of the present invention, the method may further include defining the third parameter as the rate of decrease in oil influx after the oil well is shut in which is defined by the following relationship:• AT-CHP - PK)Here,Qliq.rate(t) represents the oil decrease rate at the shut-in time,J denotes the productivity index (bpd / psi),t represents the shut-in time (days),pf denotes the well fluid density (psi / ft),Pr denotes the reservoir pressure (psi),Hi represents the pump submergence or column height (ft),CHP denotes the casing head pressure (psi), andPgc represents the gas column hydrostatic pressure (psi).

[0012] In some exemplary embodiments of the present invention, the method may further include defining the third parameter as fluid loss volume over time and is defined by the following relationship:Here,Vliq.loss(t) represents the liquid loss volume over time,Qi denotes the constant liquid rate prior to well shut-in,t signifies the shut-in time (days),c represents the well capacity (bbl / ft),pf denotes the well fluid density (psi / ft),Pr represents the reservoir pressure (psi),Hi signifies the pump submergence or column height (ft),CHP denotes the casing head pressure (psi),Pgc represents the gas column hydrostatic pressure (psi), andJ denotes the productivity index (bpd / psi).

[0013] In accordance with a second aspect of the present invention, there is provided a system for determining at least one desired oil well characteristic. The system may comprise a memory and one or more processors coupled with the memory. The processor is configured to receive a value for one or more first parameters associated with characteristics of the oil well. The value for the one or more first parameters associated with characteristics of the oil well is an invariant representation of said characteristic. The processor is further configured to receive a first value for one or more second parameters defining characteristics of the oil well at a first-time interval after the well is shut in, and receive a second value for the one or more second parameters defining characteristics of the oil well at a second time interval when the well is shut in. The plurality of variations of the second value with reference to the first value for each of the one or more second parameters define the change in the characteristics of the oil well associated with the corresponding second parameter. The processor is further configured to determine a third value for one or more third parameters defining the desired characteristics of the oil well based on the received values of the first parameters and the first and second values for each of the second parameters at the specified time intervals.

[0014] The system offers the advantage of automating the process of determining desired oil well characteristics, thereby increasing efficiency and accuracy. By utilizing a processor to handle data collection and analysis, the system reduces the potential for human error and enhances the reliability of the results. Automation facilitates more informed decision-making in well management and optimization, contributing to improved operational efficiency and reduced operational risks.

[0015] In some exemplary embodiments of the present invention, the system may further include defining the one or more first parameters as density of the fluid column in the welland total capacity of the well. The addition of density of the fluid column in the well and total capacity of the well enhances the capability of the system to capture essential characteristics of the oil well. By incorporating parameters such as fluid density and total capacity, the system may provide a comprehensive analysis of the condition and performance of the well.

[0016] In some exemplary embodiments of the present invention, the system may further include defining the one or more second parameters at the first- and second-time intervals as height of the fluid column in a well annulus and casing head pressure and hydrostatic pressure of a gas column in the well annulus. By including parameters such as fluid column height, casing head pressure, and gas column hydrostatic pressure, the system provides a thorough assessment of the characteristics of the well over time.

[0017] In some exemplary embodiments of the present invention, the system may further include determining the height of the fluid column in the well annulus using an echoshot gun. The use of echoshot gun enhances the capability of the system to accurately measure the fluid column height, an important parameter for evaluating well characteristics. Echoshot gun may be utilized for precise and reliable measurements, thereby improving the overall accuracy of the analysis done by the system.

[0018] In some exemplary embodiments of the present invention, the system may further include determining the casing head pressure using a pressure gauge.

[0019] In some exemplary embodiments of the present invention, the system may further include defining the third parameters as one or more of reservoir pressure, productivity index, and height of the fluid column in the well annulus. The desired oil well characteristics are defined by the following relationship:H(t) i (.Pr - OTP - Pgc 4- * 'In the above equation,H(t) represents the final height of the fluid column in the well annulus at the shut-in time (ft), p denotes the well fluid density (in psi / ft),Pr represents the reservoir pressure (in psi),CHP represents the casing head pressure (in psi),Pgc denotes the gas column hydrostatic pressure (in psi),Hi represents the pump submergence or initial column height (in feet),J denotes the productivity index (in bpd / psi),T represents the shut-in time (in days), andc represents the well capacity (in bbl / ft).

[0020] In some exemplary embodiments of the present invention, the system may further include defining the third parameter as pump intake pressure (PIP) which is defined by the following relationship:PH / '^7 1 )PIP(f)In the above equation,PIP(t) represents the pump intake pressure at the shut-in time (in psi),Pr denotes the reservoir pressure (in psi),J represents the productivity index (in bpd / psi),t represents the shut-in time (in days),pf denotes the well fluid density (in psi / ft),c represents the well capacity (in bbl / ft),Hi represents the pump submergence or column height (in feet),CHP denotes the casing head pressure (in psi), andPgc represents the gas column hydrostatic pressure (in psi).

[0021] In some exemplary embodiments of the present invention, the system may further include defining the third parameter as the rate of decrease in oil influx after the oil well is shut in which is defined by the following relationship:In the above equation,Qliq.rate(t) represents the oil decrease rate at the shut-in time,J denotes the productivity index (in bpd / psi),t represents the shut-in time (in days),pf denotes the well fluid density (in psi / ft),Pr denotes the reservoir pressure (in psi),Hi represents the pump submergence or column height (in feet),CHP denotes the casing head pressure (in psi), andPgc represents the gas column hydrostatic pressure (in psi).

[0022] In some exemplary embodiments of the present invention, the system may further include defining the third parameter as fluid loss volume over time and is defined by the following relationship:In above equation,Vliq.loss(t) represents the liquid loss volume over time,Qi denotes the constant liquid rate prior to well shut-in,t signifies the shut-in time (in days),c represents the well capacity (in bbl / ft),pf denotes the well fluid density (in psi / ft),Pr represents the reservoir pressure (in psi),Hi signifies the pump submergence or column height (in feet),CHP denotes the casing head pressure (in psi),Pgc represents the gas column hydrostatic pressure (in psi), andJ denotes the productivity index (in bpd / psi).Brief Description of Drawings:

[0023] The accompanying drawings are included in order to more clearly illustrate the embodiments of the present disclosure and the related art. The drawings included herein provide a further understanding of the disclosure, and are incorporated in and constitute a part of the present disclosure. It is appreciable that the drawings illustrate implementations of the disclosure and, together with the description, serve to explain the principles of the disclosure. It is apparent that the drawings are merely some embodiments of the present disclosure, a person having ordinary skill in this field can obtain other figures according to these figures without paying the premise.

[0024] FIG. 1 illustrates a cross-sectional view of a conventional oil wellbore with situation or conditions suitable to illustrate current invention.

[0025] FIG. 2 illustrates a block diagram of a system for determining characteristics of oil wells, in accordance with an exemplary embodiment of the present invention.

[0026] FIG. 3 illustrates a flowchart of a method for determining characteristics of oil wells, in accordance with an exemplary embodiment of the present invention.

[0027] FIG. 4 illustrates a graphical representation of comparative experimental outcomes obtained from the method of present invention and field measured data.

[0028] The summary above, as well as the following detailed description of illustrative embodiments, is better understood when read in conjunction with the appended drawings. 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 Numerals:Description of component Reference numeralA-annulus pressure sensor 112B-annulus pressure sensor 114Flowing THP pressure sensor 116Pump suction pressure sensor 118Pump discharge pressure sensor 120Well Annulus 130Gas slug 132Actual height of fluid within w( 134 annulusFoam 136Height of fluid + Foam 138Flow of fluid from the reservoir 150Oil and Gas 160Oil 162Gas 164Accumulated sand 170System 200Sucker rod pump 210Sucker rod 212Display 220Processors 230Memory 240Sensors 250I / O devices 260Control Unit 270Detailed Description:

[0029] 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 thedescription below, details of well-known features and techniques may be omitted to avoid unnecessarily obscuring the presented embodiments and implementations.

[0030] An embodiment of the present invention discloses a method and a system (200) for determining characteristics of oil wells or oil wellbores. An exemplary embodiment of the present invention may include a system and a method to determine characteristics of oil wells such as fluid column or liquid column rise trend within the annulus, pump intake pressure, oil decrease rate and liquid loss volume in oil wells over time. The method and system presented herein provides insights into well behavior even in challenging reservoir conditions. The determination of oil well characteristics is used for optimizing well performance and safeguarding the economic interests of oil and gas companies.

[0031] The liquid column includes the entirety of the fluid present within the wellbore, spanning from the bottom of the well to the surface facilities. The liquid column comprises various components, including crude oil, natural gas, and formation water, each characterized by distinct properties such as density, viscosity, and phase behavior. The behavior of the liquid column is influenced by a multitude of factors, including reservoir pressure, fluid composition, wellbore geometry, and production rate.

[0032] FIG. 1 illustrates a cross-sectional view of a conventional oil wellbore, showing a crucial pathway for fluid flow. Originating from a reservoir, the fluid traverses this pathway into the oil well, potentially accumulating sand (170) over time. If unchecked, this sand accumulation (170) poses a risk of obstructing fluid flow. Positioned within the downhole portion of the wellbore, a sucker rod pump (SRP) (210) facilitates the suction of liquids, including those mixed with impurities like sand and gases, from the reservoir into the well annulus (130). Within the well annulus (130), the fluid fills up to a designated height, denoted as (134), with an additional measurement marked as (138), accounting for the height inclusive of foam (136). Above this fluid level, the remaining annular space houses gases, exerting pressure towards the fluid. The fluid flows from the reservoir as shown by arrow (150), after which the suction of the pump takes the oil to the surface as shown by the arrow (162) and the gas slugs (132) that are coming from the reservoir, exit through the well annulus (130) asshown by arrow (164). When the well is shut-in, the outlet for the pressure exerted by both gases and fluid is lost, prompting an increase in pressure within the well annulus (130). Over time, the foam layer (136) diminishes under the mounting pressure, leading to the determination of the final actual height of the fluid column in the well annulus (130). Moreover, the wellbore is equipped with a multitude of sensors, including pressure gauges, A-annulus pressure sensor (112), B-annulus pressure sensor (114), flowing THP pressure sensor (116), pump suction pressure sensor (118), and pump discharge pressure sensor (120). These sensors (250) serve to measure critical well parameters such as pump submergence, pump intake pressure (PIP), and casing head pressure (CHP), facilitating comprehensive monitoring and analysis of well performance. Additionally, the figure highlights several parameters that remain unknown but may be calculated using the method detailed below, underscoring the method's potential to enhance understanding and optimization of oil well operations.

[0033] Figure. 2 illustrates a system (200) for determining reservoir characteristics of tight oil wells. In one exemplary embodiment of the present invention, the system (200) may include a control unit (270) that serves as a central component or processor (230) for overseeing and managing the operations of the system. The control unit (270) may be implemented as either a general-purpose computer or a dedicated circuit. In some exemplary embodiments of the present invention, the control unit may be configured to receive parameters for defining the well bore characteristics. Specifically, the control unit may receive input parameters including but not limited to reservoir pressure (Pr), productivity index (J), flowing reservoir pressure (Pwg), casing head pressure (CHP), gas column hydrostatic pressure (Pgc), well capacity (c), well fluid density (pF), shut-in time (T) and pump submergence or initial column height (Hi).

[0034] In some exemplary embodiments of the present invention, the control unit (270) may include components, such as a Central Processing Unit (CPU) or processors (230), memory, and input / output devices (260). The inclusion of a CPU or processor (230) may enable the control unit to execute complex algorithms and process data in real-time. The memory (240) 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.

[0035] In some exemplary embodiments of the present invention, the control unit (270) may feature user-friendly input / output devices, providing an intuitive and interactive interface for users. The interface may include a display (220) screen, buttons, touch panels, or other intuitive input methods. Using the input / output device, users may conveniently input parameters regarding well bore characteristics. The display screen may provide real-time feedback and display determined unknown parameters.

[0036] A memory (240) 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 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), and / 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 and / or the like that may be accessible via the internet.

[0037] A display (220) 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 and / or the like. In some embodiments of the present disclosure, thedisplay 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 and / or the like.

[0038] 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 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) and / or the like.

[0039] In some exemplary embodiment of the present invention, the control unit (270) may determine reservoir pressure, productivity index, fluid column rise trend within the annulus, pump intake pressure, oil decrease rate and liquid loss volume in oil wells over time.

[0040] In some exemplary embodiments of the present invention, the system (200) may include a tight oil well. Tight wells are characterized by reservoir rocks with very low permeability, significantly restricting fluid flow. These wells require specialized techniques,such as hydraulic fracturing, to improve fluid flow and enhance production efficiency. In the development and operation of tight wells, advanced methods are employed to manage the limited fluid flow and high pressure differentials. The implementation of these techniques ensures optimized recovery strategies and effective production from tight formations. In some exemplary embodiments of the present invention, the system may include a packerless well. Packerless wells are wells that do not use packers, devices that typically isolate sections of the wellbore to manage fluid flow and pressure. This design allows for production from multiple zones within the well, offering a flexible and efficient approach to hydrocarbon extraction. However, managing a packerless well requires careful consideration of pressure and flow dynamics to prevent crossflow between different zones. The operation of packerless wells involves advanced monitoring and control techniques to ensure safe and efficient production from multiple reservoir zones.

[0041] In some exemplary embodiments of the present invention, the system may include a low productivity well that is defined as a well that yields relatively small quantities of oil or gas compared to high productivity wells. These wells typically produce lower volumes of hydrocarbons, which makes them less economically viable and more difficult to manage. Low productivity may result from various factors, including poor reservoir quality, low permeability, high water saturation, or depletion of the hydrocarbon-bearing formation.

[0042] Low productivity wells may present significant challenges due to their reduced output.These wells often experience issues such as increased water cut, which is the ratio of water produced compared to the volume of total liquids produced. High water cut may complicate the extraction process and increase operational costs, as more effort and resources are required to separate and dispose of the produced water.

[0043] Low productivity wells may require more frequent interventions and maintenance to sustain production levels. For instance, the buildup of paraffin and scale within the wellbore may restrict fluid flow, necessitating regular cleaning and treatment. Additionally, artificial lift systems, such as sucker rod pumps (SRPs) (210), may need to be optimized or replaced more frequently to maintain efficiency in these wells. They may face economic challengesdue to the higher cost per barrel of oil or cubic foot of gas produced. The lower output may lead to a higher break-even price, making these wells less attractive for investment, especially in fluctuating market conditions. Operators may need to implement cost-saving measures and optimize production strategies to ensure the economic viability of these wells.

[0044] Low productivity wells often experience extended times for pressure build-up due to the inherently low permeability and poor quality of the reservoir. The slow pressure build-up means that when these wells are shut in, it may take weeks for the pressure to stabilize and provide accurate reservoir data. The prolonged shut-in period is necessary so that the pressure readings reflect the true reservoir conditions, as rapid pressure changes are less pronounced in low productivity wells. Consequently, the extended shut-in time may result in significant operational delays and economic losses, highlighting the need for more efficient methods to determine reservoir pressure in a shorter time frame.

[0045] To address this, the present invention employs an advanced column-rise equation coupled with real-time monitoring of pump submergence and inflow performance relationship (IPR) data. This innovative approach reduces the time required for pressure stabilization by continuously adjusting for dynamic reservoir conditions. When the well is shut in, the system immediately begins to monitor and analyze pressure data, utilizing the column-rise equation to predict the pressure build-up trajectory. By comparing real-time measurements with these predictions, the system can accurately determine when the pressure has stabilized to a reliable reading, often in a fraction of the time traditionally required. This method ensures that the reservoir pressure data is accurate without the need for extended shut-in periods. Moreover, the invention's ability to rapidly process and interpret pressure data minimizes operational delays and reduces economic losses associated with prolonged shut-in times.

[0046] In some exemplary embodiments of the present invention, the system (200) may include a sucker rod pump (SRP). The sucker rod pump (210) is positioned in a downhole portion of the wellbore.

[0047] A sucker rod pump is a widely recognized and extensively utilized artificial lift system in the oil and gas industry. The sucker rod pump comprises several key components, including a downhole pump assembly, sucker rods, and surface drive equipment. The downhole pump assembly, typically positioned at the bottom of the wellbore, consists of a pump barrel, plunger, standing valve, and traveling valve. The sucker rods (212), connected in a series, transmit reciprocating motion from the surface drive to the downhole pump, facilitating fluid lifting from the reservoir to the surface.

[0048] In some exemplary embodiment of the present invention, the system (200) may include a plurality of sensors. 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 pump intake pressure and a comprehensive assessment of performance of the well.

[0049] In some exemplary embodiments of the present invention, the system may include a multiphase flowmeter to measure oil rate at surface well bore. Measured oil rate is a parameter reflecting the actual oil production from the well.

[0050] In some exemplary embodiment of the present invention, the system may include a pressure gauge or pressure sensor or pressure transducer sensor at the surface of the well for measuring the casing head pressure.

[0051] In some exemplary embodiment of the present invention, an echoshot gun may be used for measuring pump submergence or initial height of the fluid column in the well annulus. The measurement received from the echoshot gun is used specifically for providing input data calculations

[0052] An echoshot gun is a specialized device used to generate acoustic signals within a wellbore. These signals travel through the well fluid and reflect off the fluid column and other well components, providing vital data on the internal conditions of the well. These echoshot guns are used for conducting a survey which involves using the echoshot gun to measure theheight of the fluid column within the well at specific instances. The acoustic signals emitted by the gun are analyzed upon reflection, allowing operators to determine the precise fluid levels and other characteristics within the wellbore.

[0053] The present invention optimizes the value of echoshot surveys by leveraging initial measurements of key parameters, such as reservoir pressure and productivity index, for prolonged periods. Following an initial echoshot survey conducted at two distinct instances, the invention utilizes derived relationships to accurately forecast changes in critical well parameters over time. Given that variables like reservoir pressure and productivity index evolve gradually, the initial survey data remains applicable for extended durations.

[0054] The approach of the present invention negates the necessity for frequent echoshot surveys, leading to substantial cost reductions. By harnessing the initial dataset and established correlations, the invention ensures precise and dependable assessments of well conditions. Consequently, operators may streamline well management and maintenance planning without recurrent and expensive survey undertakings.

[0055] In some exemplary embodiments of the present invention, the control unit (270) may receive any one of the parameters including but not limited to reservoir pressure (Pr), productivity index (J), flowing reservoir pressure (Pwg), casing head pressure (CHP), gas column hydrostatic pressure (Pgc), well capacity (c), well fluid density (pf), shut-in time (T) and pump submergence or initial column height (Hi).

[0056] The method and system (200) as disclosed in the present invention may use relations, for example those derived from the inflow performance relationship (IPR) to determine characteristics such as fluid column rise trend within the annulus, pump intake pressure, oil decrease rate and liquid loss volume in oil wells over time.

[0057] In some exemplary embodiments of the present invention, the control unit (270) may determine fluid column rise trend within the annulus using, for example, relations derivedfrom the inflow performance relationship (IPR). The fluid column rise trend within the well annulus (130) may be determined by:H(t) = (pr ■■■■ CHP . Pgc P' ' " - (1)In the above equation:H(t): represents the final height of the fluid column in the well annulus (134) at the shut-in time (ft).p: denotes the well fluid density (psi / ft).Pr: represents the reservoir pressure (psi).CHP: represents the casing head pressure (psi).Pgc: denotes the gas column hydrostatic pressure (psi).Hi: represents the pump submergence or initial column height (ft).J: denotes the productivity index (bpd / psi).T: represents the shut-in time (days),c: represents the well capacity (bbl / ft).

[0058] The inflow performance relationship (IPR) is a fundamental concept in petroleum engineering, describing the relationship between reservoir properties, wellbore geometry, and fluid flow characteristics. The inflow performance relationship may provide insights into the performance of oil and gas wells, aiding in reservoir evaluation, production optimization, and decision-making processes within the industry. The inflow performance relationship is a mathematical model used to analyze the fluid flow from a reservoir into a wellbore. The inflow performance relationship may consider factors such as reservoir pressure, fluid properties, wellbore configuration, and production rate to predict performance of the well over time. By understanding the inflow performance relationship, production strategies may be optimized, reservoir characteristics may be estimated, and productivity of the well may be evaluated.

[0059] Reservoir pressure (Pr) represents the pressure of the oil or gas within the reservoir formation. Reservoir pressure is a characteristic in well analysis which influences production rates and overall reservoir performance. Reservoir pressure directly affects the flow rate of fluids into the wellbore and is used for estimating the ultimate recovery potential of the well. For instance, a higher reservoir pressure typically indicates a greater potential for fluid production, while declining reservoir pressure over time may signify reservoir depletion.

[0060] The determination of reservoir pressure is important for understanding the overall health and potential of an oil well. Reservoir pressure provides insights into the available energy within the reservoir to drive oil to the surface. Accurate knowledge of the pressure allows for better planning and optimization of extraction processes, ensuring that the well is operating efficiently and effectively. Without accurate reservoir pressure data, it becomes challenging to estimate the productivity index, which measures the ability of the well to produce oil at a given pressure drop. The productivity index is a key indicator of well performance, helping operators make informed decisions about production strategies, well interventions, and long-term field development.

[0061] Well fluid density (pf) denotes the density of the fluid within the wellbore, influencing fluid flow dynamics and pressure distribution. Measured in psi / ft, well fluid density contributes to the accuracy of pressure determination and enhances understanding of fluid behavior within the wellbore.

[0062] Casing head pressure (CHP) denotes the pressure exerted at the top of the well casing.Casing head pressure is a parameter used in assessing the overall pressure profile within the wellbore and its influence on fluid flow dynamics. For instance, casing head pressure encompasses various factors such as fluid density, wellbore geometry, and production rates, all of which contribute to the pressure conditions at the wellhead. Additionally, casing head pressure may be influenced by external factors such as atmospheric pressure and temperature variations. A higher casing head pressure may indicate greater pressure support for fluid production, while a lower casing head pressure may suggest challenges such as fluid migration which refers to the unwanted movement of fluids between different geological formations,which can lead to contamination and reduced efficiency in hydrocarbon production or inadequate reservoir pressure support which occurs when the natural pressure within the reservoir is insufficient to drive fluids to the wellbore, resulting in lower production rates and the need for artificial lift techniques. In some exemplary embodiment of the present invention, casing head pressure may be measured using a pressure gauge or pressure sensor or pressure transducer sensor.

[0063] Gas column hydrostatic pressure (Pgc) refers to the pressure exerted by the gas within the wellbore. Gas column hydrostatic pressure is used for determining the overall pressure balance within the well and its effect on fluid flow behavior. For example, gas column hydrostatic pressure accounts for the weight of the gas above the fluid level within the wellbore, influencing pressure conditions and fluid flow dynamics. Additionally, gas column hydrostatic pressure may vary depending on factors such as gas density, well depth, and oil production rates. By incorporating gas column hydrostatic pressure into the analysis, insights into the gas-liquid interaction within the wellbore and its impact on production performance may be understood. Monitoring changes in gas column hydrostatic pressure over time allows for proactive management of gas influx issues and optimization of production strategies.

[0064] The representation of pump submergence or initial height of the fluid in the well annulus (Hi) may denote the depth at which the pump is submerged within the fluid in the wellbore, impacting pressure distribution and fluid dynamics. For instance, a pump submergence of 100 feet may characterize specific well configurations, dictating fluid flow characteristics and overall well performance. In some exemplary embodiments of the present invention, pump submergence or initial height of the fluid in the well annulus (130) may be measured using the echoshot gun.

[0065] The pump intake pressure (PIP) represents the pressure at the pump intake prior to the well being shut in. Pump intake pressure accounts for factors such as fluid column height, casing head pressure (CHP), and gas column hydrostatic pressure (Pgc). For instance, pump intake pressure incorporates the casing head pressure, which represents the pressure at the top of the well casing, and the gas column hydrostatic pressure, which accounts for the pressureexerted by the gas column in the wellbore. By considering factors like casing head pressure and gas column hydrostatic pressure, the pressure conditions within the wellbore and their impact on fluid flow dynamics may be understood. A higher pump intake pressure may indicate a greater pressure gradient driving fluid production, resulting in higher production rates. Conversely, a lower pump intake pressure may suggest issues such as fluid migration, wellbore integrity problems, or insufficient reservoir pressure. The change in pump intake pressure over time may offer information about well performance and potential issues. Pressure buildup within the wellbore may be assessed and reservoir characteristics may be evaluated by monitoring pump intake pressure during shut-in periods. Analyzing variations in pump intake pressure during production may help identify changes in fluid behavior, such as gas influx or liquid migration, enabling proactive measures to optimize production and mitigate risks.

[0066] The shut-in time (T) denotes the duration during which the well is closed off from production, influencing pressure buildup and reservoir evaluation. For example, a shut-in time of 3 days may be common for specific well testing procedures, allowing pressure dynamics and reservoir behavior to be assessed.

[0067] Well capacity (c) refers to the total volume of fluid that the wellbore and annulus may hold per unit length. For instance, a higher well capacity indicates that the wellbore and annulus may accommodate a larger volume of fluid, potentially leading to higher production rates during fluid flow. Conversely, a lower well capacity may restrict fluid flow and impact production performance. Variations in well capacity may include adjustments based on factors such as wellbore geometry, tubing dimensions, and fluid properties. For example, a wider tubing diameter or increased annular space may result in a higher well capacity, allowing for greater fluid storage and enhanced production potential. By considering variations in well capacity and their impact on fluid behavior, tailored production plans to maximize hydrocarbon recovery and economic value may be developed.

[0068] Productivity index (J) represents the ability of the well to produce fluids and provides insights into reservoir characteristics and flow behavior. Productivity index is a measure ofthe inherent productivity of the well under specific reservoir and operating conditions. Productivity index represents the ratio of the steady-state fluid flow rate into the wellbore to the pressure drawdown across the reservoir interval. Essentially, the productivity index determines how efficiently the reservoir may deliver fluids to the wellbore under the prevailing conditions. Productivity index may be represented as the number of barrels of fluid produced per day per PSI of pressure differential. Productivity index is considered a nonchanging property of the well under steady-state flow conditions. Productivity index once established remains relatively constant over time, assuming the reservoir conditions and well configuration remain unchanged. In practical terms, the ability of the well to produce fluids, as represented by the productivity index, does not fluctuate during normal production operations. The productivity index is primarily influenced by reservoir characteristics such as permeability, thickness, and fluid properties such as viscosity. Higher permeability reservoirs typically have higher productivity indices because they offer less resistance to fluid flow. Similarly, thicker reservoirs or those with lower fluid viscosity tend to have higher productivity indices.

[0069] In some exemplary embodiments of the present invention, the control unit (270) may determine pump intake pressure after the well is shut in using equation (1). The pump intake pressure after the well is shut in may be determined by:PIP(t ) _ *i J 1" -■L)-rHt-Pfi-CHP-iPge- (2) In the above equation:PIP(t): represents the pump intake pressure at the shut-in time (psi).Pr: denotes the reservoir pressure (psi), which reflects the initial pressure of the fluid within the reservoir formation.J: represents the productivity index (bpd / psi), indicating the ability of the well to produce fluids under given reservoir conditions.t: represents the shut-in time (days), signifying the duration during which the well is closed off from production.pf: denotes the well fluid density (psi / ft), representing the density of the fluid within the wellbore.c: represents the well capacity (bbl / ft), indicating the total volume of fluid the wellbore and annulus may hold per unit length.Hi: represents the pump submergence or column height (ft), signifying the depth at which the pump is submerged within the fluid column in the wellbore.CHP: denotes the casing head pressure (psi), representing the pressure at the top of the well casing.Pgc: represents the gas column hydrostatic pressure (psi), indicating the pressure exerted by the gas column in the wellbore.

[0070] In some exemplary embodiments of the present invention, the control unit may determine rate of decrease of oil influx in a well after the well shut-in using:Qiiq.rate(t) = -T^(Pr - Hi - Pf - CHP - PK)6■ - (3)In the above equation:Qliq.rate (t): represents the oil decrease rate at the shut-in time, providing insights into the rate of fluid production decline following well closure.J: denotes the productivity index (bpd / psi), which reflects the ability of the well to produce fluids under given reservoir conditions.t: represents the shut-in time (days), indicating the duration during which the well is closed off from production.pf: denotes the well fluid density (psi / ft), representing the density of the fluid within the wellbore.Pr: denotes the reservoir pressure (psi), which reflects the initial pressure of the fluid within the reservoir formation.Hi: represents the pump submergence or column height (ft), signifying the depth at which the pump is submerged within the fluid column in the wellbore.CHP: denotes the casing head pressure (psi), representing the pressure at the top of the well casing.Pgc: represents the gas column hydrostatic pressure (psi), indicating the pressure exerted by the gas column in the wellbore.

[0071] In some exemplary embodiments of the present invention, the control unit may determine the actual oil loss as a function of shut-in time, particularly considering wellbore storage effects after shut-in in a low productivity well where fluid pounding occurs. The dynamic changes in liquid influx rates with respect to time and wellbore storage effect may be determined by:-■ a • ( . ■ (Pr - Hi ■ p? . CHP -- Ppd 1 -- e'k J- (4)In the equation:Vliq.loss(t): represents the liquid loss volume over time, reflecting the cumulative effects of decreasing liquid influx rates during shut-in.Qi: denotes the constant liquid rate prior to well shut-in, providing a baseline for liquid influx, t: signifies the shut-in time, indicating the duration during which the well remains closed off from production.c: represents the well capacity, indicating the total volume of fluid the wellbore and annulus mayhold per unit length.pf: denotes the well fluid density, reflecting the density of the fluid within the wellbore. Pr: represents the reservoir pressure, indicating the initial pressure of the fluid within the reservoir formation.Hi: signifies the pump submergence or column height, representing the depth at which the pump is submerged within the fluid column in the wellbore.CHP: denotes the casing head pressure, indicating the pressure at the top of the well casing.Pgc: represents the gas column hydrostatic pressure, indicating the pressure exerted by the gas column in the wellbore.J: denotes the productivity index, indicating the ability of the well to produce fluids under given reservoir conditions.

[0072] Wellbore storage effect may refer to the temporary accumulation of fluids within the wellbore and near-wellbore reservoir matrix due to changes in production rates or shut-in conditions. The accumulation may occur because of the compressibility of fluids and the elastic properties of the reservoir rock, leading to a delay in pressure response and subsequent fluid flow.

[0073] Fluid pounding may manifest as oscillations or surges in the fluid column within the wellbore in response to variations in bottom hole pressure. The pressure variations may occur due to cyclic changes in production rates, equipment malfunctions, or natural reservoir behavior. Fluid pounding may negatively impact production efficiency by causing erratic fluid flow patterns and increasing the risk of equipment damage.

[0074] In some exemplary embodiments of the present invention, the relation for the inflow performance relationship may be represented by equation (5):Qliq.rate = J (Pr - Pwg) - (5)where,Qliq.rate: denotes the liquid flow rate from the reservoir,J: represents the productivity index of the well,Pr: represents reservoir pressure, andPwg: represents flowing reservoir pressure.

[0075] The difference “Pr - Pwg” may also represent the pressure drawdown across the reservoir or the pressure difference between the pressure at the reservoir and the pressure atthe bottom hole of the well. The pressure difference may also be represented by AP i.e. pressure differential. The pressure differential may give fluid flow rate before the well is shut in.

[0076] In some exemplary embodiments of the present invention, the inflow performance relationship (IPR) may also be represented at the pump depth by:Qliq. rate = J(Pr-htpump) - PIP - (6)where,Qliq.rate: represents the liquid flow rate from the reservoirJ: denotes the productivity indexPr-htpump: represents the reservoir pressure at the pump depthPIP: denotes the pump intake pressure.

[0077] Equation (6) provides further insight into the factors influencing well performance and fluid flow dynamics. By incorporating the reservoir pressure at the pump depth and the pump intake pressure, a more comprehensive understanding of the pressure drawdown across the reservoir and its impact on production rates may be gained.

[0078] The addition of the reservoir pressure at the pump depth (Pr-htpump) in the inflow performance relationship may enhance the accuracy of the inflow performance relationship equation by accounting for variations in pressure along the wellbore. The reservoir pressure at the pump depth may reflect the actual pressure conditions at the depth of the pump, considering factors such as fluid density and wellbore geometry. For instance, a higher reservoir pressure at the pump depth may indicate favorable conditions for fluid production, whereas a lower pressure may signify reservoir depletion or fluid migration.

[0079] In some exemplary embodiment of the present invention, after the well is shut in, determining the liquid rate (Qliq.rate) within the wellbore may involve the rate of change of the liquid column height (dh / dt) and the well capacity (c) by:Qliq.rate = c* (dh / dt) - (7)

[0080] Equation (7) may provide insights into the fluid flow dynamics within the well, considering the volume of fluid that may be accommodated per unit length along the wellbore and annulus. For instance, by multiplying the rate of change of the liquid column height (dh / dt) by the well capacity (c), an estimate of the flow rate of liquid within the wellbore over time may be determined. The flow rate of liquid within the wellbore accounts for factors such as wellbore geometry, tubing dimensions, and fluid properties, offering a comprehensive understanding of fluid behavior and production rates.

[0081] In some exemplary embodiment of the present invention, pump intake pressure may exhibit an increase when the well is shut-in due to the rise in pressure caused by the volume of fluid within the wellbore. The increase in pressure may be attributed to various factors, including the height of the water column at any given shut-in time, the density of the fluid, the casing head pressure at any shut-in time, and the gas column hydrostatic pressure. As the well is shut-in, the fluid column within the wellbore may experience a rise in height, resulting in an elevation in pressure exerted by the fluid. Additionally, the existing pressures from the casing head and the gas column may further contribute to the overall increase in pump intake pressure. Pump intake pressure may be represented by:PIP(t) = CHP(t) + Pgc + H(t)*pf - (8)

[0082] After the well is shut in, the pressure drawdown acting across the reservoir gradually decreases over time. As the well remains closed off from production, the reservoir pressure endeavors to equalize with the bottom hole pressure within the wellbore. To facilitate the pressure equalization process, the liquid column within the wellbore may rise at a particularrate, influenced by various factors such as reservoir characteristics, fluid properties, and shut- in duration.

[0083] To determine the behavior of the liquid column rise within the annulus after the well is shut in, equations may be utilized to model and understand the fluid flow dynamics within the wellbore. Equation (6) captures the fluid production rate as influenced by factors such as reservoir pressure, pump depth, and pump intake pressure. Similarly, equation (7) accounts for the liquid rate within the wellbore based on the well capacity and rate of change of the liquid column height. Whereas, equation (8) accounts for determining pump intake pressure at any shut-in time based on the casing head pressure at that time, gas column hydrostatic pressure and pressure exerted by the fluid column at that height.

[0084] Fig. 3 illustrates a non-limiting example of a flowchart of a method for determining characteristics of oil wells, in accordance with an exemplary embodiment of the present invention. At block 310, the method comprises receiving a value of one or more first parameters associated with characteristics of the oil well. The value of the one or more first parameters associated with the characteristics of the oil well is an invariant representation of said characteristic. The value of these parameters is not affected by the state of the oil well whether it is functional or shut-in. The one or more first parameters may include but are not limited to the density of the fluid column in the well annulus (130) and a total capacity of the oil well.

[0085] At block 320, the method further includes receiving a first value for one or more second parameters defining characteristics of the oil well at a first-time interval after the well is shut in. The values for the one or more second parameters are affected by the state of the oil well. The value changes if the well is operational and also shows change depending on the period of time for which the shut-in. The one or more second parameters may include but are not limited to height of the fluid column in the well annulus (130), casing head pressure and hydrostatic pressure of a gas column in the well annulus (130). As the shut-in period progresses, the increased total pressure experienced within the annulus may impact the dynamics of the fluid and gas columns. The height of the fluid column may rise in responseto the elevated pressure until it stabilizes at a certain level. Simultaneously, the gases within the confined space of the annulus may be constrained by the rising fluid level and exert additional pressure on the annulus walls and within the annulus. This interaction between fluid and gas dynamics underscores the importance of monitoring and understanding the changing parameters of the oil well during the shut-in period.

[0086] At block 330, the method includes receiving a second value for the one or more second parameters defining characteristics of the oil well at a second time interval when the well is shut in. The method further involves determining the change in the characteristics of the oil well based on the variations of the second value relative to the first value for each of the one or more second parameters.

[0087] At step 340, the method includes determining a third value for one or more third parameters defining the desired characteristics of the oil well based on the received values of the first parameters and the first and second values of the second parameters at the specified time intervals. The one or more third parameters may include but are not limited to reservoir pressure, productivity index, height of the fluid column in the well annulus (130), pump intake pressure, rate of decrease of oil influx after the oil well is shut-in and total fluid loss volume over time.

[0088] By utilizing data from multiple time intervals, the method may predict future well behavior more reliably. Additionally, the ability to determine desired well characteristics based on historical data enables better decision-making in well management and optimization, potentially improving production efficiency and reducing operational costs.

[0089] In some exemplary embodiments of the present invention, the method may include a tight oil well. In some exemplary embodiments of the present invention, the method may include a packerless well. In some exemplary embodiments of the present invention, the method may include a low productivity well that is defined as a well that yields relatively small quantities of oil or gas compared to high productivity wells.

[0090] In some exemplary embodiments of the present invention, the method may include receiving oil by a sucker rod pump (SRP) . The sucker rod pump (200) is positioned in a downhole portion of the wellbore.

[0091] In some exemplary embodiment of the present invention, the system (200) may include a plurality of sensors. In some exemplary embodiment of the present invention, the method may include receiving pressure data from a plurality of sensors. In some exemplary embodiments of the present invention, the method may include measuring a flowing tubing head pressure using a pressure sensor transmitter at the tubing head. In some exemplary embodiments of the present invention, the method may include determining by a multiphase flowmeter oil rate at surface well bore. Measured oil rate is a parameter reflecting the actual oil production from the well.

[0092] In some exemplary embodiment of the present invention, an echoshot gun may be used for measuring pump submergence or initial height of the fluid column in the well annulus (130). The measurement received from the echoshot gun is used specifically for providing input data calculations

[0093] In some exemplary embodiments of the present invention, the method may include receiving any one of the parameters such as reservoir pressure (Pr), productivity index (J), flowing reservoir pressure (Pwg), casing head pressure (CHP), gas column hydrostatic pressure (Pgc), well capacity (c), well fluid density (pf), shut-in time (T) and pump submergence or initial column height (Hi).

[0094] In some exemplary embodiment of the present invention, the method may include determining by the control unit, using equations (6), (7) and (8), the behavior of the liquid column rise within the annulus after the well is shut in by:H(t) = (pr •••• CHP Pgc 4-P / ' " - (1) In the above equation:H(t): represents the final height of the fluid column in the well annulus (130) at the shut-in time (ft).p: denotes the well fluid density (psi / ft).Pr: represents the reservoir pressure (psi).CHP: represents the casing head pressure (psi).Pgc: denotes the gas column hydrostatic pressure (psi).Hi: represents the pump submergence or initial column height (ft).J: denotes the productivity index (bpd / psi).T: represents the shut-in time (days),c: represents the well capacity (bbl / ft).

[0095] Equation (1) may be used to analyze the behavior of the liquid column within the wellbore during shut-in. By incorporating known values for parameters such as reservoir pressure, casing head pressure, pump submergence, productivity index, and shut-in time, prediction for the final height of the fluid column in the well annulus (130) may be determined at any given time.

[0096] In some exemplary embodiment of the present invention, the method may include determining by the control unit, pump intake pressure after the well is shut. The determination of pump intake pressure after the well is shut-in involves various factors derived from equations related to wellbore pressure dynamics. One such relation is represented as equation (8) i.e. PIP(t) = CHP(t) + Pgc + H(t)*pf, where PIP(t) denotes the pump intake pressure at a specific shut-in time (t), CHP(t) denotes the casing head pressure at the same time, Pgc represents the gas column hydrostatic pressure, H(t) represents the final height of the fluid column in the well annulus (130) at the shut-in time, and p represents the well fluid density.

[0097] Using equation (1), a relationship for determining pump intake pressure at any shut-in time based on other constants may be established which may be expressed as:(f- ' ' -• 1 ) + Hi’Pf +CH P -i- Pge- (2) In the equation:PIP(t): represents the pump intake pressure at the shut-in time (psi).Pr: denotes the reservoir pressure (psi), which reflects the initial pressure of the fluid within the reservoir formation.J: represents the productivity index (bpd / psi), indicating the ability of the well to produce fluids under given reservoir conditions.t: represents the shut-in time (days), signifying the duration during which the well is closed off from production.pf: denotes the well fluid density (psi / ft), representing the density of the fluid within the wellbore.c: represents the well capacity (bbl / ft), indicating the total volume of fluid the wellbore and annulus may hold per unit length.Hi: represents the pump submergence or column height (ft), signifying the depth at which the pump is submerged within the fluid column in the wellbore.CHP: denotes the casing head pressure (psi), representing the pressure at the top of the well casing.Pgc: represents the gas column hydrostatic pressure (psi), indicating the pressure exerted by the gas column in the wellbore.

[0098] Pump intake pressure at any shut-in time may be determined by equation (2) using the above parameters. By utilizing equation (2), prediction of the trend of pump intake pressure rise over time during well shut-in period may be determined, facilitating informed decisionmaking and optimization strategies within the oil and gas industry.

[0099] In some exemplary embodiment of the present invention, the method may include, determining by the control unit, a decrease in oil rate following a well shut-in which may be understood as a consequence of the cessation of flow of fluid from the reservoir into thewellbore. When a well is shut, various dynamic processes may occur within the wellbore and reservoir, leading to changes in pressure and fluid behavior. One effect of the shut-in may be the gradual decrease in oil production rates over time.

[0100] After a well is shut, the flow of oil from the reservoir into the wellbore may cease, causing the pressure within the wellbore to build up initially due to fluid compression. As the shut-in duration progresses, reservoir pressure may start to equilibrate with the pressure in the wellbore. The pressure equalization process may result in a reduction of the driving force for the flow of fluid from the reservoir into the wellbore.

[0101] Additionally, during shut-in, the fluid column within the wellbore may undergo adjustments as the fluid column reacts to changes in pressure and temperature conditions. These adjustments may lead to changes in fluid properties and flow characteristics, further influencing the rate of oil production.

[0102] The decrease in oil rate following a well shut-in may be analyzed by considering the dynamic interactions between reservoir, wellbore, and fluid behavior. The inflow performance relationship may provide a framework for understanding these interactions and determining the oil rate decrease trend over time. By incorporating equation (6) with respect to any given shut-in time i.e. Qliq. rate (t) = J(Pr-htpump) - PIP(t) and Equation (2), a relation for determining rate of decrease of oil influx in a well after the well shut-in may be determined as:Qliq.rate(i) = "7^ ’ Pf ~ OHP - Psc)e" - (3)In the above equation:Qliq.rate (t): represents the oil decrease rate at the shut-in time, providing insights into the rate of fluid production decline following well closure.J: denotes the productivity index (bpd / psi), which reflects the ability of the well to produce fluids under given reservoir conditions.t: represents the shut-in time (days), indicating the duration during which the well is closed off from production.pf: denotes the well fluid density (psi / ft), representing the density of the fluid within the wellbore.Pr: denotes the reservoir pressure (psi), which reflects the initial pressure of the fluid within the reservoir formation.Hi: represents the pump submergence or column height (ft), signifying the depth at which the pump is submerged within the fluid column in the wellbore.CHP: denotes the casing head pressure (psi), representing the pressure at the top of the well casing.Pgc: represents the gas column hydrostatic pressure (psi), indicating the pressure exerted by the gas column in the wellbore.

[0103] By incorporating these parameters into the equation, the dynamic behavior of oil production rates over time following a well shut-in may be analyzed. The analysis may provide insights for optimizing production strategies and managing well performance effectively.

[0104] In some exemplary embodiment of the present invention, the method may include, determining by the control unit, the actual oil loss as a function of shut-in time, particularly considering wellbore storage effects after shut-in in a low productivity well where fluid pounding occurs.

[0105] In some exemplary embodiments of the present invention, to determine wellbore storage effect and fluid pounding, mathematical models and analytical methods may be used that account for reservoir properties, fluid behavior, and operational conditions. One approach may involve analyzing pressure transient data obtained from downhole sensors (250) or surface monitoring equipment during shut-in periods. By comparing pressure responses totheoretical models, the extent of fluid accumulation in the wellbore may be estimated and the severity of fluid pounding may be assessed.

[0106] In some exemplary embodiment of the present invention, the method may involve conducting numerical simulations using specialized reservoir engineering software. The simulations may simulate fluid flow and pressure dynamics within the wellbore and reservoir, allowing the effects of wellbore storage and fluid pounding under various operating scenarios to be visualized and quantified. Additionally, empirical correlations and field data analysis may provide insights into the magnitude and duration of these phenomena in specific reservoir environments.

[0107] In some exemplary embodiment of the present invention, the method may enable determination of actual oil loss occurring in oil wells due to wellbore storage behavior during shut-in periods. The actual oil loss occurring in oil wells may take into account the phenomenon of fluid pounding, which affects the flow dynamics within the wellbore and contributes to production losses over time.

[0108] In some exemplary embodiment of the present invention, mathematical models and simulation techniques may be used to determine the cumulative volume of oil storing in the well annulus over time during shut-in periods. By integrating the oil rate influx decrease equation with respect to time, the total volume of oil lost due to wellbore storage effects may be determined, facilitating more production loss assessments and reservoir performance evaluations. Liquid loss resulting from variable liquid rate decreasing function over time may also be determined. Liquid loss may reflect the volume of liquid expelled from the wellbore due to decreasing liquid influx rates during shut-in periods. The present embodiment may introduce the method to determine liquid loss by considering the cumulative effects of declining liquid rates over time.

[0109] The liquid loss volume (Vliq.loss) may be determined using:^'liq.loss — Ch ’ i J Chiq.ratel / )- (9)where:Viq.loss: represents the liquid loss volume due to decreasing liquid influx rates over time. Qi: denotes the constant liquid rate prior to well shut-in, serving as a baseline for liquid influx, t: signifies the shut-in time, indicating the duration during which the well remains closed off from production.Qliq.rate (t): represents the liquid influx rate as a function of time during the shut-in period.

[0110] Equation (9) may account for the dynamic nature of liquid influx rates, which gradually decrease over time following well shut-in. The term Qi.t represents the initial liquid volume available in the wellbore at the onset of shut-in, while the integral term accounts for the cumulative reduction in liquid influx rates over the shut-in period.

[0111] In some exemplary embodiment of the present invention, equation (8) may be further substituted to determine liquid loss, considering the dynamic changes in liquid influx rates with respect to time and wellbore storage effect and represented as:fflJn .... . / ... 21 ( p.r.... CEP - IM h - fi:. ' ' - (4)In the above equation:Vliq.loss(t): represents the liquid loss volume over time, reflecting the cumulative effects of decreasing liquid influx rates during shut-in.Qi: denotes the constant liquid rate prior to well shut-in, providing a baseline for liquid influx, t: signifies the shut-in time, indicating the duration during which the well remains closed off from production.c: represents the well capacity, indicating the total volume of fluid the wellbore and annulus may hold per unit length.pf: denotes the well fluid density, reflecting the density of the fluid within the wellbore. Pr: represents the reservoir pressure, indicating the initial pressure of the fluid within the reservoir formation.Hi: signifies the pump submergence or column height, representing the depth at which the pump is submerged within the fluid column in the wellbore.CHP: denotes the casing head pressure, indicating the pressure at the top of the well casing. Pgc: represents the gas column hydrostatic pressure, indicating the pressure exerted by the gas column in the wellbore.J: denotes the productivity index, indicating the ability of the well to produce fluids under given reservoir conditions.

[0112] Equation (4) may account for the dynamic changes in liquid influx rates over time, incorporating various parameters. By utilizing equation (4), an estimate of the liquid loss volume may be determined and its impact on overall well performance may be assessed, enabling optimization of production strategies and reservoir management practices to enhance oil and gas recovery.

[0113] In some exemplary embodiment of the present invention, a method is disclosed herein, for validating the accuracy and reliability of the equation (1) in assessing various characteristics such as reservoir pressure (Pr) and productivity index (PI) within a well. This step may entail analyzing data obtained from various shut-in wells to assess the performance of the equation under different conditions.

[0114] In some exemplary embodiments of the present invention, the authenticity of a mathematical equation is verified through the establishment and validation of boundary conditions. These boundary conditions serve as benchmarks against which the predictions or solutions of the equation are compared, determining accuracy and reliability in its application. One embodiment involves setting specific initial or boundary values for the variables involved in the equation, reflecting real-world scenarios or constraints relevant to the problem at hand. These boundary conditions may encompass physical limitations, environmental factors, or system constraints inherent to the problem domain. For instance, in the context of reservoirengineering, boundary conditions could include constraints on pressure, temperature, fluid flow rates, or geological properties such as permeability and porosity. These conditions provide essential context for solving equations governing fluid dynamics, reservoir behavior, or well performance. Once the boundary conditions are defined, the mathematical equation is solved numerically or analytically to obtain solutions or predictions. The results are then compared against observed data or known outcomes to assess the validity and predictive capability of the equation.

[0115] Before checking the boundary conditions, the initial conditions of the well may be established. Following an extended shut-in period, during which the well remains inactive, data may be collected to ensure reliable and consistent data collection. The pump submergence depths are recorded, with the pump submerged at -243 meters measured from True Vertical Depth (mTVD), facilitating measurements and analysis.

[0116] The results of boundary conditions provide insights into the behavior of the system at specific time points. For instance, in relation (1), at the initial time, the column height starts at its initial value, while the liquid production rate is determined by the productivity index multiplied by the pressure difference between the reservoir and the wellbore. This confirms the original relation of the liquid rate prior to well shut-in. Conversely, at infinite time, representing steady-state conditions, the system reaches equilibrium. Here, the column height is influenced by factors such as the pressure at pump depth, casing head pressure, and gas column hydrostatic pressure, all divided by the fluid density. Additionally, the liquid production rate approaches zero, signifying the cessation of fluid flow. This may confirm that after a long shut-in period, the liquid rate entering the well is zero. These boundary condition values serve as benchmarks for evaluating the accuracy and reliability of our equations in predicting system behavior.

[0117] Reference is made to FIG. 4 illustrating a non-limiting example of a curve which serves as a visual aid in validating a mathematical model aimed at predicting column rise within the realm of oil and gas extraction. The curve visualizes the relationship between pump submergence and rise in the height of the fluid column in the well annulus (130), pertinent tooil and gas extraction operations. The X-axis represents pump submergence measured in meters below True Vertical Depth (mTVD), while the Y-axis displays rise in the height of the fluid column in the well annulus (h(t)) based on the Inflow Performance Relationship (IPR) equation, also in mTVD. The scatter plot comprises multiple data points, indicative of measurements taken over several days.

[0118] The plotted curve aligns well with the observed data points for multiple dates throughout the displayed range. Specifically, the curve matches the observed data, for example on August 18th, 2022, August 21st, 2022, and August 24th, 2022. This close correspondence between the values predicted using the method as disclosed in the present invention and the field-tested / observed measurements suggests that the measurement technique is accurate and reliable. Overall, visualization facilitates the validation of predictions of a mathematical model against observed column rise data, aiding in the assessment of the accuracy and practical applicability of the present invention.

Claims

We claim:

1. A method for determining at least one desired oil well characteristics, the method comprising:receiving (310), a value for one or more first parameters associated with characteristics of the oil well, wherein the value for the one or more first parameters is an invariant representation of said characteristic;receiving (320), a first value for one or more second parameters defining characteristics of the oil well at a first time interval after the well is shut in;receiving (330), a second value for the one or more second parameters defining characteristics of the oil well at a second time interval when the well is shut in, wherein the plurality of variations of the second value with respect to the first value for each of the one or more second parameters defines the change in the characteristics of the oil well associated with the corresponding second parameter; anddetermining (340), a third value for one or more third parameters defining the desired characteristics of the oil well based on the received values of the one or more first parameters and the first value and the second value for each of the one or more second parameters defining the characteristics of the oil well at a first time interval and second time interval associated with the corresponding second parameter.

2. The method as claimed in claim 1 , wherein the one or more first parameters include at least one of a density of the fluid in a well annulus (130) and a total capacity of the oil well.

3. The method as claimed in claim 1, wherein the one or more second parameters include at least one of height of the fluid column in a well annulus (130), casing head pressure, and hydrostatic pressure of a gas column in the well annulus (130) at the first time interval and the second time interval.

4. The method as claimed in claim 3, wherein the height of the fluid column in the well annulus (130) is determined using an echoshot gun.

5. The method as claimed in claim 3, wherein the casing head pressure is determined using a pressure gauge.

6. The method as claimed in claim 1 , wherein the third parameters defining the desired oil well characteristics include one or more of:reservoir pressure;productivity index; andheight of the fluid column in the well annulus (130),the desired oil well characteristics is defined by:y r }■ ; X : / Tj O O ,1.:r \-O J "" ( i C-' il / * -f QC "!" |wherein, H(t) represents the final height of the fluid column in the well annulus (130) at the shut-in time (ft), p denotes the well fluid density (psi / ft), Pr represents the reservoir pressure (psi), CHP represents the casing head pressure (psi), Pgc denotes the gas column hydrostatic pressure (psi), Hi represents the pump submergence or initial column height (ft), J denotes the productivity index (bpd / psi), T represents the shut-in time (days) and c represents the well capacity (bbl / ft).

7. The method as claimed in claim 1, wherein the third parameter defining the desired oil well characteristics include pump intake pressure (PIP) and is defined by:' ' ’7 ' ' 1 S ' '.'■O' i Pgee" ''""twherein, PIP(t) represents the pump intake pressure at the shut-in time (psi), Pr denotes the reservoir pressure (psi), J represents the productivity index (bpd / psi), t represents the shut-in time (days), pf denotes the well fluid density (psi / ft), c represents the well capacity (bbl / ft),Hi represents the pump submergence or column height (ft), CHP denotes the casing head pressure (psi)and Pgc represents the gas column hydrostatic pressure (psi).

8. The method as claimed in claim 1, wherein the third parameter defining the desired oil well characteristics include rate of decrease of oil influx after the oil well is shut in and is defined by:’ (PT "" - Pr - C.HP "" Pdwherein, Qliq.rate (t) represents the oil decrease rate at the shut-in time, J denotes the productivity index (bpd / psi), t represents the shut-in time (days), pf denotes the well fluid density (psi / ft), Pr denotes the reservoir pressure (psi), Hi represents the pump submergence or column height (ft), CHP denotes the casing head pressure (psi) and Pgc represents the gas column hydrostatic pressure (psi).

9. The method as claimed in claim 1, wherein the third parameter defining the desired oil well characteristics include fluid loss volume over time and is defined by:wherein, Vliq.loss(t) represents the liquid loss volume over time, Qi denotes the constant liquid rate prior to well shut-in, t signifies the shut-in time (days), c represents the well capacity (bbl / ft), pf denotes the well fluid density (psi / ft), Pr represents the reservoir pressure (psi), Hi signifies the pump submergence or column height (ft), CHP denotes the casing head pressure (psi), Pgc represents the gas column hydrostatic pressure (psi) and J denotes the productivity index (bpd / psi).

10. A system (200) for determining at least one desired oil well characteristics, the system comprising:a memory; andone or more processors (230) coupled with the memory, wherein the one or more processors (230) are configured to:receive (310) a value for one or more first parameters associated with characteristics of the oil well, wherein the value for the one or more first parameters is an invariant representation of said characteristic;receive (320) a first value for one or more second parameters defining characteristics of the oil well at a first time interval after the well is shut in;receive (330) a second value for the one or more second parameters defining characteristics of the oil well at a second time interval when the well is shut in, wherein the plurality of variations of the second value with respect to the first value for each of the one or more second parameters defines the change in the characteristics of the oil well associated with the corresponding second parameter; anddetermine (340) a third value for one or more third parameters defining the desired characteristics of the oil well based on the received values of the one or more first parameters and the first value and the second value for each of the one or more second parameters defining the characteristics of the oil well at a first time interval and second time interval associated with the corresponding second parameter.

11. The system (200) as claimed in claim 10, wherein the one or more first parameters include density of the fluid column in the well and a total capacity of the well.

12. The system (200) as claimed in claim 10, wherein the one or more second parameters include at least one of height of the fluid column in a well annulus (130), casing head pressure, and hydrostatic pressure of a gas column in the well annulus (130) at the first time interval and the second time interval.

13. The system (200) as claimed in claim 12, wherein the height of the fluid column in the well annulus (130) is determined using an echoshot gun.

14. The system (200) as claimed in claim 12, wherein the casing head pressure is determined using a pressure gauge.

15. The system (200) as claimed in claim 10, wherein the third parameters defining the desired oil well characteristics includes one or more of:reservoir pressure;productivity index; andheight of the fluid column in the well annulus (130),the desired oil well characteristics is defined by:H(£) - -J; (Pr . CHF ■■■■ Pgc 4- )wherein, H(t) represents the final height of the fluid column in the well annulus (130) at the shut-in time (ft), p denotes the well fluid density (psi / ft), Pr represents the reservoir pressure (psi), CHP represents the casing head pressure (psi), Pgc denotes the gas column hydrostatic pressure (psi), Hi represents the pump submergence or initial column height (ft), J denotes the productivity index (bpd / psi), T represents the shut-in time (days) and c represents the well capacity (bbl / ft).

16. The system (200) as claimed in claim 10, wherein the third parameter defining the desired oil well characteristics includes pump intake pressure (PIP) and is defined by:PIP(t) =wherein, PIP(t) represents the pump intake pressure at the shut-in time (psi), Pr denotes the reservoir pressure (psi), J represents the productivity index (bpd / psi), t represents the shut-in time (days), pf denotes the well fluid density (psi / ft), c represents the well capacity (bbl / ft),Hi represents the pump submergence or column height (ft), CHP denotes the casing head pressure (psi)and Pgc represents the gas column hydrostatic pressure (psi).

17. The system (200) as claimed in claim 10, wherein the third parameter defining the desired oil well characteristics includes rate of decrease of oil influx after the oil well is shut in and is defined by:’ (Pr "" M - Pr - C.HP "" MJwherein, Qliq.rate (t) represents the oil decrease rate at the shut-in time, J denotes the productivity index (bpd / psi), t represents the shut-in time (days), pf denotes the well fluid density (psi / ft), Pr denotes the reservoir pressure (psi), Hi represents the pump submergence or column height (ft), CHP denotes the casing head pressure (psi) and Pgc represents the gas column hydrostatic pressure (psi).

18. The system (200) as claimed in claim 10, wherein the third parameter defining the desired oil well characteristics includes fluid loss volume over time and is defined by:wherein, Vliq.loss(t) represents the liquid loss volume over time, Qi denotes the constant liquid rate prior to well shut-in, t signifies the shut-in time (days), c represents the well capacity (bbl / ft), pf denotes the well fluid density (psi / ft), Pr represents the reservoir pressure (psi), Hi signifies the pump submergence or column height (ft), CHP denotes the casing head pressure (psi), Pgc represents the gas column hydrostatic pressure (psi) and J denotes the productivity index (bpd / psi).

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