Measurement of multiphase flow from well

Abstract

A multiphase well fluid system includes a moisture content meter configured for installation in a pipe network and for measuring a percentage of moisture content of a respective multiphase well fluid entering the pipe network from a respective well to a gas-oil separation plant (GOSP); a temperature sensor configured for installation in the pipe network and for measuring a temperature of a multiphase well fluid flow from the well into the pipe network to the GOSP; and a control system configured to perform operations including: generating a digital twin of the well and the pipe network; and determining a virtual flow rate of at least one fluid phase of each of the multiphase well fluids from the well using the generated digital twin, the measured percentage moisture content, and the measured temperature.

Description

Priority claim

[0001] This application claims the U.S. patent application No. 17 / 929,974 filed on September 6, 2022, the entire contents of which are hereby incorporated by reference herein. Technical Field

[0002] The present disclosure describes systems and methods for measuring multiphase flow from a well, and more particularly, systems and methods for measuring well flow including oil, gas, and water. Background Art

[0003] Periodically, each individual well (e.g., among many wells in a field) is tested for multiphase flow in the well to determine the gas flow rate, oil flow rate, and water flow rate of the individual well. Measurements are typically made using a high pressure test well (HPTT), which is a pressure vessel with flow measurement devices on the gas and liquid lines, or a multiphase flow meter (MPFM), which is a flow meter capable of measuring all phases in one device. The HPTT and MPFM are typically located in the gas and oil separation plant (GOSP) at a dedicated test manifold. To test a well, the well is connected to the test manifold, either directly from the flow line if the flow line is directly connected to the GOSP production header, or through a test line connection flow line at a remote location in the field if the flow line is normally connected to the mains. Summary of the invention

[0004] In an example embodiment, a multiphase well fluid system includes: a plurality of water cut meters configured to be installed in a pipeline network and used to measure the water cut percentage of a corresponding plurality of multiphase well fluids entering the pipeline network from a corresponding plurality of wells to a gas oil separation plant (GOSP); a plurality of temperature sensors configured to be installed in the pipeline network and used to measure the temperature of a corresponding plurality of multiphase well fluid flows entering the pipeline network from a corresponding plurality of wells to the GOSP; and a control system communicatively coupled to the plurality of water cut meters and the plurality of temperature sensors and configured to perform operations. The operations include: generating a digital twin of a plurality of wells and the pipeline network; and determining a virtual flow rate of at least one fluid phase of each of a plurality of multiphase well fluids from a corresponding plurality of wells using the generated digital twin, the plurality of measured water cut percentages, and the plurality of measured temperatures.

[0005] In aspects that may be combined with example embodiments, the operation of generating a digital twin of the plurality of wells and the pipeline network includes generating a digital twin of the plurality of wells and the pipeline network based on at least one well parameter and at least one pipeline network parameter.

[0006] In another aspect that may be combined with any of the preceding aspects, at least one well parameter includes at least one of the following: completion throttling setting, reservoir pressure, production index or PVT data; and at least one pipeline network parameter includes at least one of pipeline diameter, pipeline length, pipeline pressure loss, or flow control device pressure loss data.

[0007] Another aspect that may be combined with any of the preceding aspects further includes at least one flow meter configured to be mounted on a fluid output from the GOSP and to measure a flow rate of one of a plurality of fluid phases of the separation well fluid output from the GOSP.

[0008] In another aspect which may be combined with any of the preceding aspects, at least one flow meter comprises: a first flow meter configured to be mounted on a gas output from the GOSP; and a second flow meter configured to be mounted on an oil output from the GOSP.

[0009] In another aspect which may be combined with any of the preceding aspects, the at least one flow meter further comprises: a third flow meter configured to be mounted on the water output from the GOSP.

[0010] In another aspect that may be combined with any of the preceding aspects, the operations also include: comparing a plurality of determined virtual flow rates with a mass or volumetric fluid flow rate from the GOSP, the mass or volumetric fluid flow rate comprising a measured gas flow rate from a first flow meter, a measured oil flow rate from a second flow meter, and a measured water flow rate from a third flow meter; and verifying the plurality of determined virtual flow rates based on the comparison.

[0011] In another aspect that may be combined with any of the preceding aspects, the operations further include: adjusting the generated digital twin based on the comparison.

[0012] In another example embodiment, a method includes: measuring the water cut percentage of each of a plurality of multiphase well fluids from a corresponding plurality of wells using a plurality of water cut meters installed in a pipeline network between a plurality of wells and a gas and oil separation plant (GOSP); measuring the temperature of each of the plurality of multiphase well fluids from a corresponding plurality of wells using a plurality of temperature sensors installed in the pipeline network between the plurality of wells and the GOSP; generating a digital twin of the plurality of wells and the pipeline network using a control system that is communicatively coupled to the plurality of water cut meters and the plurality of temperature sensors; and determining, using the control system, a virtual flow rate of at least one fluid phase of each of the plurality of multiphase well fluids from the corresponding plurality of wells using the generated digital twin, the plurality of measured water cut percentages, and the plurality of measured temperatures.

[0013] In aspects that may be combined with example embodiments, generating a digital twin of the plurality of wells and the pipeline network includes generating, using a control system, a digital twin of the plurality of wells and the pipeline network based on at least one well parameter and at least one pipeline network parameter.

[0014] In another aspect that may be combined with any of the preceding aspects, at least one well parameter includes at least one of the following: completion throttling setting, reservoir pressure, production index or PVT data, and at least one pipeline network parameter includes at least one of pipeline diameter, pipeline length, pipeline pressure loss, or flow control device pressure loss data.

[0015] Another aspect that may be combined with any of the preceding aspects further includes measuring a flow rate of one of the plurality of fluid phases of the separation well fluid output from the GOSP by at least one flow meter mounted on the fluid output of the GOSP.

[0016] In another aspect which may be combined with any of the preceding aspects, measuring includes: measuring a first flow rate of gas output from the GOSP by a first flow meter; and measuring a second flow rate of oil output from the GOSP by a second flow meter.

[0017] In another aspect which may be combined with any of the preceding aspects, measuring further comprises measuring a third flow rate of water output from the GOSP by a third flow meter.

[0018] Another aspect that may be combined with any of the preceding aspects also includes: comparing, by a control system, a plurality of determined virtual flows with a mass or volumetric fluid flow from a GOSP, the mass or volumetric fluid flow comprising a measured gas flow from a first flow meter, a measured oil flow from a second flow meter, and a measured water flow from a third flow meter; and verifying, by a control system, the plurality of determined virtual flows based on the comparison.

[0019] Another aspect that may be combined with any of the preceding aspects also includes: based on the comparison, adjusting the generated digital twin through a control system.

[0020] In another example embodiment, a computer-implemented method includes: identifying, using one or more hardware processors of a control system, a measured water cut percentage of each of a plurality of multiphase well fluids from a corresponding plurality of wells using a plurality of water cut meters installed in a pipeline network between a plurality of wells and a gas and oil separation plant (GOSP); identifying, using one or more hardware processors, a measured temperature of each of a plurality of multiphase well fluids from a corresponding plurality of wells using a plurality of temperature sensors installed in a pipeline network between the plurality of wells and the GOSP; generating, using one or more hardware processors, a digital twin of the plurality of wells and the pipeline network; and determining, using the one or more hardware processors, a virtual flow rate of at least one fluid phase of each of the plurality of multiphase well fluids from the corresponding plurality of wells using the generated digital twin, the plurality of measured water cut percentages, and the plurality of measured temperatures.

[0021] In aspects that may be combined with the example embodiments, generating digital twins of the plurality of wells and the pipeline network comprises generating, by one or more hardware processors, digital twins of the plurality of wells and the pipeline network based on at least one well parameter and at least one pipeline network parameter.

[0022] In another aspect that may be combined with any of the preceding aspects, at least one well parameter includes at least one of the following: completion throttling setting, reservoir pressure, production index or PVT data, and at least one pipeline network parameter includes at least one of pipeline diameter, pipeline length, pipeline pressure loss, or flow control device pressure loss data.

[0023] Another aspect that may be combined with any of the preceding aspects also includes: using one or more hardware processors, using at least one flow meter mounted on the fluid output of the GOSP, identifying a measured flow rate of one of multiple fluid phases of the separation well fluid output from the GOSP.

[0024] In another aspect that may be combined with any of the preceding aspects, the identifying includes: using one or more hardware processors to identify a measured first flow rate of a gas phase of a separation well fluid output from the GOSP using a first flow meter; and using one or more hardware processors to identify a measured second flow rate of an oil phase of the separation well fluid output from the GOSP using a second flow meter.

[0025] In another aspect that may be combined with any of the preceding aspects, identifying further comprises: identifying, using one or more hardware processors, a measured third flow rate of an aqueous phase of the separation well fluid output from the GOSP using a third flow meter.

[0026] Another aspect that may be combined with any of the preceding aspects also includes: using one or more hardware processors to compare multiple determined virtual flow rates with a mass or volume fluid flow from the GOSP, the mass or volume fluid flow including a measured gas flow rate from a first flow meter, a measured oil flow rate from a second flow meter, and a measured water flow rate from a third flow meter; and using one or more hardware processors to verify the multiple determined virtual flow rates based on the comparison.

[0027] Another aspect that may be combined with any of the preceding aspects also includes: based on the comparison, adjusting the generated digital twin using one or more hardware processors.

[0028] Implementations of systems and methods for measuring multiphase flow from wells according to the present disclosure may include one or more of the following features. For example, systems and methods for measuring multiphase flow from wells according to the present disclosure may provide real-time multiphase flow measurements, which can be used to optimize reservoir production / injection strategies and manage water production in a timely manner. As another example, systems and methods for measuring multiphase flow from wells according to the present disclosure may include or provide techniques for facilitating continuous multiphase flow measurements using more cost-effective measurement equipment, digital twins, and data analysis. As another example, systems and methods for measuring multiphase flow from wells according to the present disclosure may generate a virtual model that uses actual wellhead water cut and temperature measurements and hydraulic simulations to calculate the rates of different wells connected to a single production network.

[0029] The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, drawings, and claims. BRIEF DESCRIPTION OF THE DRAWINGS

[0030] Figure 1 is a schematic diagram of an example implementation of a multiphase well fluid testing system according to the present disclosure.

[0031] Figure 2A is a schematic diagram of an example implementation of a well fluid production network including a plurality of wells connected to an oil and gas separation plant according to the present disclosure.

[0032] Figure 2B is a schematic diagram of an example embodiment of a portion of a well fluid production network including wells connected to a test line and a trunk line to flow wellbore fluids to an oil and gas separation plant according to the present disclosure.

[0033] Figure 3 is a schematic diagram of a workflow for determining multiphase well fluid flow using a digital twin of a well fluid production network in accordance with the present disclosure.

[0034] Figure 4 is a schematic diagram of an example control system according to the present disclosure. DETAILED DESCRIPTION

[0035] The present disclosure describes example embodiments of a multiphase well fluid testing system that can be operated to accurately and efficiently determine the flow rates (and in some aspects, other parameters) of separated phases of a multiphase fluid produced from a well (which may be a well of many wells all connected to an oil and gas separation plant or GOSP). In some aspects, the testing system generates and uses a digital twin of a well fluid production network (in other words, one or more wells and a pipeline network connecting the one or more wells to the GOSP). For example, in some aspects, a multiphase well fluid testing system can include and use a digital twin and online well water cut and temperature measurement equipment to determine individual phase-by-phase fluid flow rates (e.g., for oil, gas, and water in a multiphase flow), and verify the determined flow rates and reconcile them with further well fluid measurements made at the GOSP. In some aspects, the well fluid flow rates can be determined and verified in real time, such as when the multiphase fluid is flowing from one or more wells to the GOSP for processing and separation.

[0036] Figure 1 is a schematic diagram of an example implementation of a multiphase well fluid testing system 100 according to the present disclosure. In this example, the multiphase well fluid testing system 100 includes wells 102 (five are shown, but fewer or greater numbers of wells are also contemplated) connected to a GOSP 112 via a piping network 110. Typically, the piping network 110 includes a plurality of pipe or conduit sections, valves and other flow control devices, and measurement devices (not all of which are shown) that are connected to carry a multiphase well fluid flow from the wells 102 to the GOSP 112. Typically, the GOSP 112 operates to separate the phases of the multiphase well fluid into constituent phases, such as gas, oil, and water (fresh water or brine).

[0037] As shown in this example, each well 102 includes a production well on the surface 104 (ground or water) for producing multiphase well fluid 108 from a subsurface hydrocarbon reservoir 106. In some aspects, a piping network 110 is connected to the wellhead of each well 102 to circulate the multiphase well fluid 108 from the well 102 into the piping network 110 and to the GOSP 112. The GOSP 112 operates to separate and output a gas output stream 122, a crude oil output stream 124, and a water output stream 126.

[0038] Briefly turn to Figure 2A, which shows a schematic diagram of an example implementation of a well fluid production network 200 that includes a plurality of wells 102 connected to a GOSP 112. For example, in a typical fluid production network 200, there may be a plurality of production sites 202 (one of many is referenced). Each production site 202 may include at least one (but typically several) wells 102. Within each production site 202, the wells 102 are connected to a pipeline network 110 and thus to a GOSP 112.

[0039] Steering Figure 2B , which is a schematic diagram of an example embodiment of a portion of a well fluid production network 200 that includes a well 102 connected by a flow line 250 to a conventional test line 252 and a conventional trunk line 254 for flowing wellbore fluids to a GOSP 112. In conventional testing systems and processes, the test line 252 is necessary for the conventional testing system to (in some cases inaccurately) estimate the individual flow rates of oil, gas, and water. For example, to test a well at a GOSP, the process typically involves the following steps: 1. draining the test line 252 (e.g., operating one or more flow control devices to direct fluid flow) to the production header at GOSP 112; 2. lining up the well 102 to the test line 252; 3. flowing the well 102 for 2 to 6 hours to flush the test line 252 (e.g., depending on the length of the test line 252 to GOSP 112); 4. lining up the test line 252 to the test header of GOSP 112; and using the HPPT or MPFM to test the well for 8 hours. The process is laborious and requires frequent opening and closing of manual valves. In addition, typically no more than three wells can be tested in a single day. Some wells are retested if further adjustments to the choke settings are needed. Wells are typically tested once a month, but it can be longer, depending on the progress of the testing plan for the wells on the production priority list.

[0040] However, in an example embodiment of the present disclosure, the multiphase well fluid testing system 100 integrates specific measurement equipment with the digital twin to continuously measure the multiphase flow from the well 102 while eliminating the need for the test line 252. Figure 1 , the multiphase well fluid testing system 100 includes a water cut meter 114 and a temperature sensor 116 installed in a piping network 110 (e.g., flow line 250) between each well 102 and a GOSP 112. Thus, in this example, to measure the multiphase flow of each well 102, the ratio of wells 102 to meters 112 and sensors 116 may be 1:1. In some aspects, the water cut meter 112 may be an Aquafield water cut meter from Hammertech AS.

[0041] As shown, each water cut meter 114 is communicatively coupled (or otherwise makes measurement data available) to a control system 999 as part of the multiphase well fluid testing system 100 via a data connection 118 (wired or wireless) to provide real-time measurements to the control system 999. Alternatively, the measurements made by the water cut meter 114 (in other words, the measurement of the water percentage of the multiphase well fluid 108) can be saved and later retrieved or provided to the control system 999. Similarly, each temperature sensor 116 is communicatively coupled (or otherwise makes measurement data available) to the control system 999 via a data connection 120 (wired or wireless) to provide real-time measurements to the control system 999. Alternatively, the measurements made by the temperature sensor 116 (in other words, the measurement of the temperature of the multiphase well fluid 108) can be saved and later retrieved or provided to the control system 999.

[0042] In some aspects, the water cut meter 114 and the temperature sensor 116 may be deployed on a well 102 that, for example, includes a current fiber optic or very small aperture terminal (VSAT) connection back to the GOSP 112. For example, the water cut meter 114 and / or the temperature sensor 116 may be connected to an existing remote terminal unit (RTU) at each well 102, and the data may be available in a supervisory control and data acquisition (SCADA) system and a primary plant information (PI) system of the GOSP 112. Alternatively, the water cut meter 114 and the temperature sensor 116 may be deployed on a well 102 that, for example, does not include a current fiber optic or VSAT connection.

[0043] like Figure 1As further shown, the multiphase well fluid testing system 100 includes: a gas flow meter 128a, installed on the gas output stream 122 to measure the gas flow rate; an oil flow meter 128b, installed on the oil output stream 124 to measure the oil flow rate; and a water flow meter 128c, installed on the water output stream 126 to measure the water flow rate. The flow meters 128a-128c are communicatively coupled (or otherwise have measurement data available) to the control system 999 via a data connection 130 (wired or wireless) to provide real-time measurements from these flow meters 128a-128c to the control system 999. Alternatively, the measurements made by the flow meters 128a-128c can be saved and later retrieved by or provided to the control system 999. In some aspects, the multiphase well fluid testing system 100 may include only two of the three flow meters 128a-128c (and the flow rate of the fluid phase on the output excluding the flow meter may be determined, for example, by mass or volumetric flow rate balance and other data from GOSP 112). In some aspects, the multiphase well fluid testing system 100 may include only one of the three flow meters 128a-128c (and the flow rate of the fluid phase on the output excluding the flow meter may be determined, for example, by mass or volumetric flow rate balance and other data from GOSP 112).

[0044] The control system 999 includes a microprocessor-based computing system (in an example embodiment) that includes a processing device 990, a graphical user interface 992 for displaying virtual or digital data, and a data storage device 994 (e.g., a non-transitory computer-readable medium storing computer-executable instructions and data). The data storage device 994 can store one or more digital twins 136 of the well 102 and the pipeline network 110, well and pipeline data 132, virtual fluid phase flow 134, and verified flow rate 138. In some aspects, the well and pipeline data 132 can include, for example, completion choke settings, reservoir pressure, productivity index and PVT data and other well data. In some aspects, the well and pipeline data 132 can also include pipeline diameter, pipeline length, pipeline pressure loss (total length or per length), flow control device pressure loss data and other data. In some aspects, the well and pipeline data 132 can include actual operating conditions of the production system (in other words, the well 102 and the pipeline network 110).

[0045] In this example embodiment, the processing device 990 generates one or more digital twins 136 based at least in part on the well and pipeline data 132. Measured water cut data and temperature data from corresponding water cut meters 114 and temperature sensors 116 (where such water cut data and temperature data may or may not be stored in the data storage device 994) can be applied to the digital twin 136 to generate a virtual flow rate 134 for each phase of the multiphase well fluid 108 for each well 102. In some aspects, the control system 999 can generate the digital twin 136 using, for example, steady-state multiphase simulation software (e.g., PIPESIM, GAP / Prosper, or other digital twin software packages).

[0046] In an example operation of the multiphase well fluid testing system 100, a multiphase well fluid 108 is produced from one, some, or all of the wells 102 into the piping network 110. As the produced multiphase well fluid 108 circulates through the piping network 110 (e.g., through the corresponding flow lines 250 and into the trunk line 254), a water cut meter 114 installed, for example, in each flow line 250 measures the percentage of water in the multiphase well fluid 108 from each well 102. The measured water percentage for each well 102 is provided to the control system 999 (via the data connection 118). In addition, as the produced multiphase well fluid 108 circulates through the piping network 110 (e.g., through the corresponding flow lines 250 and into the trunk line 254), a temperature sensor 116 installed, for example, in each flow line 250 measures the temperature of the multiphase well fluid 108 from each well 102. The measured temperature for each well 102 is provided to the control system 999 (via the data connection 120).

[0047] The example operation also includes generating a digital twin 136 of the well 102 and the pipeline network 110 using the well and pipeline data 132 by using steady-state multiphase simulation software executed by the control system 999. The digital twin 136 is a virtual representation (eg, a computer-generated virtual model) of the well 102 and the pipeline network 110.

[0048] Next, in an example operation, the control system 999 applies the measured water percentage in the multiphase well fluid 108 of each well 102 and the measured temperature of the multiphase well fluid 108 of each well 102 to the generated digital twin 136. Based on the generated digital twin and the measured water cut percentage and temperature of the multiphase well fluid 108 from each well 102, the control system 999 determines a separate, virtual flow rate for each phase of the multiphase well fluid 108 of each well 102, namely a virtual gas flow rate, a virtual oil flow rate, and a virtual water flow rate. The virtual flow rates determined by the control system 999 can be stored as virtual flow rates 134 for each phase of the multiphase well fluid 108 of each well 102.

[0049] For example, in this operation step, the calibrated steady-state multiphase simulation model can accurately simulate the pressure, temperature, and flow distribution of each component (e.g., well 102, manifold, or trunk) of the pipeline network 110. The measured temperature (from the temperature sensor 114) can be used to determine the operating state of the corresponding well 102. The real-time water cut measurement results from the water cut meter 112 can be input into the digital twin 136 to identify changes in water cut in a timely manner (e.g., real time).

[0050] In example operation, the individual flow rates of the separate gas output stream 122, oil output stream 124, and water output stream 126 from the GOSP 112 are measured by respective flow meters 128a to 128c. In some aspects, each of the respective flow meters 128a to 128c can be a single-phase flow meter, each single-phase flow meter being selected for the particular output flow line on which it is installed. The measured gas output stream 122, oil output stream 124, and water output stream 126 are provided to the control system 999 via the data connection 130.

[0051] In an example operation, the control system 999 may verify or reconcile the virtual flow rate 134 with the measured gas output flow 122, oil output flow 124, and water output flow 126. For example, the control system 999 may compare the facility output of the GOSP 112 (in other words, the gas output flow 122, oil output flow 124, and water output flow (e.g., in real time or over 1 or more days of operation)) with the sum of the individual virtual flow rates 134 of gas, oil, and water provided to the GOSP 112 via the pipeline network 110. In some aspects, the control system 999 may calculate a mass flow balance (e.g., the mass or volume flow rate entering the GOSP 112 and the mass or volume flow rate leaving the GOSP 112), and the control system 999 may then adjust the virtual flow rate 134 and / or the digital twin 136 based on the difference in the mass or volume flow balance. In the case of an adjusted digital twin 136, the new digital twin 136 may then be used to determine a new virtual flow rate 134. For example, mass flow balances can be calculated and the digital twin 136 can be tuned via advanced equation-based data validation and coordination packages (e.g., BELSIM’s VALI).

[0052] Figure 3 is a schematic diagram of a workflow 300 for determining multiphase well fluid flow using a digital twin of a well fluid production network according to the present disclosure. In some aspects, for example, the workflow 300 can be performed by or through Figure 1102. The workflow 300 may be implemented by the control system 999 of the multiphase well fluid testing system 100 in FIG. 104. The workflow 300 may begin at 302, which includes acquiring, receiving, and / or identifying field measurements 304 of water cut percentage and temperature of the multiphase well fluid 108 produced from the well 102. The field measurements 304 are provided to step 306 of the workflow 300, which includes implementing the digital twin 136 generated from the well and pipeline data 132. Implementing the digital twin 136 using the field measurements 304 produces a simulated (per well 102) phase flow rate 310 of oil, gas, and water in each multiphase well fluid 108. In series or in parallel with implementing step 306, field measurements 308 of separate output streams (in other words, separate gas, oil, and water streams) from the GOSP 112 are acquired, received, or identified. The measured or aggregated flow 312 from the GOSP 112 is provided to step 314, which includes validating the virtual flow rate 134 against the measured or aggregated flow rate 312 from the GOSP 112. The effective virtual flow rate 316 is output from the control system 999, such as to the user interface 992. In some aspects, the validated virtual flow rate 316 can be used in step 306 to generate or adjust the digital twin 136.

[0053] Figure 4 is an example controller 400 (or control system) (e.g., Figure 1 400). For example, all or part of the controller 400 can be used for some or all of the operations previously described. The controller 400 is intended to include various forms of digital computers, such as printed circuit boards (PCBs), processors, digital circuits, etc. In addition, the system may include portable storage media, such as a universal serial bus (USB) flash drive. For example, a USB flash drive can store an operating system and other applications. The USB flash drive may include input / output components, such as a wireless transmitter or a USB connector that can be plugged into a USB port of another computing device.

[0054] The controller 400 includes a processor 410, a memory 420, a storage device 430, and an input / output device 440. Each of the components 410, 420, 430, and 440 is interconnected using a system bus 450. The processor 410 is capable of processing instructions for execution within the controller 400. The processor can be designed using any of a variety of architectures. For example, the processor 410 can be a CISC (Complex Instruction Set Computer) processor, a RISC (Reduced Instruction Set Computer) processor, or a MISC (Minimum Instruction Set Computer) processor.

[0055] In one embodiment, the processor 410 is a single-threaded processor. In another embodiment, the processor 410 is a multi-threaded processor. The processor 410 is capable of processing instructions stored in the memory 420 or on the storage device 430 to display graphical information of the user interface on the input / output device 440.

[0056] The memory 420 stores information within the controller 400. In one embodiment, the memory 420 is a computer readable medium. In one embodiment, the memory 420 is a volatile memory unit. In another embodiment, the memory 420 is a non-volatile memory unit.

[0057] The storage device 430 can provide mass storage for the controller 400. In one embodiment, the storage device 430 is a computer-readable medium. In various embodiments, the storage device 430 can be a floppy disk device, a hard disk device, an optical disk device, a tape device, a flash memory, a solid-state device (SSD), or a combination thereof.

[0058] The input / output device 440 provides input / output operations for the controller 400. In one embodiment, the input / output device 440 includes a keyboard and / or a pointing device. In another embodiment, the input / output device 440 includes a display unit for displaying a graphical user interface.

[0059] The features described may be implemented in digital electronic circuitry, or in computer hardware, firmware, software, or a combination thereof. The apparatus may be implemented in a computer program product tangibly embodied in an information carrier, for example, in a machine-readable storage device for execution by a programmable processor; and the method steps may be performed by a programmable processor executing a program of instructions to perform the functions of the described embodiments by operating on input data and generating output. The features described may be advantageously implemented by one or more computer programs executable on a programmable system, the programmable system comprising at least one programmable processor coupled to receive data and instructions from and to send data and instructions to a data storage system, at least one input device, and at least one output device. A computer program is a set of instructions that can be used directly or indirectly in a computer to perform a specific activity or produce a certain result. A computer program may be written in any form of programming language, including compiled or interpreted languages, and it may be deployed in any form, including as a stand-alone program or as a module, component, subroutine, or other unit suitable for use in a computing environment.

[0060] As examples, suitable processors for executing instruction programs include general and special purpose microprocessors and a single processor or one of multiple processors of any kind of computer. Typically, the processor will receive instructions and data from a read-only memory or a random access memory or both. The basic elements of a computer are a processor for executing instructions and one or more memories for storing instructions and data. Typically, a computer will also include one or more mass storage devices for storing data files or be operably coupled to communicate with one or more mass storage devices; such devices include magnetic disks, such as internal hard disks and removable disks; magneto-optical disks; and optical disks. Storage devices suitable for tangibly embodying computer program instructions and data include all forms of non-volatile memory, including, for example, semiconductor memory devices, such as EPROM, EEPROM, solid-state drives (SSD), and flash memory devices; magnetic disks, such as internal hard disks and removable disks; magneto-optical disks; and CD-ROM and DVD-ROM disks. The processor and memory may be supplemented by or incorporated into an ASIC (Application Specific Integrated Circuit).

[0061] To provide for interaction with a user, these features may be implemented on a computer having a display device, such as a CRT (cathode ray tube) or LCD (liquid crystal display) or LED (light emitting diode) monitor for displaying information to the user, and a keyboard and pointing device, such as a mouse or trackball through which the user can provide input to the computer. Additionally, such activity may be implemented via a touch screen flat panel display and other appropriate mechanisms.

[0062] These features can be implemented in a control system that includes a back-end component (e.g., a data server), or in a control system that includes a middleware component (e.g., an application server or an Internet server), or in a computer system that includes a front-end component (e.g., a client computer with a graphical user interface or an Internet browser), or any combination thereof. The components of the system can be connected by any form or medium of digital data communication, such as a communication network. Examples of communication networks include a local area network ("LAN"), a wide area network ("WAN"), a peer-to-peer network (with self-organizing or static members), a grid computing infrastructure, and the Internet.

[0063] Although this specification contains many specific implementation details, these details should not be interpreted as limiting any scope of the invention or the scope of protection claimed, but should be interpreted as a description of the features of a specific embodiment dedicated to a specific invention. In a single embodiment, some features described in this specification in the context of a separate embodiment can also be implemented in combination. On the contrary, the various features described in the context of a single embodiment can also be implemented individually or in any suitable sub-combination in multiple embodiments. In addition, although features can be described above as working in some combinations and even initially claimed as such, one or more features from the claimed combination can be deleted from the combination in some cases, and the claimed combination can be for a variant of a sub-combination or a sub-combination.

[0064] Similarly, although operations are depicted in a particular order in the accompanying drawings, this should not be understood as requiring that the operations be performed in the particular order shown or in a sequential order, or that all of the operations shown be performed to achieve the desired results. In some cases, multitasking and parallel processing may be advantageous. In addition, the separation of various system components in the above-described embodiments should not be understood as requiring such separation in all embodiments, and it should be understood that the described program components and systems can generally be integrated into a single software product or packaged into multiple software products.

[0065] A number of embodiments have been described. However, it should be understood that various modifications may be made without departing from the spirit and scope of the present disclosure. For example, the example operations, methods, or processes described herein may include more steps or fewer steps than those described. In addition, the steps in such example operations, methods, or processes may be performed in an order different from that described or shown in the figures. Therefore, other embodiments are within the scope of the appended claims.

Claims

1. A multiphase well fluid system, comprising: a plurality of water cut meters configured to be installed in the pipeline network and to measure the water cut percentage of a corresponding plurality of multiphase well fluids entering the pipeline network from a corresponding plurality of wells to a gas and oil separation plant GOSP; a plurality of temperature sensors configured for installation in the piping network and for measuring temperatures of respective ones of the plurality of multiphase well fluid flows entering the piping network from respective ones of the plurality of wells to the GOSP; as well as A control system communicatively coupled to the plurality of moisture meters and the plurality of temperature sensors and configured to perform operations comprising: generating a digital twin of the plurality of wells and the pipeline network; as well as A virtual flow rate of at least one fluid phase of each of the plurality of multiphase well fluids from a corresponding plurality of wells is determined using the generated digital twin, the plurality of measured water cut percentages, and the plurality of measured temperatures.

2. The multiphase well fluid system according to claim 1, wherein: The operation of generating digital twins of the plurality of wells and the pipeline network includes generating digital twins of the plurality of wells and the pipeline network based on at least one well parameter and at least one pipeline network parameter.

3. The multiphase well fluid system according to claim 2, wherein: The at least one well parameter comprises at least one of the following: completion choke setting, reservoir pressure, production index, or PVT data; and The at least one pipeline network parameter includes at least one of the following: pipeline diameter, pipeline length, pipeline pressure loss, or flow control device pressure loss data.

4. The multiphase well fluid system of claim 1 , further comprising at least one flow meter configured to be mounted on the fluid output from the GOSP and to measure the flow rate of a fluid phase among the multiple fluid phases of the separation well fluid output from the GOSP.

5. The multiphase well fluid system according to claim 4, wherein: The at least one flow meter comprises: a first flow meter configured for installation on a gas output from the GOSP; and A second flow meter is configured for installation on the oil output from the GOSP.

6. The multiphase well fluid system according to claim 5, wherein: The at least one flow meter further comprises: A third flow meter is configured for installation on the water output from the GOSP.

7. The multiphase well fluid system according to claim 6, wherein: The operations also include: comparing a plurality of determined virtual flow rates to mass or volumetric fluid flow rates from the GOSP, the mass or volumetric fluid flow rates comprising a measured gas flow rate from the first flow meter, a measured oil flow rate from the second flow meter, and a measured water flow rate from the third flow meter; and The plurality of determined virtual flow rates are validated based on the comparison.

8. The multiphase well fluid system according to claim 7, wherein: The operations also include adjusting the generated digital twin based on the comparison.

9. A method comprising: measuring the water content percentage of each of the plurality of multiphase well fluids from the corresponding plurality of wells using a plurality of water cut meters installed in a pipeline network between the plurality of wells and a gas and oil separation plant GOSP; measuring the temperature of each of the plurality of multiphase well fluids from the corresponding plurality of wells using a plurality of temperature sensors installed in the piping network between the plurality of wells and the GOSP; generating a digital twin of the plurality of wells and the pipeline network using a control system, the control system communicatively coupled to the plurality of water cut meters and the plurality of temperature sensors; as well as Utilizing the control system, a virtual flow rate of at least one fluid phase of each of the plurality of multiphase well fluids from a corresponding plurality of wells is determined utilizing the generated digital twin, the plurality of measured water cut percentages, and the plurality of measured temperatures.

10. The method according to claim 9, wherein: Generating digital twins of the plurality of wells and the pipeline network includes generating digital twins of the plurality of wells and the pipeline network based on at least one well parameter and at least one pipeline network parameter using the control system.

11. The method according to claim 10, wherein: The at least one well parameter includes at least one of the following: completion choke setting, reservoir pressure, production index, or PVT data, and The at least one pipeline network parameter includes at least one of the following: pipeline diameter, pipeline length, pipeline pressure loss, or flow control device pressure loss data.

12. The method of claim 9, further comprising measuring a flow rate of a fluid phase among a plurality of fluid phases from a separation well fluid output of the GOSP using at least one flow meter mounted on the fluid output of the GOSP.

13. The method according to claim 12, wherein: Measurements include: measuring a first flow rate of a gas output from the GOSP using a first flow meter; as well as A second flow rate of oil output from the GOSP is measured using a second flow meter.

14. The method according to claim 13, wherein: Measuring also includes measuring a third flow rate of water output from the GOSP using a third flow meter.

15. The method according to claim 14, further comprising: comparing, with the control system, a plurality of determined virtual flow rates to mass or volumetric fluid flow rates from the GOSP, the mass or volumetric fluid flow rates comprising a measured gas flow rate from the first flow meter, a measured oil flow rate from the second flow meter, and a measured water flow rate from the third flow meter; and Using the control system, a plurality of determined virtual flow rates are verified based on the comparison.

16. The method according to claim 15, further comprising: Based on the comparison, the generated digital twin is adjusted using the control system.

17. A computer-implemented method comprising: identifying, using one or more hardware processors of the control system, a measured water cut percentage of each of a plurality of multiphase well fluids from a corresponding plurality of wells using a plurality of water cut meters installed in a pipeline network between the plurality of wells and the gas and oil separation plant (GOSP); identifying, with the one or more hardware processors, a measured temperature of each of the plurality of multiphase well fluids from a corresponding one of the plurality of wells using a plurality of temperature sensors installed in the piping network between the plurality of wells and the GOSP; generating, using the one or more hardware processors, a digital twin of the plurality of wells and the pipeline network; as well as Determine, using the one or more hardware processors, a virtual flow rate of at least one fluid phase for each of the plurality of multiphase well fluids from the corresponding plurality of wells using the generated digital twin, the plurality of measured water cut percentages, and the plurality of measured temperatures.

18. The computer-implemented method of claim 17, wherein: Generating digital twins of the plurality of wells and the pipeline network includes generating digital twins of the plurality of wells and the pipeline network based on at least one well parameter and at least one pipeline network parameter using the one or more hardware processors.

19. The computer-implemented method of claim 18, wherein: The at least one well parameter comprises at least one of the following: completion choke setting, reservoir pressure, production index, or PVT data; and The at least one pipeline network parameter includes at least one of the following: pipeline diameter, pipeline length, pipeline pressure loss, or flow control device pressure loss data.

20. The computer-implemented method of claim 17, further comprising: A measured flow rate of a fluid phase among a plurality of fluid phases from a separation well fluid output of the GOSP is identified using the one or more hardware processors using at least one flow meter mounted on the fluid output of the GOSP.

21. The computer-implemented method of claim 20, wherein: Identification includes: identifying, with the one or more hardware processors, a measured first flow rate of a gas phase of the separation well fluid output from the GOSP using a first flow meter; and A measured second flow rate of an oil phase of the separation well fluid output from the GOSP is identified using a second flow meter using the one or more hardware processors.

22. The computer-implemented method of claim 21, wherein: Identifying also includes identifying, utilizing the one or more hardware processors, a measured third flow rate of an aqueous phase of the separation well fluid output from the GOSP utilizing a third flow meter.

23. The computer-implemented method of claim 22, further comprising: comparing, with the one or more hardware processors, a plurality of determined virtual flow rates to mass or volumetric fluid flow rates from the GOSP, the mass or volumetric fluid flow rates comprising a measured gas flow rate from the first flow meter, a measured oil flow rate from the second flow meter, and a measured water flow rate from the third flow meter; and The plurality of determined virtual flow rates are validated based on the comparison, utilizing the one or more hardware processors.

24. The computer-implemented method of claim 23, further comprising: Based on the comparison, the generated digital twin is adjusted using the one or more hardware processors.

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