Coloring full waveform modelling

Abstract

A method for coloring full waveform modelling may include running first and second modelling experiments that represent a first and a second seismic wavefield, respectively, where the first and second seismic wavefields differ from one another. The method may also include identifying a wavefield event at a particular time step in the first modelling experiment and / or a region of interest in the first modelling experiment, creating a model attribute that discriminates the wavefield event and / or the region of interest from a remainder of a model in the first modelling experiment and multiplying the model attribute with at least a portion of the second seismic wavefield. The method may also include dividing the second seismic wavefield by the first seismic wavefield to produce an estimated wavefield attribute and separating the first seismic wavefield using the estimated wavefield attribute to produce a separated first seismic wavefield.

Description

PATENT Attorney Docket No.: IS24.1032-US-NPCOLORING FULL WAVEFORM MODELLINGCross-Reference to Related Applications

[0001] This application claims priority to U.S. Provisional Patent Application No. 63 / 733,018, filed on December 12, 2024, which is incorporated by reference in its entirety.Background

[0002] Seismic full waveform modelling (FWM) is a common tool for surveys, design, and modelling (SDM), as well as at the core of many imaging and inversion algorithms, such as reverse-time migration (RTM) and full waveform inversion (FWI). Unlike ray-tracing based approaches, where isolated events can be modelled, wavefields generated from FWM contain multiple initiated events at once (e.g., diving waves, reflections, and the like), look complicated, and are often difficult to interpret / track specific events of interest throughout space and time. Similar difficulties exist in interpreting seismograms extracted for a specific source and receiver acquisition geometry. For example, it is challenging to identify all events in seismograms whose wavepaths interact with a particular region of interest in the earth model. This challenge can make it difficult to interpret FWI data residuals when performing model updates in targeted regions of interest (e.g., four-dimensional (4D) reservoir FWI). A way to identify events of interest in the model space, tracking their progression over time, and linking to the recorded data would be useful. A particular use case would be in identifying appropriate, reasonably sparse, field acquisitions for a region of interest within the earth model and optimizing data apertures for inversions.

[0003] Current systems include double migration methods in which two migrations are computed with the same data, the second one involving a migration operator multiplied by the specular reflection angle. The division of the two migrated images gives the specular angle along the reflectors. In this attribute migration system, the attribute is the specular reflection angle. Other systems include offset as the attribute to migrate. The division is performed after forming images, not during formation of the images at imaging time steps, and the approach is limited in the presence of multi-arrivals.PATENT Attorney Docket No.: IS24.1032-US-NPSummary

[0004] The present disclosure includes a method for coloring full waveform modelling. The method may include running a first modelling experiment representing a first seismic wavefield and running a second modelling experiment representing a second seismic wavefield, where the first and second seismic wavefields differ from one another. The method may also include identifying (1) a wavefield event at a particular time step in the first modelling experiment and / or (2) a region of interest in the first modelling experiment and creating a model attribute that discriminates the wavefield event and / or the region of interest from a remainder of a model in the first modelling experiment. The method may further include multiplying the model attribute with at least a portion of the second seismic wavefield, dividing the second seismic wavefield by the first seismic wavefield to produce an estimated wavefield attribute, and separating the first seismic wavefield using the estimated wavefield attribute to produce a separated first seismic wavefield.

[0005] The present disclosure also includes a computing system. The computing system may include one or more processors and a memory system. The memory system may include 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 running a first modelling experiment representing a first seismic wavefield and running a second modelling experiment representing a second seismic wavefield, where the first and second seismic wavefields differ from one another. The first and second modelling experiments may be run in lockstep. Boundary values may be identical in the first and second modelling experiments and may include an injection of a seismic source. Earth model parameters may be identical in the first and second modelling experiments and may include compressional velocity, shear velocity, anisotropic parameters, or a combination thereof. The operations may also include identifying (1) a wavefield event at a particular time step in the first modelling experiment and / or (2) a region of interest in the first modelling experiment and creating a model attribute that discriminates the wavefield event and / or the region of interest from a remainder of a model in the first modelling experiment. The operations may further include multiplying the model attribute with at least a portion of the second seismic wavefield that describes a state of a numerical scheme of the second modelling experiment and dividing the second seismic wavefield by the first seismic wavefield to produce an estimated wavefield attribute. The operations may also include separatingPATENT Attorney Docket No.: IS24.1032-US-NPthe first seismic wavefield using the estimated wavefield attribute and displaying the separated first seismic wavefield.

[0006] The present disclosure further includes 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 may include running a first modelling experiment representing a first seismic wavefield and running a second modelling experiment representing a second seismic wavefield, where the first and second seismic wavefields may differ from one another, boundary values may be identical in the first and second modelling experiments, and earth model parameters may be identical in the first and second modelling experiments. The operations may include identifying (1) a wavefield event at a particular time step in the first modelling experiment and / or (2) a region of interest in the first modelling experiment, where the wavefield event may include a packet of energy in the first seismic wavefield, and the region of interest may include a region of an earth model. The operations may include creating a model attribute that discriminates the wavefield event and / or the region of interest from a remainder of the earth model. The operations may further include multiplying the model attribute with the second seismic wavefield that describes a state of a numerical scheme of the second modelling experiment, where the state of the numerical scheme may include a prediction of the second seismic wavefield at a next time step based upon the second seismic wavefield at a current time step and / or a previous time step, the second seismic wavefield is interpreted as pressure, pressure and particle velocities, or particle velocities and stress tensors, and the model attribute is multiplied once in response to the wavefield event being identified at the particular time step, or at every time step in response to the region of interest being identified. The operations may also include dividing the second seismic wavefield by the first seismic wavefield to produce an estimated wavefield attribute, separating the first seismic wavefield using the estimated wavefield attribute, displaying the separated first seismic wavefield, and performing an action based upon or in response to the separated first seismic wavefield.

[0007] It will be appreciated that this summary is intended merely to introduce some aspects of the present methods, systems, and media, which are more fully described and / or claimed below. Accordingly, this summary is not intended to be limiting.PATENT Attorney Docket No.: IS24.1032-US-NPBrief Description of the Drawings

[0008] 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:

[0009] Figure 1 illustrates an example of a system that includes various management components to manage various aspects of a geologic environment, according to an embodiment.

[0010] Figures 2A-2D illustrate, respectively, a Sigsbee migration velocity model, a mask defining a region of interest, a single pick made at an early time, and a Gaussian mask, using the local dominant wavelength as the standard deviation, to define the packet of wavefield centered on the pick, according to an embodiment.

[0011] Figures 3A and 3B illustrate, respectively, wavefield coloring of energy interacting with a region of interest in the model showing a separated wavefield for increasing times, and transparent color (e.g., blue- white-red) overlay of the separated wavefield on the wavefields from the first model, according to an embodiment.

[0012] Figures 4A and 4B illustrate, respectively, coloring of a packet of wavefield energy picked at a time showing a separated wavefield for increasing times, and transparent color (blue-white-red) overlay of the separated wavefield on the wavefields from the first model, according to an embodiment.

[0013] Figures 5A and 5B illustrate, respectively, seismograms recorded for receivers spanning the top of the model having a transparent color (e g., blue-white-red) overlay of the separated wavefield seismograms on the seismograms from reference modelling shown interacting with a region of interest in the model, and picking a packet of wavefield energy, according to an embodiment.

[0014] Figure 6 is a flowchart of a method of the present disclosure, according to an embodiment.

[0015] Figure 7 illustrates a schematic view of a computing system for performing at least a portion of the method(s) described herein, according to an embodiment.Detailed Description

[0016] Reference will now be made in detail to embodiments, examples of which are illustrated in the accompanying drawings and figures. In the following detailed description, numerousPATENT Attorney Docket No.: IS24.1032-US-NPspecific details are set forth in order to provide a thorough understanding of the present disclosure. However, it will be apparent to one of ordinary skill in the art that the present disclosure may be practiced without these specific details. In other instances, well-known methods, procedures, components, circuits, and networks have not been described in detail so as not to unnecessarily obscure aspects of the embodiments.

[0017] It will also be understood that, although the terms first, second, etc. may be used herein to describe various elements, these elements should not be limited by these terms. These terms are only used to distinguish one element from another. For example, a first object or step could be termed a second object or step, and, similarly, a second object or step could be termed a first object or step, without departing from the scope of the present disclosure. The first object or step, and the second object or step, are both, objects or steps, respectively, but they are not to be considered the same object or step.

[0018] The terminology used in the description herein is for the purpose of describing particular embodiments and is not intended to be limiting. As used in this description and the appended claims, the singular forms “a,” “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will also be understood that the term “and / or” as used herein refers to and encompasses any possible combinations of one or more of the associated listed items. It will be further understood that the terms “includes,” “including,” “comprises” and / or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and / or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and / or groups thereof. Further, as used herein, the term “if’ may be construed to mean “when” or “upon” or “in response to determining” or “in response to detecting,” depending on the context.

[0019] Attention is now directed to processing procedures, methods, techniques, and workflows that are in accordance with some embodiments. Some operations in the processing procedures, methods, techniques, and workflows disclosed herein may be combined and / or the order of some operations may be changed.PATENT Attorney Docket No.: IS24.1032-US-NPSystem Overview

[0020] Figure 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).

[0021] In the example of Figure 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.

[0022] 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 can 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.

[0023] 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 can be used to instantiate object instances for use in by a program, script,PATENT Attorney Docket No.: IS24.1032-US-NPetc. For example, borehole classes may define objects for representing boreholes based on well data.

[0024] In the example of Figure 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 Figure 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.

[0025] 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 ).

[0026] 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 can 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.

[0027] 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-PATENT Attorney Docket No.: IS24.1032-US-NPstate multiphase flow simulator that incorporates the three areas of flow modeling: multiphase flow, heat transfer and fluid behavior.

[0028] 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.

[0029] 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 can 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) can 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.).

[0030] 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.).PATENT Attorney Docket No.: IS24.1032-US-NP

[0031] Figure 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 can include a framework for model building and visualization.

[0032] 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.

[0033] In the example of Figure 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 can display their data while the user interfaces 188 may provide a common look and feel for application user interface components.

[0034] As an example, the domain objects 182 can 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 display information (e.g., to display the well as part of a model).

[0035] In the example of Figure 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 can be accessed and restored using the model simulation layer 180, which can recreate instances of the relevant domain objects.PATENT Attorney Docket No.: IS24.1032-US-NP

[0036] In the example of Figure 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, Figure 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.).

[0037] Figure 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.

[0038] 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 predefined worksteps, one or more customized worksteps, etc. As an example, a workflow may be aPATENT Atorney Docket No.: IS24.1032-US-NPworkflow 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.).Coloring Full Waveform Modeling

[0039] The system and method of the present disclosure may include full waveform modelling that, after identifying events of interest or regions of interest in the model space, tracks the propagation of the wavefield associated with those events or regions over time. The system and method may execute first and second modelling experiments in tandem. An event of interest at a particular time step may be interpreted and wavefields, corresponding to the state of the numerical scheme employed, may be multiplied by an attribute that discriminates the event of interest from other events. As the numerical scheme continues to step the wavefields over time, the division of a wavefield from the second modelling experiment by the corresponding wavefield from the first modelling experiment may produce an estimate of how the attribute has propagated over time. The estimated attribute can be used to separate the event of interest from the first wavefield. By overlaying the separated wavefield (with a different color map and transparency) on top of the first wavefield, movies of wavefield progression over time can be produced that highlight movement of particular events of interest. The same can be done for seismograms to highlight recorded events. To highlight events that interact with a region of interest in the model, rather than identifying any one event, at each time step the wavefields may be multiplied by an attribute that discriminates the region of interest from the surrounding model.

[0040] The system and method can be used to design sparse monitor surveys for 4D targeted inversions (e.g. FWI), to design smart data apertures (time and space) for existing survey datasets for targeted inversions / migrations, to produce FWI visual quality checks of inversion residuals for targeted inversions, to visually inspect propagating wavefields with specific energy highlighted, and to provide the separated data as input to imaging / inversion applications.

[0041] A system of one or more computers can be configured to perform particular operations or actions by virtue of having software, firmware, hardware, or a combination of them installed on the system that in operation causes the system to perform the actions. One or more computer programs can be configured to perform particular operations or actions by virtue of includingPATENT Atorney Docket No.: IS24.1032-US-NPinstructions that, when executed by a data processing apparatus, cause the apparatus to perform the actions. One general aspect includes a method for identifying a characteristic of interest in a modelled waveform. The method may include executing a first modelling experiment and a second modelling experiment in tandem, the first model providing a reference for the second model. The second model may include an experimental model and be related to the first model, the first model and the second model having pre-selected boundary values and model parameters. The first model and the second model may be executed in lockstep at a propagation time step. The first model and the second model may be based on a first order in time or second order in a time numerical scheme, a finite-difference scheme or finite-element scheme, an acoustic scheme, an anisotropic pseudoacoustic scheme, an elastic scheme, a visco-elastic scheme, the acoustic scheme with the second order in the time numerical scheme, where a first wavefield and a second wavefield may be pressure, or pressure at previous and current time steps, the acoustic scheme with the first order in the time numerical scheme, and the first wavefield and the second wavefield may be pressure and particle velocities, or the elastic scheme with the first order in the time numerical scheme, and the first wavefield and the second wavefield are stress tensor components and particle velocities. The method also includes identifying the characteristic of interest in the modelled waveform. The characteristic includes a wavefield event at a particular time step in the first model, or the characteristic includes a region of interest in the first model. The method also includes creating an attribute that discriminates the characteristic from other characteristics in the first model. The attribute is created with smooth transitions between identifying a characteristic and a wavefield or model surrounding the characteristic. The method also includes performing a mathematical function on the second wavefield associated with the second model based on the attribute. The mathematical function includes multiplying the second wavefield by the attribute. The mathematical function is performed once when the characteristic is the wavefield event and at the time steps when the characteristic is the region of interest. The method also includes, at the time steps, obtaining an estimated wavefield attribute based on a relationship between the first wavefield from the first model and the second wavefield from the second model. The relationship includes dividing the second wavefield by the first wavefield, or the relationship includes dividing the second wavefield by the first wavefield using a local inversion in small spatial windows. The time steps are greater than the propagation time step, or the time steps are based on a frequency content of a source function. The method also includes tracking the progression of the identifiedPATENT Atorney Docket No.: IS24.1032-US-NPcharacteristic over time by separating the first wavefield based on the estimated wavefield attribute. The tracking is performed at the time steps greater than the propagation time step, or the tracking is based on the frequency content of the source function. Other embodiments of this aspect include corresponding computer systems, apparatus, and computer programs recorded on one or more computer storage devices, each configured to perform the actions of the methods.

[0042] The system and method may execute a first model in tandem with a second model. In some configurations, the second model may be an experimental model. In some configurations, the first model may be a model that is chosen as representative of the situation being modelled, referred to herein as a reference model. An event of interest at a particular time step can be interpreted, and wavefields, corresponding to the state of the numerical scheme employed, can be multiplied by an attribute that discriminates the event of interest from other events. As the numerical scheme continues to step the wavefields over time, the division of a wavefield from the second modelling experiment by the corresponding wavefield from the first modelling experiment may produce an estimate of how the attribute has propagated over time. The estimated attribute can be used to separate the event of interest from the representative wavefield. By overlaying the separated wavefield having a different color map and transparency on top of the representative wavefield, movies of wavefield progression over time can be produced that highlight movement of particular events of interest. This process can be performed for seismograms to highlight recorded events. To highlight all events that interacted with a region of interest in the model, rather than identifying any one event, the wavefields may be multiplied at time steps by an attribute that discriminates the region of interest from the surrounding model. The system and method can be used to, for example, but not limited to, implement isotropic acoustic FWM using a finite-difference scheme, a finite-element scheme, a spectral element scheme, an anisotropic pseudoacoustic scheme, other time-stepping numerical schemes, or other physics schemes.

[0043] A difference between the system and method in accordance with embodiments of the present disclosure and the concept of attribute migration is the division of wavefields at selected time steps, for example, but not limited to, a recording time sample rate. Attribute migration refers to computing two migrations with the same data, the second one involving the original data multiplied by some attribute. In this double migration method, two migrations may be computed with the same data, the second one involving a migration operator multiplied by an attribute, in some cases, a specular reflection angle. The division of the two migrated images then may give anPATENT Atorney Docket No.: IS24.1032-US-NPimage of specular angle along the reflectors. When offset is the atribute, surface offset gathers (SOGs) from wavefield extrapolation migration may be produced when data traces are scaled by their offset for a second migration. After the division, the estimated offset at each spatial location in the image may be used to bin the original image to produce SOGs.

[0044] In the system and method of the present disclosure, wavefields from a reference modelling experiment and a second modified modelling experiment may be divided. In some configurations, a scalar acoustic wave equation with a second-order in time numerical scheme may be modeled. The state of the numerical scheme may be defined by two pressure wavefields at any time, Pt(x) and Pt-At(x), where x, t and At define spatial location, time and the propagation time step, respectively. A second modelling experiment with the same model and boundary values may be executed to calculate pressure wavefields denoted Qt(x) and Qt-Δt(x) A weight, w(x, t) that discriminates events of interest may be developed. For example, to choose an event in a wavefield at a particular time, t*, during propagation, then w(x, t ≠ t*) = 1.0. In another example, to choose a region of interest in the model to determine the parts of the wavefield that interact with that region of interest, then w(x, t) = w(x). Choice of weight is not limited to these examples. At time steps of the numerical FWM scheme, the state of the second modelling experiment may be multiplied by w(x, t). That is, Qt(x) = Qt(x) x w(x, t) and Qt+Δt(x) = Qt+Δt(x) × w(x, t). At time steps where the wavefield is to be separated, the weight may be estimated by dividing the wavefields from the two experiments:ŵ(x,t) = (1)In some configurations, the division in equation (1) may be implemented as a local L2 inversion within small spatial windows.

[0045] The estimated weight may be used to separate the wavefield Pt(x) from the reference modelling experiment in the single arrival situation. With respect to a single point in space and time with multi-arrivals,St -i i / / h ai ’which is a weighted average where the weights are data amplitudes, {aᵢ}.PATENT Atorney Docket No.: IS24.1032-US-NP

[0046] Referring now to Figure 2A, the FWM of a point source in the Sigsbee migration velocity model is shown in which a finite-difference modelling scheme is shown. In the model, the source function is sparse and the model is relatively smooth, other than the water bottom and salt body. A Ricker wavelet with a peak frequency of 10Hz is injected at the top of the model in the center. Two experiments propagating for 6s are conducted.

[0047] Referring now to Figure 2B, in the first experiment, a region of interest in the model has been identified, and the propagating wavefield is separated based on energy that has interacted with the region of interest.

[0048] Referring now to Figure 2C, in the second experiment, a packet of energy in a wavefield snapshot at a particular time is identified. The energy from the wavefields is separated as the packet of energy propagates forward in time.

[0049] Referring now to Figure 2D, a choice is made and a Gaussian weighted mask is centered on the choice, where the standard deviation is set to be the dominant local wavelength. The masks displayed in Figures 2A-2D are converted to the weight in which weight = 1.0- mask. The weight is estimated through the division of the two wavefields and is used to separate the wavefield by checking for deviations from 1.0.

[0050] Referring now to Figures 3A-3B and 4A-4B, the results for the two experiments are displayed. The separated wavefield is illustrated for increasing times as well as a corresponding transparent color (blue-white-red) overlay of the separated wavefield on the wavefields from the reference modelling.

[0051] Referring now to Figures 5A and 5B, seismograms recorded from placing receivers spanning the top of the model are shown. A transparent color (e.g., blue-white-red) overlay of the separated wavefield seismograms on the seismograms from reference modelling is shown. Figure 5A presents interaction with a region of interest while Figure 5B illustrates picking a packet of wavefield energy.

[0052] In some configurations, the wavelength separation is performed at a time step, and controlled by the frequency content of the data to be recorded. In some configurations, the two modelling experiments can be executed to completion independently. When the wavefields are separated using a fixed weight, w(x, t) = w(x), in some configurations, a visco-elastic propagator is executed in conjunction with a reference propagator and differencing the results. The seismic Q model is set with a near zero value for seismic Q in the region of interest and smoothed heavily toPATENT Atorney Docket No.: IS24.1032-US-NPavoid creating additional reflections / artifacts in the subtraction. The propagator itself has the capability to model amplitude attenuation, switching off attenuation phase effects. Amplitude differences occur for energy interacting solely with the extended region from the smoothing. Using a seismic Q propagator together with the weight estimation described herein to select the wavefield is possible. When w(x, t) varies over the simulation time period, earth model properties such as seismic Q can vary in a time-variant manner.

[0053] The examples described herein focus on implementing isotropic acoustic FWM using a finite-difference scheme. The system and method are applicable to time-stepping numerical schemes (e.g. finite-element, spectral element) as well as to more complicated physics (e g. anisotropic pseudo-acoustic).Exemplary Method

[0054] Figure 6 illustrates a flowchart of a method 600 for coloring full waveform modelling, according to an embodiment. An illustrative order of the method 600 is provided below; however, one or more portions of the method 600 may be performed in a different order, simultaneously, repeated, or omitted. At least a portion of the method 600 may be performed using a computing system.

[0055] The method 600 may include running 605 a first modelling experiment representing a first seismic wavefield.

[0056] The method 600 may also include identifying 610 (1) a wavefield event at a particular time step in the first modelling experiment and / or (2) a region of interest in the first modelling experiment. The wavefield event may include a packet of energy in the first seismic wavefield. The region of interest may include a region of an earth model.

[0057] The method 600 may also include creating 615 a model attribute that discriminates the wavefield event and / or the region of interest from a remainder of a model in the first modelling experiment. The model attribute may include a weight between 0 and 1, inclusive. The model attribute may be created with smooth transitions between the identified wavefield event or the region of interest and the remainder of the earth model.

[0058] The method 600 may also include running 620 a second modelling experiment representing a second seismic wavefield. The first and second seismic wavefields may differ from one another. In an embodiment, the first and second modelling experiments may be run in lockstepPATENT Atorney Docket No.: IS24.1032-US-NPat a propagation time step. In another embodiment, the second modelling experiment may be run after the first modelling experiment and / or after the model attribute is created. The boundary values may be identical in the first and second modelling experiments. The boundary values may include an injection of a seismic source. Earth model parameters may be identical in the first and second modelling experiments. The earth model parameters may include compressional velocity, shear velocity, anisotropic parameters, or a combination thereof. The first and second modelling experiments may be run with a first or second order in time numerical scheme. The first and second modelling experiments may be run with a finite-difference scheme or a finite-element scheme. The first and second modelling experiments may be acoustic, anisotropic pseudo-acoustic, elastic, or visco-elastic.

[0059] The method 600 may also include multiplying 625 the model attribute with at least a portion of the second seismic wavefield. The second seismic wavefield may describe a state of a numerical scheme of the second modelling experiment. The state of the numerical scheme may include a prediction of one of the second seismic wavefield at a next time step based upon the second seismic wavefield at a current time step and / or a previous time step. The second seismic wavefield may be interpreted as pressure, pressure and particle velocities, or particle velocities and stress tensors The model attribute may be multiplied once in response to the wavefield event being identified at the particular time step or may be multiplied at every time step in response to the region of interest being identified.

[0060] The method 600 may also include, at later time steps, dividing 630 the second seismic wavefield by the first seismic wavefield to produce an estimated wavefield attribute. The second seismic wavefield may be divided at each time step or time steps that are larger than the propagation time step, where the larger time steps are related to a frequency content of a source function. The second seismic wavefield may be interpreted as pressure. The dividing may be performed as a local inversion in small spatial windows.

[0061] The method 600 may also include separating 635 the first seismic wavefield using the estimated wavefield attribute.

[0062] The method 600 may also include displaying 640 the separated first seismic wavefield. The displaying may include overlaying the separated first seismic wavefield on top of the first seismic wavefield with a different color scheme.PATENT Atorney Docket No.: IS24.1032-US-NP

[0063] The method 600 may also include performing 645 an action based upon or in response to the separated first seismic wavefield. The action may include changing a position of an acquisition system to capture the energy. The action may also or instead include inputting the separated first seismic wavefield into an imaging application and / or an inversion application. In an embodiment, the action may be or include generating and / or transmitting a signal (e.g., using a computing system) that recommends, instructs, or causes a physical action to occur. In an example, the physical action may include selecting where to drill a wellbore, drilling the wellbore, varying a weight and / or torque on a drill bit that is drilling the wellbore, varying a drilling trajectory of the wellbore, varying a concentration and / or flow rate of a fluid pumped into the wellbore, or the like.

[0064] In some embodiments, the methods of the present disclosure may be executed by a computing system. Figure 7 illustrates an example of such a computing system 700, in accordance with some embodiments. The computing system 700 may include a computer or computer system 701 A, which may be an individual computer system 701 A or an arrangement of distributed computer systems. The computer system 701 A includes one or more analysis modules 702 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 702 executes independently, or in coordination with, one or more processors 704, which is (or are) connected to one or more storage media 706. The processor(s) 704 is (or are) also connected to a network interface 707 to allow the computer system 701 A to communicate over a data network 709 with one or more additional computer systems and / or computing systems, such as 701B, 701C, and / or 701D (note that computer systems 701B, 701C and / or 701D may or may not share the same architecture as computer system 701A, and may be located in different physical locations, e.g., computer systems 701 A and 701B may be located in a processing facility, while in communication with one or more computer systems such as 701 C and / or 70 ID that are located in one or more data centers, and / or located in varying countries on different continents).

[0065] A processor may include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.

[0066] The storage media 706 may be implemented as one or more computer-readable or machine-readable storage media. Note that while in the example embodiment of Figure 7 storagePATENT Atorney Docket No.: IS24.1032-US-NPmedia 706 is depicted as within computer system 701 A, in some embodiments, storage media 706 may be distributed within and / or across multiple internal and / or external enclosures of computing system 701A and / or additional computing systems. Storage media 706 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.

[0067] In some embodiments, computing system 700 contains one or more method execution module(s) 708. In the example of computing system 700, computer system 701A includes the method execution module 708. In some embodiments, a single method execution module may be used to perform some aspects of one or more embodiments of the methods disclosed herein. In other embodiments, a plurality of method execution modules may be used to perform some aspects of methods herein.

[0068] It should be appreciated that computing system 700 is merely one example of a computing system, and that computing system 700 may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of Figure 7, and / or computing system 700 may have a different configuration or arrangement of the components depicted in Figure 7. The various components shown in Figure 7 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.PATENT Atorney Docket No.: IS24.1032-US-NP

[0069] 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.

[0070] 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 700, Figure 7), 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 subsurface three-dimensional geologic formation under consideration.

[0071] 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 limiting to the precise forms disclosed. Many modifications and variations are possible in view of the above teachings. Moreover, the order in which the elements of the methods described herein are illustrated and described may be re-arranged, and / or two or more elements may occur simultaneously. The embodiments were chosen and described in order to best explain the principles of the disclosure and its practical applications, to thereby enable others skilled in the art to best utilize the disclosed embodiments and various embodiments with various modifications as are suited to the particular use contemplated.

Claims

PATENT Attorney Docket No.: IS24.1032-US-NPCLAIMSWhat is claimed is:

1. A method for coloring full waveform modelling, the method comprising:running a first modelling experiment representing a first seismic wavefield;running a second modelling experiment representing a second seismic wavefield, wherein the first and second seismic wavefields differ from one another;identifying (1) a wavefield event at a particular time step in the first modelling experiment and / or (2) a region of interest in the first modelling experiment; andcreating a model attribute that discriminates the wavefield event and / or the region of interest from a remainder of a model in the first modelling experiment.

2. The method of claim 1, wherein the first and second modelling experiments are run in lockstep at a propagation time step, and wherein earth model parameters are identical in the first and second modelling experiments.

3. The method of claim 2, wherein the earth model parameters comprise compressional velocity, shear velocity, anisotropic parameters, or a combination thereof.

4. The method of claim 1, wherein boundary values are identical in the first and second modelling experiments, and wherein the boundary values comprise an injection of a seismic source.

5. The method of claim 1, wherein:the model attribute comprises a weight between 0 and 1, inclusive, andthe model attribute is created with smooth transitions between the identified wavefield event or the region of interest and the remainder of the earth model.

6. The method of claim 1, further comprising:multiplying the model attribute with at least a portion of the second seismic wavefield;PATENT Attorney Docket No.: IS24.1032-US-NPdividing the second seismic wavefield by the first seismic wavefield to produce an estimated wavefield attribute; andseparating the first seismic wavefield using the estimated wavefield attribute to produce a separated first seismic wavefield.

7. 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:running a first modelling experiment representing a first seismic wavefield; running a second modelling experiment representing a second seismic wavefield, wherein:the first and second seismic wavefields differ from one another, the first and second modelling experiments are run in lockstep, boundary values are identical in the first and second modelling experiments and comprise an injection of a seismic source, andearth model parameters are identical in the first and second modelling experiments and comprise compressional velocity, shear velocity, anisotropic parameters, or a combination thereof;identifying (1) a wavefield event at a particular time step in the first modelling experiment and / or (2) a region of interest in the first modelling experiment;creating a model attribute that discriminates the wavefield event and / or the region of interest from a remainder of a model in the first modelling experiment;multiplying the model attribute with at least a portion of the second seismic wavefield that describes a state of a numerical scheme of the second modelling experiment;dividing the second seismic wavefield by the first seismic wavefield to produce an estimated wavefield attribute;separating the first seismic wavefield using the estimated wavefield attribute; and displaying the separated first seismic wavefield.PATENT Attorney Docket No.: IS24.1032-US-NP8. The computing system of claim 7, wherein the first and second modelling experiments are run with a first or second order in time numerical scheme.

9. The computing system of claim 7, wherein the first and second modelling experiments are run with a finite-difference scheme or a finite-element scheme.

10. The computing system of claim 7, wherein the first and second modelling experiments are acoustic, anisotropic pseudo-acoustic, elastic, or visco-elastic.

11. The computing system of claim 7, wherein the state of the numerical scheme comprises a prediction of the second seismic wavefield at a next time step based upon the second seismic wavefield at a current time step and / or a previous time step.

12. The computing system of claim 7, wherein the second seismic wavefield is interpreted as pressure, pressure and particle velocities, or particle velocities and stress tensors.

13. The computing system of claim 7, wherein the model attribute is multiplied:once in response to the wavefield event being identified at the particular time step, or at every time step in response to the region of interest being identified.

14. 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:running a first modelling experiment representing a first seismic wavefield;running a second modelling experiment representing a second seismic wavefield, wherein:the first and second seismic wavefields differ from one another,boundary values are identical in the first and second modelling experiments, and earth model parameters are identical in the first and second modelling experiments; identifying (1) a wavefield event at a particular time step in the first modelling experiment and / or (2) a region of interest in the first modelling experiment, wherein:the wavefield event comprises a packet of energy in the first seismic wavefield, andPATENT Attorney Docket No.: IS24.1032-US-NPthe region of interest comprises a region of an earth model;creating a model attribute that discriminates the wavefield event and / or the region of interest from a remainder of the earth model;multiplying the model attribute with the second seismic wavefield that describes a state of a numerical scheme of the second modelling experiment, wherein:the state of the numerical scheme comprises a prediction of the second seismic wavefield at a next time step based upon the second seismic wavefield at a current time step and / or a previous time step,the second seismic wavefield is interpreted as pressure, pressure and particle velocities, or particle velocities and stress tensors, andthe model attribute is multiplied:once in response to the wavefield event being identified at the particular time step, orat every time step in response to the region of interest being identified; dividing the second seismic wavefield by the first seismic wavefield to produce an estimated wavefield attribute;separating the first seismic wavefield using the estimated wavefield attribute; displaying the separated first seismic wavefield; andperforming an action based upon or in response to the separated first seismic wavefield.

15. The non-transitory computer-readable medium of claim 14, wherein the second seismic wavefield is divided at each time step or time steps that are larger than a propagation time step, and wherein the larger time steps are related to a frequency content of a source function.

16. The non-transitory computer-readable medium of claim 14, wherein the second seismic wavefield is interpreted as pressure.

17. The non-transitory computer-readable medium of claim 14, wherein the dividing is performed as a local inversion in small spatial windows.PATENT Attorney Docket No.: IS24.1032-US-NP18. The non-transitory computer-readable medium of claim 14, wherein displaying comprises overlaying the separated first seismic wavefield on top of the first seismic wavefield with a different color scheme.

19. The non-transitory computer-readable medium of claim 14, wherein the action comprises changing a position of an acquisition system to capture the energy.

20. The non-transitory computer-readable medium of claim 14, further comprising inputting the separated first seismic wavefield into an imaging application and / or an inversion application.

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