Method for oil and gas well production management using gradient metering

Abstract

A method of optimizing production from a wellbore. The method may include receiving pressure data from the wellbore, determining a gradient measurement based on the received pressure data, performing an automated flow control device sequence in a plurality of zones of the wellbore when the gradient measurement exceeds or drops below a predetermined threshold to provide a plurality of stabilized gradient measurements, and normalizing the gradient measurement based on the stabilized gradient measurements to provide a fluid characteristic for each of the zones. Each of the plurality of stabilized gradient measurements may correspond to one of the plurality of zones. Performing the automated flow control device sequence may include stopping a flow within one of the plurality of zones, detecting change in the gradient measurement while the flow within the first zone is stopped, recording a stabilized gradient measurement, and then resuming the flow within the first zone.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to U.S. Provisional Patent Application No. 63 / 777,394, filed on Mar. 25, 2025, which is incorporated by reference.BACKGROUND

[0002] Valves or flow control devices play a role in many industries. Wells or wellbores at field sites may have a number of downhole flow control valves or devices which allow for the ability to adjust the opening and closing area of valves in order to manage oil, gas, and / or water production. Many valves or other diagnostic sensors may be connected to tubing gauges which may be deployed in a wellbore at a field site to measure a current output of a related valve or series of valves.

[0003] What is needed is a method utilizing gradient measurements to understand flow behavior and optimize the production of oil and gas wells.SUMMARY

[0004] In certain embodiments, a method of optimizing production from a wellbore may be provided. The method may include receiving pressure data from the wellbore, determining a gradient measurement based on the received pressure data, performing an automated flow control device sequence in a plurality of zones of the wellbore when the gradient measurement exceeds or drops below a predetermined threshold to provide a plurality of stabilized gradient measurements, and normalizing the gradient measurement based on the stabilized gradient measurements to provide a fluid characteristic for each of the zones. Each of the plurality of stabilized gradient measurements may correspond to one of the plurality of zones.

[0005] In certain embodiments, a computing system may be provided including one or more processors and a memory system comprising one or more non-transitory computer-readable media storing instructions that, when executed by at least one of the one or more processors, cause the computing system to perform operations. The operations may include receiving pressure data from the wellbore, determining a gradient measurement based on the received pressure data, performing an automated flow control device sequence in a plurality of zones of the wellbore when the gradient measurement exceeds or drops below a predetermined threshold to provide a plurality of stabilized gradient measurements, and normalizing the gradient measurement based on the stabilized gradient measurements to provide a fluid characteristic for each of the zones. Each of the plurality of stabilized gradient measurements may correspond to one of the plurality of zones.

[0006] In certain embodiments, a non-transitory computer-readable medium storing instructions may be provided that, when executed by one or more processors of a computing system, cause the computing system to perform operations. The operations may include receiving pressure data from the wellbore, determining a gradient measurement based on the received pressure data, performing an automated flow control device sequence in a plurality of zones of the wellbore when the gradient measurement exceeds or drops below a predetermined threshold to provide a plurality of stabilized gradient measurements, and normalizing the gradient measurement based on the stabilized gradient measurements to provide a fluid characteristic for each of the zones. Each of the plurality of stabilized gradient measurements may correspond to one of the plurality of zones.BRIEF DESCRIPTION OF THE DRAWINGS

[0007] The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments of the present teachings and together with the description, serve to explain the principles of the present teachings. In the figures:

[0008] FIG. 1 illustrates an example of a system that includes various management components to manage various aspects of a geologic environment, according to an embodiment.

[0009] FIG. 2 illustrates a flowchart of a method for performing an automated flow control device sequence, according to an embodiment.

[0010] FIG. 3 illustrates a flowchart of the method described herein, according to an embodiment.

[0011] FIG. 4 illustrates a schematic view of a computing system for performing at least a portion of the method described herein, according to an embodiment.DETAILED DESCRIPTION

[0012] In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure. It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the disclosure. These are, of course, merely examples and are not intended to be limiting. However, it will be understood by those of ordinary skill in the art that the system and / or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments are possible. This description is not to be taken in a limiting sense, but rather made merely for the purpose of describing general principles of the implementations. The scope of the described implementations should be ascertained with reference to the issued claims.

[0013] As used herein, the terms “connect”, “connection”, “connected”, “in connection with”, and “connecting” are used to mean “in direct connection with” or “in connection with via one or more elements”; and the term “set” is used to mean “one element” or “more than one element”. Further, the terms “couple”, “coupling”, “coupled”, “coupled together”, and “coupled with” are used to mean “directly coupled together” or “coupled together via one or more elements”. As used herein, the terms “up” and “down”; “upper” and “lower”; “top” and “bottom”; and other like terms indicating relative positions to a given point or element are utilized to more clearly describe some elements. Commonly, these terms relate to a reference point at the surface from which drilling operations are initiated as being the top point and the total depth being the lowest point, for example when the well (e.g., wellbore, borehole) is vertical, horizontal or slanted relative to the surface.

[0014] In addition, as used herein, the terms “real time”, “real-time”, or “substantially real time” may be used interchangeably and are intended to described operations (e.g., computing operations) that are performed without any human-perceivable interruption between operations. For example, as used herein, data relating to the systems described herein may be collected, transmitted, and / or used in control computations in “substantially real time” such that data readings, data transfers, and / or data processing steps occur once every second, once every 0.1 second, once every 0.01 second, or even more frequent, during operations of the systems (e.g., while the systems are operating). In addition, as used herein, the terms “automatic” and “automated” are intended to describe operations that are performed are caused to be performed, for example, by a control system (i.e., solely by the control system, without human intervention).

[0015] Language of degree used herein, such as the terms “approximately,”“about,”“generally,” and “substantially” as used herein represent a value, amount, or characteristic close to the stated value, amount, or characteristic that still performs a desired function or achieves a desired result. For example, the terms “approximately,”“about,”“generally,” and “substantially” may refer to an amount that is within less than 10% of, within less than 5% of, within less than 1% of, within less than 0.1% of, and / or within less than 0.01% of the stated amount. As another example, in certain embodiments, the terms “generally parallel” and “substantially parallel” or “generally perpendicular” and “substantially perpendicular” refer to a value, amount, or characteristic that departs from exactly parallel or perpendicular, respectively, by less than or equal to 15 degrees, 10 degrees, 5 degrees, 3 degrees, 1 degree, or 0.1 degree.System Overview

[0016] FIG. 1 illustrates an example of a system 100 that includes various management components 110 to manage various aspects of a geologic environment 150 (e.g., an environment that includes a sedimentary basin, a reservoir 151, one or more faults 153-1, one or more geobodies 153-2, etc.). For example, the management components 110 may allow for direct or indirect management of sensing, drilling, injecting, extracting, etc., with respect to the geologic environment 150. In turn, further information about the geologic environment 150 may become available as feedback 160 (e.g., optionally as input to one or more of the management components 110).

[0017] In the example of FIG. 1, the management components 110 include a seismic data component 112, an additional information component 114 (e.g., well / logging data), a processing component 116, a simulation component 120, an attribute component 130, an analysis / visualization component 142 and a workflow component 144. In operation, seismic data and other information provided per the components 112 and 114 may be input to the simulation component 120.

[0018] In an example embodiment, the simulation component 120 may rely on entities 122. Entities 122 may include earth entities or geological objects such as wells, surfaces, bodies, reservoirs, etc. In the system 100, the entities 122 may include virtual representations of actual physical entities that are reconstructed for purposes of simulation. The entities 122 may include entities based on data acquired via sensing, observation, etc. (e.g., the seismic data 112 and other information 114). An entity may be characterized by one or more properties (e.g., a geometrical pillar grid entity of an earth model may be characterized by a porosity property). Such properties may represent one or more measurements (e.g., acquired data), calculations, etc.

[0019] In an example embodiment, the simulation component 120 may operate in conjunction with a software framework such as an object-based framework. In such a framework, entities may include entities based on pre-defined classes to facilitate modeling and simulation. A commercially available example of an object-based framework is the MICROSOFT® NET® framework (Redmond, Washington), which provides a set of extensible object classes. In the .NET® framework, an object class encapsulates a module of reusable code and associated data structures. Object classes may be used to instantiate object instances for use in by a program, script, etc. For example, borehole classes may define objects for representing boreholes based on well data.

[0020] In the example of FIG. 1, the simulation component 120 may process information to conform to one or more attributes specified by the attribute component 130, which may include a library of attributes. Such processing may occur prior to input to the simulation component 120 (e.g., consider the processing component 116). As an example, the simulation component 120 may perform operations on input information based on one or more attributes specified by the attribute component 130. In an example embodiment, the simulation component 120 may construct one or more models of the geologic environment 150, which may be relied on to simulate behavior of the geologic environment 150 (e.g., responsive to one or more acts, whether natural or artificial). In the example of FIG. 1, the analysis / visualization component 142 may allow for interaction with a model or model-based results (e.g., simulation results, etc.). As an example, output from the simulation component 120 may be input to one or more other workflows, as indicated by a workflow component 144.

[0021] As an example, the simulation component 120 may include one or more features of a simulator such as the ECLIPSE™ reservoir simulator (SLB, Houston Texas), the INTERSECT™ reservoir simulator (SLB, Houston Texas), etc. As an example, a simulation component, a simulator, etc. may include features to implement one or more meshless techniques (e.g., to solve one or more equations, etc.). As an example, a reservoir or reservoirs may be simulated with respect to one or more enhanced recovery techniques (e.g., consider a thermal process such as SAGD, etc.).

[0022] As an example, the simulation component 120 may include one or more features of a simulator such as SYMMETRY™ software (SLB, Houston, Texas). More particularly, SYMMETRY™ may process workflows in a single integrated environment with accurate thermodynamic fluid representation and consistent modeling across multiple disciplines including process, production, and HSE. The simulator integrates steady-state and transient (e.g., dynamic) analyses that may be tailored for each domain. This approach enables users to optimize processes in upstream, midstream, and downstream sectors while maximizing profits and minimizing capital expenditures. It may also help reduce emissions, energy consumption, and waste.

[0023] As an example, the simulation component 120 may include one or more features of a simulator such as PIPESIM™ (SLB, Houston, Texas). More particularly, PIPESIM™ is steady-state multiphase flow simulator that incorporates the three areas of flow modeling: multiphase flow, heat transfer and fluid behavior.

[0024] As an example, the simulation component 120 may include one or more features of a simulator such as OLGA™ (SLB, Houston, Texas). More particularly, OLGA™ is a dynamic multiphase flow simulator that models transient flow (e.g., time-dependent behaviors) to maximize production potential. Transient modeling is a component for feasibility studies and field development design. Dynamic simulation is useful in deep water and is used in both offshore and onshore developments to investigate transient behavior in pipelines and wellbores. Transient simulation with the OLGA™ simulator provides an added dimension to steady-state analysis by predicting system dynamics, such as time-varying changes in flow rates, fluid compositions, temperature, solids deposition, and operational changes.

[0025] In an example embodiment, the management components 110 may include features of a commercially available framework such as the PETREL® seismic to simulation software framework (SLB, Houston, Texas). The PETREL® framework provides components that allow for optimization of exploration and development operations. The PETREL® framework includes seismic to simulation software components that may output information for use in increasing reservoir performance, for example, by improving asset team productivity. Through use of such a framework, various professionals (e.g., geophysicists, geologists, and reservoir engineers) may develop collaborative workflows and integrate operations to streamline processes. Such a framework may be considered an application and may be considered a data-driven application (e.g., where data is input for purposes of modeling, simulating, etc.).

[0026] In an example embodiment, various aspects of the management components 110 may include add-ons or plug-ins that operate according to specifications of a framework environment. For example, a commercially available framework environment marketed as the OCEAN® framework environment (SLB, Houston, Texas) allows for integration of add-ons (or plug-ins) into a PETREL® framework workflow. The OCEAN® framework environment leverages .NET® tools (Microsoft Corporation, Redmond, Washington) and offers stable, user-friendly interfaces for efficient development. In an example embodiment, various components may be implemented as add-ons (or plug-ins) that conform to and operate according to specifications of a framework environment (e.g., according to application programming interface (API) specifications, etc.).

[0027] FIG. 1 also shows an example of a framework 170 that includes a model simulation layer 180 along with a framework services layer 190, a framework core layer 195 and a modules layer 175. The framework 170 may include the commercially available OCEAN® framework where the model simulation layer 180 is the commercially available PETREL® model-centric software package that hosts OCEAN® framework applications. In an example embodiment, the PETREL® software may be considered a data-driven application. The PETREL® software may include a framework for model building and visualization.

[0028] As an example, a framework may include features for implementing one or more mesh generation techniques. For example, a framework may include an input component for receipt of information from interpretation of seismic data, one or more attributes based at least in part on seismic data, log data, image data, etc. Such a framework may include a mesh generation component that processes input information, optionally in conjunction with other information, to generate a mesh.

[0029] In the example of FIG. 1, the model simulation layer 180 may provide domain objects 182, act as a data source 184, provide for rendering 186 and provide for various user interfaces 188. Rendering 186 may provide a graphical environment in which applications may display their data while the user interfaces 188 may provide a common look and feel for application user interface components.

[0030] As an example, the domain objects 182 may include entity objects, property objects and optionally other objects. Entity objects may be used to geometrically represent wells, surfaces, bodies, reservoirs, etc., while property objects may be used to provide property values as well as data versions and display parameters. For example, an entity object may represent a well where a property object provides log information as well as version information and displays information (e.g., to display the well as part of a model).

[0031] In the example of FIG. 1, data may be stored in one or more data sources (or data stores, generally physical data storage devices), which may be at the same or different physical sites and accessible via one or more networks. The model simulation layer 180 may be configured to model projects. As such, a particular project may be stored where stored project information may include inputs, models, results and cases. Thus, upon completion of a modeling session, a user may store a project. At a later time, the project may be accessed and restored using the model simulation layer 180, which may recreate instances of the relevant domain objects.

[0032] In the example of FIG. 1, the geologic environment 150 may include layers (e.g., stratification) that include a reservoir 151 and one or more other features such as the fault 153-1, the geobody 153-2, etc. As an example, the geologic environment 150 may be outfitted with any of a variety of sensors, detectors, actuators, etc. For example, equipment 152 may include communication circuitry to receive and to transmit information with respect to one or more networks 155. Such information may include information associated with downhole equipment 154, which may be equipment to acquire information, to assist with resource recovery, etc. Other equipment 156 may be located remote from a well site and include sensing, detecting, emitting or other circuitry. Such equipment may include storage and communication circuitry to store and to communicate data, instructions, etc. As an example, one or more satellites may be provided for purposes of communications, data acquisition, etc. For example, FIG. 1 shows a satellite in communication with the network 155 that may be configured for communications, noting that the satellite may additionally or instead include circuitry for imagery (e.g., spatial, spectral, temporal, radiometric, etc.).

[0033] FIG. 1 also shows the geologic environment 150 as optionally including equipment 157 and 158 associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures 159. For example, consider a well in a shale formation that may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures. As an example, a well may be drilled for a reservoir that is laterally extensive. In such an example, lateral variations in properties, stresses, etc. may exist where an assessment of such variations may assist with planning, operations, etc. to develop a laterally extensive reservoir (e.g., via fracturing, injecting, extracting, etc.). As an example, the equipment 157 and / or 158 may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, etc.

[0034] As mentioned, the system 100 may be used to perform one or more workflows. A workflow may be a process that includes a number of worksteps. A workstep may operate on data, for example, to create new data, to update existing data, etc. As an example, a may operate on one or more inputs and create one or more results, for example, based on one or more algorithms. As an example, a system may include a workflow editor for creation, editing, executing, etc. of a workflow. In such an example, the workflow editor may provide for selection of one or more pre-defined worksteps, one or more customized worksteps, etc. As an example, a workflow may be a workflow implementable in the PETREL® software, for example, that operates on seismic data, seismic attribute(s), etc. As an example, a workflow may be a process implementable in the OCEAN® framework. As an example, a workflow may include one or more worksteps that access a module such as a plug-in (e.g., external executable code, etc.).

[0035] A network architecture for drilling operations typically involves a multi-layered setup designed to handle the complexities of rig environments, as shown in FIG. 1. The infrastructure may be segmented into distinct network zones, such as an information technology (IT) network, an operational technology (OT) network, and a rig network, to ensure security and manageability.

[0036] The IT network may include centralized support and monitoring systems, such as the Service Provider Central Support Network, which interacts with the rig networks via secure communication channels. The OT network may operate within a more restrictive environment, managing essential control systems and acquisition networks, including surface and downhole data acquisition devices. Each network segment is further isolated using firewalls and hypervisor technologies, enabling network segmentation and perimeter security.

[0037] The rig network connects critical edge devices, such as drilling control units, acquisition systems, and other wellsite equipment which perform various automation and data processing tasks. These edge devices often operate with limited bandwidth, making it challenging to transmit large amounts of data in real time. Therefore, a robust strategy for monitoring and data collection is preferred to ensure efficient operation without overwhelming the network.Method for Oil and Gas Well Production Management Using Gradient Metering

[0038] Wells having downhole flow control valves or devices allow for the ability to adjust the opening and closing area of the flow control device to manage oil, gas, and / or water production. Existing methodologies may include the recording of multiphase flow measurements at the surface of the well by closing and opening the valves to understand the flow behavior, or by running production logging tool(s) (PLTs) downhole. Based on contributions of flow recorded from each zone, appropriate decisions may be made to adjust the valve flow area to manage production.

[0039] In certain embodiments, instead of surface and downhole measurements, gradient measurements may be used to understand flow behavior and / or to operate downhole valves or flow control devices. In certain embodiments, at least two downhole tubing gauges may be deployed in the wellbore above flow control valves. The difference in pressure between the two gauges may then be divided by the difference in the depth to provide a gradient. For example, a gradient measurement may be provided by equation 1:<semantics definitionURL="">❘<annotation encoding="Mathematica">"\[LeftBracketingBar]"< / annotation>< / semantics>P⁢1-P⁢2<semantics definitionURL="">❘<annotation encoding="Mathematica">"\[RightBracketingBar]"< / annotation>< / semantics><semantics definitionURL="">❘<annotation encoding="Mathematica">"\[LeftBracketingBar]"< / annotation>< / semantics>D⁢1-D⁢2<semantics definitionURL="">❘<annotation encoding="Mathematica">"\[RightBracketingBar]"< / annotation>< / semantics>,(1)where P1 is the pressure at the first tubing gauge, P2 is the pressure at the second tubing gauge, D1 is the true vertical depth of the first tubing gauge, and D2 is the true vertical depth of the second tubing gauge.Based on a fluid flow through the short vertical section of the wellbore where the gradient may be calculated, and disregarding the effects of phase slippage and friction, a qualitative inference may be made to understand the type or composition of the fluid flowing through the well, namely the percentage of oil, gas, and / or water within the flow. In certain embodiments, the fluid flow inferred at the well level may be further segregated to an individual downhole valve or device level to understand the flow behavior of each valve or zone, for example, by rule of exception.

[0041] FIG. 2 illustrates a flow chart of a method 200 or process flow for managing production from a wellbore, according to an embodiment. The method 200 may include deploying one or more downhole flow control devices in a wellbore at a wellsite. The method may also include deploying at least two downhole tubing gauges in the wellbore and then determining a gradient measurement based on a difference in pressure between the two gauges divided by a difference in depths of the gauges, as at 202.

[0042] In certain embodiments, the gradient measurement may be further processed by normalization of the gradient across all valves or zones within the wellbore. For example, the depth or distance between the at least two downhole tubing gauges may be subdivided or sorted into a plurality of zones, with each zone including at least one flow control device or a group or subset of flow control devices. When sorted into zones, the determined normalized gradient may provide information of combined fluid phases for each flow control device or zone relative to the other flow control devices or zones. For example, according to an embodiment, a normalized value of 1 may represent a more gaseous phase which may gradually transition to a liquid phase of oil at or about a normalization value of 0.5, and then water as the normalization value approaches and reaches 0, such that values at or closest to 0 indicate higher water fractions.

[0043] According to certain embodiments, the normalization value from each valve or zone may be used to adjust the valve flow area for optimum production, thereby enabling management of gas and water production while producing a maximum volume of oil. The method 200 may further include monitoring the gradient measurement in real time and then triggering an automated flow control device opening and closing sequence when the gradient measurement exceeds or drops below a predetermined threshold. For example, a change in the gradient above or below a predetermined threshold triggers an automated flow control device sequence to close and / or open the downhole valves one by one or in groups. As seen in FIG. 2, a determination may be made as at 204 where the well gradient for the wellbore may be determined to be either below 0.3 or above 0.36. If the well gradient is within the threshold, the process ends as at 206. If, however, the well gradient is either below or above the threshold, a command may be automatically generated and then transmitted to all of the zones within the wellbore in sequence, beginning with a first flow control device or zone, as at 208. Depending on the number of flow control devices installed in the wellbore, each flow control device may be closed, one by one or in groups, and opened prior to closing another flow control device (or multiple flow control devices simultaneously) to see the impact on gradient changes in the wellbore of closing and opening the valve(s) by following appropriate stabilization times. In certain embodiments, the command may include a command to close or adjust at least one valve within each respective zone, or to close or adjust any subset or combination of flow control devices within each respective zone. The one or more flow control devices within each zone may then be open, closed, or otherwise adjusted according to the received command, beginning with the flow control devices within the first zone, as at 210.

[0044] In certain embodiments, the gradient within the wellbore may be measured in real time at various points during the automated closing sequence of the flow control devices within the first zone, as at 212. In certain embodiments, a predetermined time period allowing for stabilization of the pressure within the wellbore may be allowed to lapse, as at 214. In certain embodiments, if a stabilized pressure has been achieved, for example after a few hours, the gradient for the wellbore may be measured and then recorded or stored in a database, as at 216. The stored gradient information may also include an inherent fluid behavior pattern of each zone. The one or more flow control devices within the first zone may then be opened or returned to their initial state. However, in certain embodiments, if after the predetermined time period for stabilization has elapsed and the pressure within the wellbore is still not consistent and is instead continuously changing, the flow control devices within the first zone may be further adjusted and a second predetermined time period may be allowed to lapse so as to achieved a stabilized pressure.

[0045] In certain embodiments, after the flow control devices within the first zone have been reopened, the next zone within the wellbore, for example a second zone including one or more flow control devices or one or more subsets of flow control devices, may be closed, as at 218. The same process described above to measure the gradient within the wellbore while the flow control devices within the first zone were closed may then be repeated while the flow control devices within the second zone are closed, namely the gradient within the wellbore may be measured in real time at various points during the automated closing sequence of the flow control devices within the second zone, as at 220. In certain embodiments, a predetermined time period allowing for stabilization of the pressure within the wellbore may be allowed to lapse, as at 222. In certain embodiments, if a stabilized pressure has been achieved, for example after a few hours, the gradient for the wellbore may be measured and then recorded or stored in a database, as at 224. The one or more flow control devices within the second zone may then be opened or returned to their initial state.

[0046] According to certain embodiments, this same process may be repeated for each of the zones of flow control devices within the wellbore in sequence, beginning with a first zone and ending with a zone N, where N represents the total number of flow control device zones within the wellbore. Specifically, after the flow control devices within an immediately preceding zone have been reopened, the one or more flow control devices included within the next zone N may be closed, as at 226. The gradient within the wellbore may be measured in real time at various points during the automated closing sequence of the flow control devices within zone N, as at 228. In certain embodiments, a predetermined time period allowing for stabilization of the pressure within the wellbore may be allowed to lapse, as at 230. In certain embodiments, if a stabilized pressure has been achieved, for example after a few hours, the gradient for the wellbore may be measured and then recorded or stored in a database, as at 232. The one or more flow control devices within zone N may then be opened or returned to their initial state. In certain embodiments, after the gradient within the wellbore has been measured each time as the flow control devices within each zone have been sequentially cycled, the gradient measurement portion of the method 200 may end, as at 234.

[0047] In certain embodiments, the measured gradients recorded as each flow control device zone within the wellbore is cycled may be used to determine a normalization of the gradient across all flow control devices or zones, as at 236. For example, the normalization of the gradient of the wellbore may be determined by equations 2:(Gc-Gmin)(Gmax-Gmin),(2)where Gc is the current recorded gradient value, Gmin is the minimum gradient value, and Gmax is the maximum gradient value.In certain embodiments, the normalization value may be used to label the fluid phases being produced by each of the flow control device zones of the wellbore, as at 238. In certain embodiments, high normalizations value that are at or close to 0.7 may be labeled as a water gradient, normalization values that are at or around 0.5 may be labeled as an oil gradient, and normalization values that are at or around 0.3 may be labeled as a gas gradient.

[0049] According to certain embodiments, the labeled fluid phases may then be displayed on a display as an output for a user, as at 240. In some embodiments, the user may react to the displayed labeled fluid phases by further adjusting the flow in one or more of the downhole flow control devices of one or more of the zones so as to optimize production from the wellbore. In other words, by labeling the stabilized gradient measurements for each zone of the wellbore, a user may be provided with the fluid characteristics for each zone of the wellbore so as to make further adjustments to the flow control devices within one or more the zones. For example, if a wellbore includes three different zones, with each zone including a corresponding subset of flow control devices, the user may be provided with a normalization value of 0.34 for a first zone, 0.52 for a second zone, and 0.65 for a third zone as provided by the method 200 described above. Based on the labeled normalization value, the user will know that the first zone is producing slightly more gas than is ideal and that the third zone is producing more water than is ideal, while the second zone is producing an amount of oil that is in line with a predetermined projection or target. The user may then adjust one or more flow control devices within each of the first and third zones so as to raise or lower the gradient measurement of the wellbore respectively to maximize oil production within each zone, and ultimately for the wellbore as a whole. In certain embodiments, the user may continually adjust one or more of the flow control devices within one or more of the zones until the gradient measurement equals or is within a predetermined range of the defined normalization value corresponding to oil. In certain embodiments, the more or more flow control devices may be adjusted so that the gradient measurement may consistently be between 0.2 psi / ft-0.45 psi / ft gradient units.Exemplary Method

[0050] FIG. 3 illustrates a flowchart of a method 300 of optimizing production from a wellbore. An illustrative order of the method 300 is provided below; however, one or more portions of the method 300 may be performed in a different order, simultaneously, repeated, or omitted. At least a portion of the method 300 may be performed using a computing system.

[0051] The method may include inserting a first downhole tubing gauge at a first depth within the wellbore and inserting a second downhole tubing gauge at a second depth within the wellbore, as at 302.

[0052] In certain embodiments, the method 300 may include receiving pressure data from the wellbore, as at 304. The wellbore may include a plurality of zones. Receiving pressure data may include receiving a first pressure value from the first downhole tubing gauge and a second pressure value from the second downhole tubing gauge.

[0053] In certain embodiments, the method 300 may include determining a gradient measurement based on the received pressure data, as at 306. Determining the gradient measurement may include determining a difference between the first pressure value and the second pressure value to obtain a pressure differential between the first and second downhole tubing gauges, and then dividing the pressure differential by a difference between the first true vertical depth and the second true vertical depth of the respective downhole tubing gauges. Determining the gradient measurement based on the received pressure data may include determining the gradient measurement (psi / ft) in real time.

[0054] In certain embodiments, the method 300 may include performing an automated flow control device sequence in a plurality of zones of the wellbore when the gradient measurement exceeds or drops below a predetermined threshold, as at 308. The flow control device sequence may include stopping a fluid flow within a first zone of the plurality of zones, detecting change in the gradient measurement while the flow within the first zone is stopped, recording a stabilized gradient measurement based on the change in the gradient measurement while the flow within the first zone is stopped in a database, and resuming the flow within the first zone. Performing the automated flow control device sequence may also include stopping a flow within a further zone of the plurality of zones, detecting a further change in the gradient measurement while the flow within the further zone is stopped, recording a stabilized gradient measurement based on the further change in the gradient measurement while the flow within the further zone is stopped in the database, and resuming the flow within the further zone. Recording the stabilized gradient measurement based on the change in the gradient measurement while the flow within the first zone is stopped in the database may include waiting for a predetermined amount of time to elapse and then recording the gradient measurement as the stabilized gradient measurement when the predetermined amount of time has elapsed and when change in the gradient measurement is no longer be detected. The flow within the first zone may be adjusted when a continuous change in the gradient measurement is detected after the predetermined amount of time has elapsed. Performing the automated flow control device sequence may include closing or adjusting a fluid flow through at least one flow control device in each of the zones in a predetermined sequence. Performing the flow control device sequence in the plurality of zones may also include transmitting a command signal to a first zone of the plurality zones. Performing the automated flow control device sequence in the plurality of zones of the wellbore when the gradient measurement exceeds or drops below the predetermined threshold to provide the plurality of stabilized gradient measurements may include comparing the gradient measurement to the predetermined threshold in real time. Performing the automated flow control device sequence in the plurality of zones of the wellbore when the gradient measurement exceeds or drops below the predetermined threshold to provide the plurality of stabilized gradient measurements may also comparing the gradient measurement to the predetermined threshold in real time.

[0055] According to certain embodiments, the method 300 may also include normalizing the gradient measurement based on the stabilized gradient measurements to provide a fluid characteristic for each of the zones, as at 310. Normalizing the gradient measurement based on the stabilized gradient measurements to provide the fluid characteristic for each of the zones may include normalizing the gradient measurement based on the stabilized gradient measurement while the flow within the first zone is stopped and the stabilized gradient measurement while the flow within the further zone is stopped. Normalizing the gradient measurement based on the stabilized gradient measurements to provide the fluid characteristic of each of the zones may include defining a normalization value corresponding to oil, a normalization value corresponding to water, and a normalization value corresponding to gas. Normalizing the gradient measurement based on the stabilized gradient measurements to provide the fluid characteristic of each of the zones may include comparing the stabilized gradient measurements for each of the zones to the defined normalization values corresponding to oil, water, and gas. The fluid characteristic for each of the zones may include a percentage of oil, gas, and / or water within a flow corresponding to each of the zones.

[0056] In certain embodiments, the method 300 may also include performing an action based on the fluid characteristic of each of the zones, as at 312. Performing the action may include generating or transmitting a signal that recommends, instructs, or causes an action to occur. The action may include a physical action. The physical action may include displaying the fluid characteristic for each zone on a display, adjusting a fluid flow through the wellbore, adjusting a flow through at least one flow control device in at least one of the zones until the gradient measurement is equal to or within a predetermined range of the oil gradient, or a combination thereof. For example, the action may include sending a command to close or open the down hole flow control device of a specific zone or multiple zones in small increments to achieve the desired oil gradient or to optimize a flow potential when all the zones are producing unwanted fluids.Exemplary Computing System

[0057] In some embodiments, the methods of the present disclosure may be executed by a computing system. FIG. 4 illustrates an example of such a computing system 400, in accordance with some embodiments. The computing system 400 may include a computer or computer system 401A, which may be an individual computer system 401A or an arrangement of distributed computer systems. The computer system 401A includes one or more analysis modules 402 that are configured to perform various tasks according to some embodiments, such as one or more methods disclosed herein. To perform these various tasks, the analysis module 402 executes independently, or in coordination with, one or more processors 404, which is (or are) connected to one or more storage media 406. The processor(s) 404 is (or are) also connected to a network interface 407 to allow the computer system 401A to communicate over a data network 409 with one or more additional computer systems and / or computing systems, such as 401B, 401C, and / or 401D (note that computer systems 401B, 401C and / or 401D may or may not share the same architecture as computer system 401A, and may be located in different physical locations, e.g., computer systems 401A and 401B may be located in a processing facility, while in communication with one or more computer systems such as 401C and / or 401D that are located in one or more data centers, and / or located in varying countries on different continents).

[0058] A processor may include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.

[0059] The storage media 406 may be implemented as one or more computer-readable or machine-readable storage media. Note that while in the example embodiment of FIG. 4 storage media 406 is depicted as within computer system 401A, in some embodiments, storage media 406 may be distributed within and / or across multiple internal and / or external enclosures of computing system 401A and / or additional computing systems. Storage media 406 may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), BLURAY® disks, or other types of optical storage, or other types of storage devices. Note that the instructions discussed above may be provided on one computer-readable or machine-readable storage medium, or may be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes. Such computer-readable or machine-readable storage medium or media is (are) considered to be part of an article (or article of manufacture). An article or article of manufacture may refer to any manufactured single component or multiple components. The storage medium or media may be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions may be downloaded over a network for execution.

[0060] It should be appreciated that computing system 400 is merely one example of a computing system, and that computing system 400 may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of FIG. 4, and / or computing system 400 may have a different configuration or arrangement of the components depicted in FIG. 4. The various components shown in FIG. 4 may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and / or application specific integrated circuits.

[0061] Further, the steps in the processing methods described herein may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAS, PLDs, or other appropriate devices. These modules, combinations of these modules, and / or their combination with general hardware are included within the scope of the present disclosure.

[0062] Computational interpretations, models, and / or other interpretation aids may be refined in an iterative fashion; this concept is applicable to the methods discussed herein. This may include use of feedback loops executed on an algorithmic basis, such as at a computing device (e.g., computing system 400, FIG. 4), and / or through manual control by a user who may make determinations regarding whether a given step, action, template, model, or set of curves has become sufficiently accurate for the evaluation of the risk index.

[0063] While any discussion of or citation to related art in this disclosure may or may not include some prior art references, applicant neither concedes nor acquiesces to the position that any given reference is prior art or analogous prior art.

[0064] The foregoing description, for purpose of explanation, has been described with reference to specific embodiments. However, the illustrative discussions above are not intended to be exhaustive or to limit the invention to the precise forms disclosed. Many modifications and variations are possible in view of the above teachings. The embodiments were chosen and described in order to explain the principles of the invention and its practical applications, to thereby enable others skilled in the art to utilize the invention and various embodiments with various modifications as are suited to the particular use contemplated.

[0065] Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims. It is also contemplated that various combinations or sub-combinations of the specific features and aspects of the embodiments described may be made and still fall within the scope of the disclosure. It should be understood that various features and aspects of the disclosed embodiments may be combined with, or substituted for, one another in order to form varying modes of the embodiments of the disclosure. Thus, it is intended that the scope of the disclosure herein should not be limited by the particular embodiments described above.

Claims

1. A method of optimizing production from a wellbore, the method comprising:receiving pressure data from the wellbore;determining a gradient measurement based on the received pressure data;performing an automated flow control device sequence in a plurality of zones of the wellbore when the gradient measurement exceeds or drops below a predetermined threshold to provide a plurality of stabilized gradient measurements; andnormalizing the gradient measurement based on the stabilized gradient measurements to provide a fluid characteristic for each of the zones,wherein each of the plurality of stabilized gradient measurements corresponds to one of the plurality of zones.

2. The method of claim 1, further comprising inserting a first downhole tubing gauge at a first depth within the wellbore and inserting a second downhole tubing gauge at a second depth within the wellbore.

3. The method of claim 2, wherein receiving pressure data from the wellbore comprises receiving a first pressure value from the first downhole tubing gauge and a second pressure value from the second downhole tubing gauge.

4. The method of claim 3, wherein determining the gradient measurement comprises:determining a difference between the first pressure value and the second pressure value to obtain a pressure differential between the first and second downhole tubing gauges; anddividing the pressure differential by a difference between the first depth and the second depth of the respective downhole tubing gauges.

5. The method of claim 1, wherein performing the automated flow control device sequence comprises:stopping a flow within a first zone of the plurality of zones;detecting change in the gradient measurement while the flow within the first zone is stopped;recording a stabilized gradient measurement based on the change in the gradient measurement while the flow within the first zone is stopped in a database; andresuming the flow within the first zone.

6. The method of claim 5, further comprising:stopping a flow within a further zone of the plurality of zones;detecting a further change in the gradient measurement while the flow within the further zone is stopped;recording a stabilized gradient measurement based on the further change in the gradient measurement while the flow within the further zone is stopped in the database; andresuming the flow within the further zone.

7. The method of claim 6, wherein recording the stabilized gradient measurement based on the change in the gradient measurement while the flow within the first zone is stopped in the database comprises:waiting for a predetermined amount of time to elapse; andrecording the gradient measurement as the stabilized gradient measurement when the predetermined amount of time has elapsed and when change in the gradient measurement is no longer be detected.

8. The method of claim 7, further comprising adjusting the flow within the first zone when a continuous change in the gradient measurement is detected after the predetermined amount of time has elapsed.

9. The method of claim 6, wherein normalizing the gradient measurement based on the stabilized gradient measurements to provide the fluid characteristic for each of the zones comprises normalizing the gradient measurement based on the stabilized gradient measurement while the flow within the first zone is stopped and the stabilized gradient measurement while the flow within the further zone is stopped.

10. The method of claim 1, further comprising performing an action based on the fluid characteristic for each of the zones.

11. A computing system, comprising:one or more processors; anda memory system comprising one or more non-transitory computer-readable media storing instructions that, when executed by at least one of the one or more processors, cause the computing system to perform operations, the operations comprising:receiving pressure data from a wellbore;determining a gradient measurement based on the received pressure data;performing an automated flow control device sequence in a plurality of zones of the wellbore when the gradient measurement exceeds or drops below a predetermined threshold to provide a plurality of stabilized gradient measurements; andnormalizing the gradient measurement based on the stabilized gradient measurements to provide a fluid characteristic for each of the zones,wherein each of the plurality of stabilized gradient measurements corresponds to one of the plurality of zones.

12. The computing system of claim 11, wherein normalizing the gradient measurement based on the stabilized gradient measurements to provide the fluid characteristic of each of the zones comprises defining a normalization value corresponding to oil, a normalization value corresponding to water, and a normalization value corresponding to gas.

13. The computing system of claim 12, wherein normalizing the gradient measurement based on the stabilized gradient measurements to provide the fluid characteristic of each of the zones comprises comparing the stabilized gradient measurements for each of the zones to the defined normalization values corresponding to oil, water, and gas.

14. The computing system of claim 11, wherein performing the automated flow control device sequence comprises closing or adjusting a fluid flow through at least one flow control device in each of the zones in a predetermined sequence.

15. The computing system of claim 11, wherein performing the automated flow control device sequence in the plurality of zones comprises transmitting a command signal to a first zone of the plurality zones.

16. The computing system of claim 11, wherein determining the gradient measurement based on the received pressure data comprises determining the gradient measurement in real time.

17. The computing system of claim 11, wherein the fluid characteristic for each of the zones comprises a percentage of oil, gas, and / or water within a flow corresponding to each of the zones.

18. The computing system of claim 11, wherein performing the automated flow control device sequence in the plurality of zones of the wellbore when the gradient measurement exceeds or drops below the predetermined threshold to provide the plurality of stabilized gradient measurements comprises comparing the gradient measurement to the predetermined threshold in real time.

19. The computing system of claim 11, wherein the operations further comprise performing an action based on the fluid characteristic of each of the zones, wherein performing the action comprises generating or transmitting a signal that instructs or causes an action to occur, wherein the action comprises a physical action, and wherein the physical action comprises displaying the fluid characteristic for each zone on a display, adjusting a fluid flow through the wellbore, adjusting a flow through at least one flow control device in at least one of the zones until the gradient measurement is equal to or within a predetermined range of the oil gradient, or a combination thereof.

20. A non-transitory computer-readable medium storing instructions that, when executed by one or more processors of a computing system, cause the computing system to perform operations, the operations comprising:receiving pressure data from a wellbore;determining a gradient measurement based on the received pressure data;performing an automated flow control device sequence in a plurality of zones of the wellbore when the gradient measurement exceeds or drops below a predetermined threshold to provide a plurality of stabilized gradient measurements; andnormalizing the gradient measurement based on the stabilized gradient measurements to provide a fluid characteristic for each of the zones,wherein each of the plurality of stabilized gradient measurements corresponds to one of the plurality of zones.

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