Method and system for controlling automated choke valves

Abstract

An exemplary method includes transporting, via a conduit, a multi-phase fluid stream to a fluid processing system including a vessel to separate the multi-phase fluid stream into its constitutive streams, a gas stream and at least one liquid stream. The method includes determining, via a first sensor located at the inlet of the at least one conduit, the flow rate of the multi-phase fluid stream flowing into the conduit. The method includes regulating, via an automated choke valve, the flow of the multi-phase fluid stream. The method includes determining, via a second sensor, a flow-rate of the multi-phase fluid passing through the automated choke valve. The method includes monitoring and processing the measurement signals from each of the first sensor and the second sensor. The method includes computing a set point based upon the measurement signals. The method includes passing the set point to the automated choke valve.

Description

METHOD AND SYSTEM FOR CONTROLLING AUTOMATED CHOKE VALVESCROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims priority to and the benefit of U.S. Provisional Application No. 63 / 679,857, entitled “METHOD AND SYSTEM FOR CONTROLLING AUTOMATED CHOKE VALVES," having a filing date of August 6, 2024, the disclosure of which is incorporated herein by reference in its entirety.FIELD

[0002] The present application relates generally to the field of hydrocarbon management. Specifically, the disclosure relates to a methodology for the management of slugs in conduits. BACKGROUND

[0003] This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

[0004] Exploration and production (E&P) companies operate multiphase production systems. For example, in the offshore oil and gas industry, exploration and production (E&P) companies operate multiphase production systems, which may include four primary connected sections: a production well section, a subsea gathering system, a vertical riser section, and a surface production facility. For example, the wellbore section allows fluid from the reservoir to be transported up to the wellhead. The subsea gathering system, is a pipeline network that is utilized to gather the produced fluids from the wellheads and transport them to one or more central locations to be subsequently transported to the surface. The vertical riser section, is a flexible pipeline that connects the gathering system on the seabed with the surface production facility. The surface production facility, separates the multiphase fluid into its constitutive components. For example, the surface production facility may typically be either a floating production storage and offloading (FPSO) vessel or onshore central production facility (CPF).

[0005] As another example, in onshore facilities, multiphase production systems may include two primary connected sections. For example, these sections may include a production well section and a production facility.SUMMARY OF THE INVENTION[0006J An embodiment provided herein relates to a system that includes a conduit to transport a multi-phase fluid stream to a fluid processing system. The system includes a first sensor to determine the flow rate of the multi-phase fluid flowing into the conduit. The system also includes an automated choke valve to regulate the flow of the multi-phase fluid stream. The system further includes a second sensor fluidically coupled to the automated choke valve on the conduit to determine the flow-rate of the multi-phase fluid passing through the automated choke valve into the corresponding conduit. The system also further includes a processor of a computer unit, wherein the processor is to monitor and process measurement signals from the sensors, and compute and pass a set point to the automated choke valve based upon the measurement signals.

[0007] Another embodiment provided herein relates to a method that includes transporting, via a conduit, a multi-phase fluid stream to a fluid processing system comprising a vessel to separate the multi-phase fluid stream into its constitutive streams, a gas stream and at least one liquid stream. The method includes determining, via a first sensor located at the inlet of the at least one conduit, the flow rate of the multi-phase fluid stream flowing into the conduit. The method also includes regulating, via an automated choke valve, the flow of the multi-phase fluid stream. The method further includes determining, via a second sensor, a flow-rate of the multiphase fluid passing through the automated choke valve. The method also further includes monitoring and processing the measurement signals from each of the first sensor and the second sensor. The method includes computing a set point based upon the measurement signals. The method further includes passing the set point to the automated choke valve.

[0008] These and other features and attributes of the disclosed embodiments of the present disclosure and their advantageous applications and / or uses will be apparent from the detailed description that follows.BRIEF DESCRIPTION OF THE DRAWINGS

[0009] The present application is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of exemplary implementations, in which like reference numerals represent similar parts throughout the several views of the drawings. In this regard, the appended drawings illustrate only exemplary implementations and are therefore not to be considered limiting of scope, for the disclosure mayadmit to other equally effective embodiments and applications.

[0010] FIG. 1 is a process flow diagram of an exemplary phases in riser-based slugging, that can be mitigated and managed in accordance with embodiments of the present disclosure;

[0011] FIG. 2 is a high level block diagram of an exemplary system that can adaptively adjust valves in conduits processing multi-phase fluid streams, in accordance with embodiments of the present disclosure;

[0012] FIG. 3 is a block diagram of an exemplary closed loop slug mitigation system that can adaptively adjust valves in conduits processing multi-phase fluid streams, in accordance with embodiments of the present disclosure;

[0013] FIG. 4 is a schematic diagram of an exemplary pipeline system that can be integrated with embodiments of the present disclosure;

[0014] FIG. 5A is a schematic diagram of an exemplary a pipeline system with an integrated containerized application including a feedforward and feedback control scheme, according to embodiments of the present disclosure;

[0015] FIG. 5B is a schematic diagram of an exemplary a pipeline system with an integrated containerized application including a feedback control scheme, according to embodiments of the present disclosure;

[0016] FIG. 6A is a schematic diagram of an exemplary system implementing a feedforward and feedback control scheme, according to embodiments of the present disclosure;

[0017] FIG. 6B is a schematic diagram of an exemplary system implementing a feedback control scheme, according to embodiments of the present disclosure;

[0018] FIG. 7 is a process flow diagram of an exemplary method for automatically computing set points for an automated choke valve in a conduit containing a multi-phase fluid stream, in accordance with the present disclosure;

[0019] FIG. 8 is a block diagram of an exemplary cluster computing system that may be utilized to implement embodiments of the present disclosure;

[0020] FIG. 9 is a block diagram of an example containerized application that may be utilized to implement embodiments of the present disclosure;

[0021] FIG. 10 is a block diagram of an exemplary non-transitory, computer-readable storage medium that may be used for the storage of data and modules of program instructions for implementing embodiments of the present disclosure; and

[0022] FIG. 11 is a set of graphs illustrating the performance of various virtual multi-phase flow meters.

[0023] It should be noted that the figures are merely examples of the present disclosure and are not intended to impose limitations on the scope of the present disclosure. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the present disclosure.DETAILED DESCRIPTION

[0024] The methods, devices, systems, and other features discussed below may be embodied in a number of different forms. Not all of the depicted components may be required, however, and some implementations may include additional, different, or fewer components from those expressly described in this disclosure. Variations in the arrangement and type of the components may be made without departing from the spirit or scope of the claims as set forth herein. Further, variations in the processes described, including the addition, deletion, or rearranging and order of logical operations, may be made without departing from the spirit or scope of the claims as set forth herein.

[0025] It is to be understood that the present disclosure is not limited to particular devices or methods, which may, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting. As used herein, the singular forms “a,” “an,” and “the” include singular and plural referents unless the content clearly dictates otherwise. Furthermore, the words “can” and “may” are used throughout this application in a permissive sense (i.e., having the potential to, being able to), not in a mandatory sense (i.e., must). The term “include,” and derivations thereof, mean “including, but not limited to.” The term “coupled” means directly or indirectly connected. The word “exemplary” is used herein to mean “serving as an example, instance, or illustration.” Any aspect described herein as “exemplary” is not necessarily to be construed as preferred or advantageous over other aspects. The term “uniform” means substantially equal for each subelement, within about ±10% variation.

[0026] The term “and / or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and / or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entitiesspecifically identified by the “and / or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and / or B,” when used in conjunction with open-ended language such as “including,” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.

[0027] As used herein, the term “any” means one, some, or all of a specified entity or group of entities, indiscriminately of the quantity.

[0028] The phrase “at least one,” when used in reference to a list of one or more entities (or elements), should be understood to mean at least one entity selected from any one or more of the entities in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities, and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently, “at least one of A and / or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and / or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B, and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C,” and “A, B, and / or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B, and C together, and optionally any of the above in combination with at least one other entity.

[0029] As used herein, artificial lift refers to any system that adds energy to the fluid column in a wellbore with the objective of initiating and improving production from the well. Artificiallift systems may use a range of operating principles, including rod pumping, gas lift, and electric submersible pumps.

[0030] As used herein, the phrase “based on” does not mean “based only on,” unless expressly specified otherwise. In other words, the phrase “based on” means “based only on,” “based at least on,” and / or “based at least in part on.”

[0031] As used herein, the term “battery” refers to installation of similar or identical units of equipment in a group, such as a separator battery, header battery, filter battery, or tank battery. The phrase “battery site” refers to a portion of land that contains separators, treaters, dehydrators, storage tanks, pumps, compressors, and other surface equipment in which fluids coming from a well are separated, measured, or stored.

[0032] As used herein, the term “choke” refers to a device incorporating an orifice that is used to control fluid flow rate or downstream system pressure. Chokes are available in several configurations for both fixed and adjustable modes of operation. Adjustable chokes enable the fluid flow and pressure parameters to be changed to suit process or production requirements.

[0033] As used herein, the term “conduit” refers to a length of pipe between a set of wells and a processing facility. For example, portions of a conduit may be referred to as a riser, or other terms. A production facility may have multiple conduits incoming from multiple sets of wells.

[0034] As used herein, the terms “example,” exemplary,” and “embodiment,” when used with reference to one or more components, features, structures, or methods according to the present disclosure, are intended to convey that the described component, feature, structure, or method is an illustrative, non-exclusive example of components, features, structures, or methods according to the present disclosure. Thus, the described component, feature, structure, or method is not intended to be limiting, required, or exclusive / exhaustive; and other components, features, structures, or methods, including structurally and / or functionally similar and / or equivalent components, features, structures, or methods, are also within the scope of the present disclosure.

[0035] The term “geophysical data” as used herein broadly includes seismic data, as well as other data obtained from non-seismic geophysical methods such as electrical resistivity. In this regard, examples of geophysical data include, but are not limited to, seismic data, gravity surveys, magnetic data, electromagnetic data, well logs, image logs, radar data, or temperature data.

[0036] As used herein, “hard measurements” refer to measurements from one or more sensors at an instrumentation device.

[0037] As used herein, “hydrocarbon management”, “managing hydrocarbons” or “hydrocarbon resource management” includes any one, any combination, or all of the following: hydrocarbon extraction; hydrocarbon production, (e.g., drilling a well and prospecting for, and / or producing, hydrocarbons using the well; and / or, causing a well to be drilled, e.g., to prospect for hydrocarbons); hydrocarbon exploration; identifying potential hydrocarbon-bearing formations; characterizing hydrocarbon-bearing formations; identifying well locations; determining well injection rates; determining well extraction rates; identifying reservoir connectivity; acquiring, disposing of, and / or abandoning hydrocarbon resources; reviewing prior hydrocarbon management decisions; and any other hydrocarbon-related acts or activities, such activities typically taking place with respect to a subsurface formation. The aforementioned broadly include not only the acts themselves (e.g., extraction, production, drilling a well, etc.), but also or instead the direction and / or causation of such acts (e.g., causing hydrocarbons to be extracted, causing hydrocarbons to be produced, causing a well to be drilled, causing the prospecting of hydrocarbons, etc.). Hydrocarbon management may include reservoir surveillance and / or geophysical optimization. For example, reservoir surveillance data may include, well production rates (how much water, oil, or gas is extracted over time), well injection rates (how much water or CO2 is injected over time), well pressure history, and time-lapse geophysical data. As another example, geophysical optimization may include a variety of methods geared to find an optimum model (and / or a series of models which orbit the optimum model) that is consistent with observed / measured geophysical data and geologic experience, process, and / or observation.

[0038] As used herein, “obtaining” data generally refers to any method or combination of methods of acquiring, collecting, or accessing data, including, for example, directly measuring or sensing a physical property, receiving transmitted data, selecting data from a group of physical sensors, identifying data in a data record, and retrieving data from one or more data libraries.

[0039] Generally speaking, the term “pressure” refers to a force acting on a unit area. Pressure is typically provided in units of pounds per square inch (psi).

[0040] As used herein, slugging refers to a multi-phase flow intermittency.

[0041] As used herein, “soft measurements” refers to predicted or estimated measurements that utilize one or more models. For example, a virtual flow meter may make soft measurementsof a particular flow rate based on other data received at the virtual flow meter. As one example, a virtual multiphase flow meter can estimate mass flow rates of a gas stream and liquid stream based on an input flow rate of a fluid that is later separated.

[0042] The term “substantially,” when used in reference to a quantity or amount of a material, or a specific characteristic thereof, refers to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may depend, in some cases, on the specific context.

[0043] As used herein, “water injection rate” refers to the rate of water injected into the reservoir to pressurize and displace hydrocarbons to producing wells.

[0044] As used herein, “workover” refers to the repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

[0045] If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted for the purposes of understanding this disclosure.Overview

[0046] As discussed above, E&P companies operate various different multiphase production systems to retrieve hydrocarbons. One challenge associated with operating multiphase production systems is the mitigation of severe slugging that can transpire various sections. In some examples, as in the example of offshore production systems, slugging can occur in a vertical riser section. For example, there are a multitude of negative consequences that can occur due to severe slugging in a riser, including: (i) liquid flooding of the topside separator / s; (ii) operating gas compressors at pressures and flow rates they were not designed for; (iii) potential loss of primary containment due to fatigue of the system induced by vibrations generated from oscillating pressure swings; (iv) increased erosion generated by rapid changes in pressure, flow rate, and gas liquid ratios; (v) low production caused by the inhibition of gas assisted lift; and (vi) production slop that occurs when the excess oil and / or gas is flared.

[0047] To mitigate the effects of riser based severe slugging, E&P’s either employ passive or active mitigation techniques. In passive based approaches, the effects of severe slugging are reduced by physically changing the pipeline system and can be broadly categorized by: (i)methods that reduce the flow line diameter; (ii) methods that alter shape of the flow line near the base of the riser; and (iii) methods that utilize multiple risers; or (iv) a combination of these methods.

[0048] In active based approaches, the frequency and severity of slugs is reduced by modulating an automated choke valve that is typically located at the inlet of the surface production facility. The desired openness of the automated choke valve is governed by a control system that receives information from measurement devices located on the flow line system. The measurement devices can be located at the base of the riser, upstream of the choke valve, and / or downstream of the choke valve.

[0049] There are various types of instrumentation devices utilized in active based methods. Depending on the type of the measurement, devices can measure: mass flow rate, volumetric flow rate, density, pressure, temperature, tank level, temperature, or some combination thereof. The advantages and disadvantages of each measurement device is contingent on the type of control method employed as well as where the measurement device is located within the flow line system and the underlying technology it employs. For example, a sole pressure measurement device located directly upstream of the topside choke valve may cost less to install and maintain than a coriolis flow meter that is located on the seabed directly upstream of the riser. However, the coriolis flow meter will provide the mass flow rate, density, temperature, and volumetric flow rate of the fluid entering the riser, which in turn can be utilized to establish a stable feedforward control scheme as opposed to a potentially unstable feedback control scheme based upon sole pressure measurement.

[0050] To reduce capital costs, operational costs, and maintenance requirements E&P companies may typically employ active based methods with control variables that are from or derived from pressure measurements. For example, some methods modulate an automated choke valve based upon the change in differential pressure with respective to time across the choke valve. Other methods utilize a cascade control scheme, whose principle control variable is the pressure directly upstream of the automated choke valve. Various E&P companies have also designed and implemented their own in house active based methods for slug mitigation.

[0051] However, some of the drawbacks of the aforementioned active based methods are that they rely upon feedback proportional-integral-derivative (PID) controllers, and that their virtual flow meters have to be re-calibrated manually. This is problematic for a multitude of reasons.For example, manual tuning of the virtual flow meters requires a skilled operator or engineer. In addition, depending on the dynamics of the system, the virtual flow meters may experience measurement drift, which in turn exacerbates plant-model mismatch. Moreover, feedback PID controllers cannot anticipate gas surges or liquid slugs. The result may be flooding, caused by rupture or loss of containment at the surface when the liquid slug reaches the processing plant. For example, flooding can occur in the separators when the slug reaches the FPSO or processing facility. Specifically, flooding occurs when a liquid is overfilled in a vessel.

[0052] The present disclosure includes an active based method that utilizes a controller and virtual multiphase mass flow meters that can be re-calibrated automatically by utilizing mass flow measurements taken downstream after successful separation of the gas and liquid streams. In various examples, the controller is a flow controller, which may be a feedback or integrated feedforward and feedback control scheme, depending on the layout. The virtual multiphase mass flow meters can estimate flow at particular points of conduits based on pressure, temperature, density, or any combination thereof. The present disclosure thus provides methods to measure and control gas surges and liquid slugs in a multiphase pipeline system using actuation from an automated choke valve. The openness of the automated choke valve is governed by a controller, which receives hard measurements from instrumentation devices, and soft measurements from virtual multiphase flow meters. The virtual multiphase flow meters can be re-calibrated using downstream measurements taken after the successful separation of the multiphase stream. In some examples, the controller, virtual multiphase flow meters, and procedure to re-calibrate the virtual multiphase flow meters are housed in a containerized application, which can be installed and operated in a control system with container hosting functionality or through serverless architectures. As one example, a method is provided to identify, quantify, and minimize the frequency and severity of gas surges and liquid slugs in a multiphase pipeline system using adaptive flow control and virtual multiphase flow meters. The virtual multiphase flow meters are able to quantify the mass flow rates of the gas stream and the liquid stream in the fluid and can be re-calibrated utilizing measurement information gathered downstream after successful separation of the streams. The controller manipulates an automated choke valve to adjust the back pressure on the system. The controller, virtual multiphase flow meters, and the algorithm to tune the virtual multiphase flow meters are housed in a containerized application. For example,the application can be installed and operated through serverless architectures or a control system with container hosting functionality.

[0053] The present disclosure may derive one or more benefits. For example, the disclosure enables the suppression of the formation of liquid slugs using an active based approach to slug and surge management. In this regard, the disclosure thus further enables more stable and efficient operation of hydrocarbon processing.

[0054] FIG. l is a schematic view of an exemplary cycle 100 of different phases in riserbased slugging, that can be mitigated and managed in accordance with the present disclosure. The exemplary cycle 100 starts at block 101A, where an initial blockage 102 is created by complete liquid holdup at the base of the riser. This blockage prevents gas from flowing into the riser, and thereby debilitates gas assisted flow in the riser.

[0055] Almost immediately after the initial blockage occurs, a second slug growth phase begins at block 101B, in which the liquid holdup begins to extend vertically 104 up the riser, and horizontally 106 along the flow line that lays on the seabed.

[0056] Once the slug reaches the top of the riser, at block 101C, a third phase is set in motion and total liquid production 108 begins. At this stage, the slug can still be growing horizontally along the seabed or the slug can begin to be pushed horizontally 110 along the flow line to the base of the riser.

[0057] At block 101D, after the slug has been pushed up the base of the riser, a fourth phase is initiated and fast liquid production 112 begins.

[0058] At block 101E, once the slug has been pushed through the riser, a fifth phase commences with gas blow down 114. In various examples, the gas surge continues until the cycle restarts with complete liquid holdup or blockage 102 at the base of the riser, and the cycle 100 thus repeats at block 101A.Adaptive Slug Mitigation and Management Methods and Systems

[0059] FIG. 2 is a high level block diagram of an exemplary system 200 that can adaptively adjust valves in conduits processing multi-phase fluid streams. The system 200 includes a set of sensors 201 providing a set of measurement signals 202 to a computer program 204. The system 200 further includes a set of automated valves 206. For example, the measurement signals 202 may include hard measurements and soft measurements. In various embodiments, the hard measurements may include pressure measurements and temperature measurements, the stemposition of the choke control valve, as well as flow measurements. In various embodiments, the soft measurements may include estimated or predicted measurements for one or more individual phase components of a stream from a virtual multiphase flow meter. In some embodiments, a virtual flow meter associated with each conduit may calculate soft measurements for that conduit.

[0060] In various embodiments, the computer program 204 is a containerized application running on any suitable platform. For example, the containerized application may be implemented using serverless architectures or a control system with container hosting functionality. In various embodiments, the computer program 204 includes a controller. For example, the controller may be a flow controller that can either utilize a feedback control scheme or an integrated feedforward and feedback control scheme. In a feedback control scheme, a single virtual multiphase flow meter is utilized. In the integrated feedforward and feedback control scheme, dual virtual multiphase flow meters are utilized. The set of virtual multiphase flow meters can be re-calibrated utilizing using downstream measurements taken after successful separation of the multiphase stream. In some embodiments, the controller, set of virtual multiphase flow meters, and procedure to re-calibrate the set of virtual multiphase flow meters are housed in a containerized application. This application can be installed and operated in a control system with container hosting functionality or through serverless architectures.

[0061] FIG. 3 is a block diagram of an exemplary closed loop slug mitigation system 300 that can adaptively adjust valves in conduits processing multi-phase fluid streams. The example closed loop slug mitigation system 300 includes an automation system 302 communicatively coupled to received input from system models 304. The system 300 includes actuators 306 communicatively coupled to the automation system 302 to receive generated set points. For example, in some embodiments, the actuators 306 are automated choke valves. The system 300 also further includes a process 308 coupled to receive output from the actuators 306.

[0062] In various embodiments, the system 300 receives an Xref input 310 at automation system 302 and generates output y 312 from process 308. For example, the Xref input 310 may include any combination of measurement signals, including sure measurements, temperature measurements, stem position of the choke valves etc. In various embodiments, the output y 312 is the desired set point of the automated choke valves or any other instrument to be controlled. The automation system 302 includes a controller 314, a smart logic 316, and an operatorinterface 318. In various embodiments, the controller 314 includes a controller based on model predictive control (MPC). In some embodiments, the controller 314 may be a Multi-Input, Multi-Output (MIMO) type control system that uses a linear quadratic regulator (LQR), among other suitable types of model based control methods. The smart logic 316 includes logic to automatically adjust set points for various actuators 306 based on input values from any combination of models. The operator interface 318 includes a user interface that provides information such as flow rates of different phases of liquids for each of any number of conduits between a series of wells and a production plant. The operator interface 318 also includes information about detected potential slugs and their mitigation and management, such as decreased levels in a separator or reduced set points at automated choke valves.

[0063] In various embodiments, the system models 304 include predictive models 320, realtime models 322, and diagnostic models 324. The predictive models 320 include models trained to identify slugs in gathering systems and risers. In some embodiments, the predictive models 320 are machine learning models that are trained to identify the slugs before the slugs reach a facility. For example, the machine learning models may be trained to detect slug events in a gathering system or any point in a conduit. In various embodiments, each conduit of a system including multiple conduits may have a dedicated machine learning model for detecting slug events that may indicate formation of slugs in the conduits. The real-time models 322 detect slugs downstream of automated shutdown valves on the FPSO. For example, the real-time models 322 can include virtual multiphase flow meters. The diagnostic models 324 describe the effect of slugs on the topside processing equipment. For example, the diagnostic models 324 may be used by the smart logic 316 to automatically reduce the level set point in a separator, or increase a flow rate coming out of separator. In various embodiments, the diagnostic models 324 may use physics based equations to calculate set points.

[0064] In this manner, the system 300 can be used to mitigate slugging. For example, the system 300 can manage potential slugs to ensure that a production facility can continue to operate and not have to completely shut down to address major slugging. In some examples, the closed loop system 300 can be used during startup and ramp up to ensure that slugs formed during startup only result in the closure of one conduit rather than the entire production facility.

[0065] FIG. 4 is a schematic diagram of an exemplary pipeline system 400 that can be integrated with embodiments of the present disclosure. In the example of FIG. 4, the pipelinesystem 400 is a flow line and riser system that has a single point of entry 402 on the seabed, which is connected to the effluent end of a gathering system. Once the fluid passes through the point of entry 402, the fluid then travels through the riser, which is a long vertical flow line, before the flow reaches a FPSO or CPF. In various examples, the FPSO or CPF includes one or more vessels. Each of the vessels may include sensors such as pressure sensors or level sensors indicating the used capacity of the vessel. As soon as the fluid reaches the FPSO or CPF, the flow passes through an automated choke valve and then is subsequently separated into its constitutive streams, gas and liquid. Thus, the pipeline system 400 may run from the inlet on a seabed to the outlet streams on a first separator on a FPSO or CPF. In the example of FIG. 4, the multiphase fluid that is produced by the well / s enter the pipeline system at point of entry 402. The fluid travels in a horizontal section of pipe along the seabed 404 until the fluid reaches the riser 406. Once the fluid enters the riser 406, the fluid travels vertically up from the seabed to the FPSO or CPF. After the fluid reaches the production facility, the fluid travels through another section 408 of a pipe before the fluid reaches an automated choke valve 410, which controls the back pressure applied on the pipeline system upstream of the choke valve based upon a set point provided by a controller 412. In various examples, any suitable type of controller may be utilized.

[0066] Once the fluid passes through the choke valve, the fluid travels through an additional section 414 of pipe, before the fluid enters a separator 416. For example, the separator 416 may be part of a FPSO or CPF. In various examples, the separator is a two-phase or three-phase separator. In the case of a two-phase separator, the multiphase fluid is separated into two streams: one stream containing gas 418, and one containing liquids 420. For example, the liquids 420 can include oil and produced water. In this manner, a two-phase separator may function as a slug catcher. In the case of a three-phase separator, the multiphase fluid is separated into three streams: one containing gas 418, one containing production water (not shown), and one containing oil (not shown). In this case, the liquids can be digitally commingled back into a multi-component liquid fluid 420.Exemplary Systems Implementing Embodiments of the Present Disclosure

[0067] FIG. 5A is a schematic diagram of an exemplary a pipeline system 500A with an integrated containerized application including a feedforward and feedback control scheme, according to embodiments of the present disclosure. FIG. 5A illustrates one embodiment inwhich the containerized application housing the adaptive control system is integrated with a pipeline system, such as the pipeline system 400 of FIG. 4. FIG. 5A includes similarly referenced elements of FIG. 4. For example, FIG. 5A includes a point of entry 402, an automated choke valve 410 to control flow of the point of entry 402, and a separator 416 that produces gas 418 and liquids 420. The system 500A of FIG. 5A further includes various instrumentation, including measurement devices 502, 504, 506 that are communicatively coupled to an application 508, as indicated by dashed arrows. In various embodiments, the application 508 is containerized, built in the control system, or hosted on edge servers, or any combination thereof. The system 500A also further includes measurement devices 510, 512, 514, and 516 that are also communicatively coupled to the application 508, also similarly indicated using dashed arrows. In various embodiments, the measurement devices 502, 504, 506, 510, 512, 514, and 516 can include any combination of pressure transducers, flow meters, thermometers, or other measurement devices.

[0068] In one example configuration of FIG. 5A, the measurement device 510 is an additional pressure and temperature transducer used for a topside virtual multiphase flow meter. The measurement device 510 is located downstream of the automated choke valve 410. Since there is a virtual flow meter on the riser portion of the flow line, the controller can utilize both feedback and feedforward control.

[0069] In the embodiment of FIG. 5A, a multiphase fluid enters the pipeline system at the base of the seafloor at point of entry 402. In various embodiments, immediately before the fluid reaches the riser, its pressure and temperature states is measured via measurement devices 502, and the measurement values are passed to the application 508.

[0070] After the fluid travels up riser and right before the fluid reaches the choke valve 410, the pressure and temperature states of the fluid is measured again via measurement devices 504 and passed to the application 508. In various embodiments, that the measurements taken at measurement devices 502 and 504 are utilized for the virtual multiphase flow meter on the riser.

[0071] In various embodiments, the automated choke valve 410 controls the back pressure applied on the pipeline system upstream of the automated choke valve 410 and the flow rate through the automated choke valve 410. The openness of the automated choke valve 410 is governed by an controller within the application 508. Once the fluid travels through the automated choke valve 410, the pressure and temperature states of the fluid are immediatelymeasured again via measurement devices 506, and then measured a short way downstream via measurement devices 510. In various embodiments, both of the sets of measurements are passed to the application 508. The measurements taken via measurement devices 504, 506, and 510 are utilized for the virtual multiphase flow meter on the topside.

[0072] After the fluid is measured another time, the fluid enters the separator 416 to be separated into gas 418 and liquid 420 streams. After the gas 418 and liquid 420 streams have been separated, their mass flow rates are subsequently measured via measurement devices 512 and 514, respectively, and are passed to the application 508. In various embodiments, the liquid level in the separator 416 is measured as well via measurement devices 516 and passed to the application 508.

[0073] Thus, in various embodiments, as shown in the configuration of FIG. 5A, immediately after a fluid enters the flow line system, its pressure and temperature are measured via the first measurement devices 502. The pressure and temperature of the fluid are directly measured downstream again at the FPSO or CPF including the separator 416 via measurement devices. For example, the pressure and temperature can be measured directly upstream of the automated choke valve via measurement devices 504, directly downstream of the automated choke valve via measurement devices 506, a short distance downstream of the automated choke valve via measurement devices 510, or any combination thereof. In various embodiments, the third set of measurement devices 510 are at least six pipeline diameters downstream from the second set of measurement devices. In various embodiments, the last three sets of measurements, taken via measurement devices 512, 514, and 516 at the FPSO or CPF including the separator 416, along with the openness of the automated choke valve 410 are utilized by a topside virtual multiphase flow meter to compute the mass flow rate of the gas phase and liquid phase of the fluid traveling through the automated choke valve 410. In various examples, the liquid phase includes oil and produced water. In various embodiments, the pressure and temperature of the fluid as measured at the base of the riser and directly upstream of the automated choke valve 410, in conjunction with the virtual mass flow rates of each phase computed by the topside virtual multiphase flow meter, are utilized by an additional virtual multiphase flow meter to compute the mass flow rate of each phase of the fluid entering the flow line system.

[0074] Once the fluid travels past the fourth set of measurement devices 510, the flow entersa two phase separator 416, where its liquid and gas phases are separated into their constitutive streams, including gas 418 and liquid 420 streams. After successful separation, the mass flow rates of the two separated gas 418 and liquid 420 streams are measured via measurement devices 512 and 514, respectively. In various embodiments, these measurements are utilized in a procedure to re-calibrate the upstream virtual flow meters. In various examples, there is a time delay between when a fluid molecule passes through the virtual multiphase flow meters and when the molecule passes through its respective mass flow meter on the effluent end of the separator 416. For example, the time delay between a flow measured by a virtual multiphase flow meter at a sea floor and the appearance of the same flow at the separator may be measured in minutes. Thus, the values from the virtual multiphase flow meter at the seabed provide time for a response to be implemented at the automated choke valve or the vessel of a processing facility based on any detected slug events.

[0075] In the configuration of FIG. 5A, the controller utilizes an integrated feedforward and feedback control scheme, as described in the example of FIG. 6A. The feedforward portion of the controller originates from the ability of the control scheme to modulate the automated choke valve 410 based upon the pressure, temperature, and mass flow rate of each phase entering the flow line system at the base of the riser. The feedback portion of the control scheme emanates from the ability of the system to change the openness of the automated choke valve 410 based the pressure and temperature, as well of the mass flow rate, of each phase directly upstream and across the automated choke valve 410, respectively. In these manners, the automated choke valve 410 can be modulated to reduce the size of slugs while they are forming and thus mitigate their impact.

[0076] In various embodiments, the controller, virtual multiphase flow meters, and procedure to re-calibrate the set of virtual multiphase flow meters is packed and run in an isolated runtime environment referred to herein as a container. The container encapsulates the code along with all dependencies, including system libraries, configuration files, and binaries. Leveraging this containerized approach, the developed application can be practically run anywhere. This all-in- one packaging of the application makes the application portable by enabling the application to behave consistently in diverse host systems. In various examples, the containerized application is also a lightweight application, thus further enabling faster launch and execution.

[0077] FIG. 5B is a schematic diagram of an exemplary a pipeline system 500B with anintegrated containerized application including a feedback control scheme, according to embodiments of the present disclosure. The pipeline system 500B of FIG. 5B illustrates how the adaptive control system, virtual multiphase flow meter on the riser, and topside virtual multiphase flow meter are integrated with the pipeline system when a third set of measurement devices for the topside virtual multiphase flow meter is downstream of the adjustable choke valve 410. FIG. 5B includes similarly referenced elements of FIGS. 4 and 5A. However, in the pipeline system 500B of FIG. 5B, there is no virtual flow meter on the riser portion of the flow line. Therefore, the controller of pipeline system 500B utilizes a feedback control scheme, such as the scheme described with respect to FIG. 6B.

[0078] FIG. 6A is a schematic diagram of an exemplary system 600A implementing a feedforward and feedback control scheme, according to embodiments of the present disclosure. FIG. 6A illustrates how the virtual multiphase flow meters 614, the controller 604, which utilizes an integrated feedforward and feedback control scheme, the parameter adjuster 618, and the measurement and automation equipment such as the automated choke valve 608 within the pipelines system are integrated together. In various embodiments, disturbances 612 are passed to the process and to the virtual multiphase flow meters 614. For example, the disturbances may include measurement noise, high frequency noise in the flow, etc. The desired set points for the mass flow rate of the fluid traveling through the choke valve and / or the pressure directly upstream of the automated choke valve 608 is governed by the flow of input 602 and the set points are passed directly to the controller 604. The controller 604 computes the desired openness 606 of the automated choke valve 608 based upon process measurements 610 and 616, and passes the computed desired openness 606 to the automated choke valve 608.

[0079] In various embodiments, measurement values 610 taken from the pressure and temperature transducers on the pipeline system are passed to the virtual multiphase flow meter 614, and to the controller 604. The mass flow rate of the multiphase fluid traveling through the choke valve and possibly the fluid traveling the riser, depending on the configuration, is passed to the parameter adjuster 618 of the adaptive control system, as well as the controller 604. The parameters 620, from the parameter adjuster 618 are also passed to the controller 604.

[0080] FIG. 6B is a schematic diagram of an exemplary system 600B implementing a feedback control scheme, according to embodiments of the present disclosure. FIG. 6B includes similarly referenced elements described in FIG. 6A. FIG. 6B illustrates how the measurementand automated choke valve 608 within the pipeline system and the virtual multiphase flow meter 614 are integrated with the controller 604, when the controller 604 utilizes a feedback control scheme.

[0081] FIG. 7 is a process flow diagram of an exemplary method 700 for automatically computing set points for an automated choke valve in a conduit containing a multi -phase fluid stream. In various embodiments, the method 700 can be implemented using any suitable computer system, such as the cluster computing system 800 of FIG. 8 , and as a containerized application, such as the containerized application 900 of FIG. 9.

[0082] The method 700 begins at block 702, in which a multi-phase fluid stream is transported via a conduit to a fluid processing system comprising a vessel to separate the multiphase fluid stream into its constitutive streams, a gas stream and at least one liquid stream. In some embodiments, the vessel may act as a slug catcher. For example, the vessel may include a two-phase separator. In some embodiments, the vessel may include a three-phase separator. In various embodiments, the fluid processing system may be connected to any number of conduits. For example, each of the number of conduits may be connected to any number of wells.

[0083] At block 704, the flow rate of the multi-phase fluid stream flowing into the conduit is determined via a first sensor located at the inlet of the at least one conduit. For example, the flow rate may be measured directly using a flow meter containing the first sensor.

[0084] At block 706, the flow of the multi-phase fluid stream is regulated via an automated choke valve. In various embodiments, the automated choke valve is associated with any number of sensors in each of a number of conduits.

[0085] At block 708, a flow-rate of the multi-phase fluid passing through the automated choke valve is determined via a second sensor. For example, in some embodiments, the second sensor is upstream of the automated choke valve on the conduit. In some embodiments, the second sensor is downstream of the automated choke valve on the conduit. In some embodiments, the flow-rate is determined via two sensors located upstream and downstream of the automated choke valve on the conduit.

[0086] At block 710, the measurement signals from each of the first sensor and the second sensor are monitored and processed. For example, one or more of the measurement signals may be used to calculate a flow rate of one or more phases via a virtual multiphase flow meter. In various embodiments, a virtual multiphase flow meter may be associated with each of the at leastone conduit.[0087J At block 712, a set point is computed based upon the measurement signals. In various embodiments, any number of set points may be computed. For example, the appropriate choking set point to pass to the automated choke valve to reduce the frequency and severity of liquid slugs based upon the measurement signals can be determined via a model -based process controller on a computer unit. In some embodiments, the appropriate choking set point to pass to the automated choke valve to reduce the frequency and severity of liquid slugs based upon the measurement signal is determined via a machine learning based logic on the computer unit.

[0088] At block 714, the set point is passed to the automated choke valve. For example, the automated choke valve may then adjust the flow rate of the multi-phase fluid based on the set point.

[0089] The process flow diagram of FIG. 7 is not intended to indicate that the steps of the method 700 are to be executed in any particular order, or that all of the steps of the method 700 are to be included in every case. Further, any number of additional steps not shown in FIG. 7 may be included within the method 700, depending on the details of the specific implementation. For example, in various embodiments, the method 700 can include determining the phase component flow-rates of each of the fluid streams exiting the fluid processing system. In some embodiments, the method 700 includes performing at least one measurement to determine the capacity of the system. In some embodiments, the method 700 includes tuning sensors that are utilized to determine the flow rate of the multi-phase fluid flowing into a number of conduits and passing through the automated choke valve. For example, the automated choke valve may have an associated sensor in each of any number of conduits. In some embodiments, the associated sensor in each of the number of conduits is downstream of the automated choke valve. In some embodiments, the associated sensor in each of the number of conduits is upstream of the automated choke valve.Exemplary Cluster Computing System and Containerized Application for Implementing Embodiments of the Present Disclosure

[0090] FIG. 8 is a block diagram of an exemplary cluster computing system 800 that may be utilized to implement the present disclosure. The exemplary cluster computing system 800 shown in FIG. 8 has four computing units 802A, 802B, 802C, and 802D, each of which may perform calculations for a portion of the present disclosure. However, one of ordinary skill inthe art will recognize that the cluster computing system 800 is not limited to this configuration, as any number of computing configurations may be selected. For example, a smaller analysis may be run on a single computing unit, such as a workstation, while a large calculation may be run on a cluster computing system 800 having tens, hundreds, thousands, or even more computing units. In some embodiments, one or more of the computing units of the cluster computing system 800 is used to implement an edge of an edge computing platform.

[0091] The cluster computing system 800 may be accessed from any number of client systems 804A and 804B over a network 806, for example, through a high-speed network interface 808. The computing units 802A to 802D may also function as client systems, providing both local computing support and access to the wider cluster computing system 800.

[0092] The network 806 may include a local area network (LAN), a wide area network (WAN), the Internet, or any combinations thereof. Each client system 804A and 804B may include one or more non-transitory, computer-readable storage media for storing the operating code and program instructions that are used to implement the present disclosure. For example, each client system 804A and 804B may include a memory device 810A and 810B, which may include random access memory (RAM), read only memory (ROM), and the like. Each client system 804A and 804B may also include a storage device 812A and 812B, which may include any number of hard drives, optical drives, flash drives, or the like.

[0093] The high-speed network interface 808 may be coupled to one or more buses in the cluster computing system 800, such as a communications bus 814. The communication bus 814 may be used to communicate instructions and data from the high-speed network interface 808 to a cluster storage system 816 and to each of the computing units 802A to 802D in the cluster computing system 800. The communications bus 814 may also be used for communications among the computing units 802A to 802D and the cluster storage system 816. In addition to the communications bus 814, a high-speed bus 818 can be present to increase the communications rate between the computing units 802A to 802D and / or the cluster storage system 816.

[0094] The cluster storage system 816 can have one or more non-transitory, computer- readable storage media, such as storage arrays 820A, 820B, 820C and 820D for the storage of models, data (including core data relating to one or more wells), visual representations, results (such as graphs, charts, and the like used to convey results obtained using the present disclosure), code, and other information concerning the implementation of the present disclosure. Thestorage arrays 820A to 820D may include any combinations of hard drives, optical drives, flash drives, or the like.

[0095] Each computing unit 802A to 802D can have a processor 822A, 822B, 822C and 822D and associated local non-transitory, computer-readable storage media, such as a memory device 824 A, 824B, 824C and 824D and a storage device 826 A, 826B, 826C and 826D. Each processor 822A to 822D may be a multiple core unit, such as a multiple core central processing unit (CPU) or a graphics processing unit (GPU). Each memory device 824A to 824D may include ROM and / or RAM used to store program instructions for directing the corresponding processor 822A to 822D to implement the present disclosure. Each storage device 826A to 826D may include one or more hard drives, optical drives, flash drives, or the like. In addition, each storage device 826A to 826D may be used to provide storage for models, intermediate results, data, images, or code associated with operations, including code used to implement the present disclosure.

[0096] The present disclosure is not limited to the architecture or unit configuration illustrated in FIG. 8. For example, any suitable processor-based device may be utilized for implementing all or a portion of embodiments of the present disclosure, including without limitation personal computers, laptop computers, computer workstations, mobile devices, and multi-processor servers or workstations with (or without) shared memory. For example, in some embodiments, the present disclosure can be implemented vi an edge device of an edge computing platform. Moreover, embodiments may be implemented on application specific integrated circuits (ASICs) or very-large-scale integrated (VLSI) circuits. In fact, persons of ordinary skill in the art may utilize any number of suitable structures capable of executing logical operations according to embodiments described herein.

[0097] FIG. 9 is a block diagram of an example containerized application 900 that may be utilized to implement embodiments of the present disclosure. FIG. 9 illustrates the three primary components of a containerized application 900, which include hardware requirements 902, software dependencies 904, and the application 906 itself. In various embodiments, the hardware requirements 902 may include various hardware components such as a network, CPU, disk, and RAM, as described in greater detail with respect to FIG. 8. In some embodiments, the application 906 may be implemented on a server functioning as an edge device of an edge computing platform.

[0098] The software dependencies 904 may include any software related to containerization or various dependencies of the application 902. For example, dependencies may include system libraries, configuration files, and binaries.

[0099] The application 902 includes elements of the automation system and any related models. For example, the application 902 can include automation system components such as predictive, real-time, and diagnostic components. For example, the application 902 can include a controller, smart logic, and an operator interface.

[0100] FIG. 10 is a block diagram of an exemplary non-transitory, computer-readable storage medium 1000 that may be used for the storage of data and modules of program instructions for implementing the present disclosure. The non-transitory, computer-readable storage medium 1000 may include a memory device, a hard disk, and / or any number of other devices, as described herein. A processor 1002 may access the non-transitory, computer- readable storage medium 1000 over a bus or network 1004. While the non-transitory, computer- readable storage medium 1000 may include any number of modules (and sub-modules) for implementing the present disclosure, in some embodiments, the non-transitory, computer- readable storage medium 1000 includes a sensor monitor module 1006. More specifically, the sensor monitor module 1006 may direct the processor 1002 to monitor and process measurement signals from any number of sensors. For example, in some embodiments, the, the flow rate of the multi-phase fluid stream flowing into the conduit is determined via a first sensor located at the inlet of the at least one conduit. In some embodiments, a flow-rate of the multi-phase fluid passing through the automated choke valve is determined via a second sensor. In some embodiments, the second sensor is downstream of the automated choke valve on the conduit. In addition, in some embodiments, the second sensor is upstream of the automated choke valve on the conduit.

[0101] Furthermore, in some embodiments, the non-transitory, computer-readable storage medium 1000 includes a set point computer module 1008 for computing set points for automated choke valves. In some embodiments, the set point computer module 1008 may direct the processor 1002 to compute set points based upon the measurement signals.

[0102] In addition, in some embodiments, the non-transitory, computer-readable storage medium 1000 includes a valve adjuster module 1010 for adjusting automated choke valves. Insome embodiments, the set point computer module 1010 may direct the processor 1002 to pass the set points to automated choke valves.

[0103] FIG. 11 is a set of graphs 1102, 1104, and 1106, illustrating the performance of various virtual multi-phase flow meters. Each of the graphs 1102, 1104, and 1106 includes a horizontal axis representing time in days and a vertical axis representing a normalized gas liquid ratio, normalized liquid flow rate, and normalized gas flow rate, respectively. In addition, each of graphs 1102, 1104, and 1106 depicts a 95% confidence interval of actual values using substantially vertical bars and predicted values using a solid black line. For example, a system may have multiple conduits receiving fluid from multiple sets of wells. As one example, each conduit coupled to the HP separator may be fluidically coupled to receive fluid from five wells. The conduit coupled to the test separator may be fluidically coupled to receive fluid from a single well. In various examples, the HP separator may receive fluid streams from a number of conduits and the test separator may receive fluid from a single conduit. The test separator breaks the fluid from the single conduit down into its constituent parts in order to determine the fluid components being received from a specific well. For example, the test separator can calculate water flow rates, gas flow rates, oil flow rates. In some examples, pressure, volume, temperature (PVT) samples may also be taken at a test separator to determine the constituent parts, such as how much methane, ethane, etc., are in each of the phases. In various examples, each of the conduits may be similarly tested.

[0104] In this manner, the disclosure described herein provides a practical application that directly improves the mitigation and management of potential slugs in conduits containing fluids from a system of wells, and thus enables improved hydrocarbon management. For example, the disclosure enables more stable and continuous processing of fluids with less occurrences of slugging and associated shutdowns and delays.

[0105] Although embodiments herein are described with respect to the unconventional oil extraction, one with skilled in the art will readily recognize that the embodiments of the disclosure described herein are also suitable for application in other areas. For example, such applications may include carbon storage applications, among other applications within hydrocarbon management. It is intended that the foregoing detailed description be understood as an illustration of selected forms that the present disclosure can take and not as a definition of the present disclosure. Further, it should be noted that any aspect of any of the preferredembodiments described herein may be used alone or in combination with one another. Finally, persons skilled in the art will readily recognize that in preferred implementation, some, or all of the steps in the disclosed method are performed using a computer so that the methodology is computer implemented.

[0106] While the embodiments described herein are well -calculated to achieve the advantages set forth, it will be appreciated that such embodiments are susceptible to modification, variation, and change without departing from the spirit thereof. In other words, the particular embodiments described herein are illustrative only, as the teachings of the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Moreover, the systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and / or any optional element disclosed herein. While compositions and methods are described in terms of “comprising” or “including” various components or steps, the compositions and methods can also “consist essentially of’ or “consist of’ the various components and steps. Indeed, the present disclosure includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

Claims

CLAIMSWhat is claimed is:

1. A system, comprising: a conduit to transport a multi-phase fluid stream to a fluid processing system; a first sensor to determine the flow rate of the multi-phase fluid flowing into the conduit; an automated choke valve to regulate the flow of the multi-phase fluid stream; a second sensor fluidically coupled to the automated choke valve on the conduit to determine the flow-rate of the multi-phase fluid passing through the automated choke valve into the corresponding conduit; and a processor of a computer unit, wherein the processor is to monitor and process measurement signals from the sensors, and compute and pass a set point to the automated choke valve based upon the measurement signals.

2. The system of claim 1, wherein the fluid processing system comprises a vessel.

3. The system of claim 2, wherein the vessel is to separate the multi-phase fluid stream into constitutive streams comprising a gas stream and at least one liquid stream.

4. The system of claim 2, wherein the vessel is a slug catcher.

5. The system of any of claims 1 to 4, wherein the first sensor is located at the inlet of the conduit.

6. The system of any of claims 1 to 5, wherein the second sensor is upstream of the automated choke valve.

7. The system of any of claims 1 to 6, wherein the second sensor is downstream of the automated choke valve.

8. The system of any of claims 1 to 7, comprising a pressure measurement device at the inlet of the conduit.

9. The system of any of claims 1 to 8, comprising a pressure measurement device at the outlet of the conduit.

10. The system of any of claims 1 to 9, comprising a pressure measurement device on at least one vessel.

11. The system of any of claims 1 to 10, wherein the processor is to determine the phase component flow-rates of each of the fluid streams exiting the fluid processing system.

12. The system of any of claims 1 to 11, wherein the processor is to perform a measurement used to determine the capacity of the system.

13. The system of any of claims 1 to 12, wherein the processor is configured to use a model-based process controller on a computer unit to determine an appropriate set point to pass to the automated choke valve to reduce the frequency and severity of liquid slugs based upon the measurement signals.

14. The system of any of claims 1 to 13, wherein the processor is configured to use a machine learning based logic on the computer unit to determine the appropriate set point to pass to the automated choke valve to reduce the frequency and severity of liquid slugs based upon the measurement signals.

15. The system of any of claims 1 to 14, wherein the processor is configured to tune the second sensor.

16. A method, comprising: transporting, via a conduit, a multi-phase fluid stream to a fluid processing system comprising a vessel to separate the multi-phase fluid stream into its constitutive streams, a gas stream and at least one liquid stream; determining, via a first sensor located at the inlet of the at least one conduit, the flow rate of the multi-phase fluid stream flowing into the conduit;regulating, via an automated choke valve, the flow of the multi-phase fluid stream; determining, via a second sensor, a flow-rate of the multi-phase fluid passing through the automated choke valve; monitoring and processing the measurement signals from each of the first sensor and the second sensor; computing a set point based upon the measurement signals; and passing the set point to the automated choke valve.

17. The method of claim 16, wherein the vessel acts as a slug catcher.

18. The method of claim 16 or claim 17, wherein the second sensor is upstream of the automated choke valve on the conduit.

19. The method of any of claims 16 to 18, wherein the second sensor is downstream of the automated choke valve on the conduit.

20. The method of any of claims 16 to 19, comprising determining the phase component flow-rates of each of the fluid streams exiting the fluid processing system.

21. The method of any of claims 16 to 20, comprising performing at least one measurement to determine the capacity of the system.

22. The method of any of claims 16 to 21, comprising determining, via a model -based process controller on a computer unit, the appropriate choking set point to pass to the automated choke valve to reduce the frequency and severity of liquid slugs based upon the measurement signals.

23. The method of any of claims 16 to 22, comprising determining, via a machine learning based logic on a computer unit, the appropriate choking set point to pass to the automated choke valve to reduce the frequency and severity of liquid slugs based upon the measurement signal.

24. The method of any of claims 16 to 23, comprising tuning sensors that are utilized to determine the flow rate of the multi-phase fluid flowing into a plurality of conduits and passing through the automated choke valve, wherein the automated choke valve has an associated sensor in each of the plurality of conduits.

25. The method of claim 24, wherein the associated sensor in each of the plurality of conduits is downstream of the automated choke valve.

26. The method of claim 24, wherein the associated sensor in each of the plurality of conduits is upstream of the automated choke valve.

27. The method of any of claims 16 to 26, wherein the automated choke valve has a plurality of associated sensors in each of a plurality of conduits.

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