Patent Application
20150219779
Operations, such as surveying, drilling, wireline testing, completions, production, planning and field analysis, may be performed to locate and gather valuable downhole fluids. Surveys are often performed using acquisition methodologies, such as seismic scanners or surveyors to generate maps of underground formations. These formations are often analyzed to determine the presence of subterranean assets, such as valuable fluids or minerals, or to determine if the formations have characteristics suitable for storing fluids. The subterranean assets are not limited to hydrocarbon such as oil, throughout this document, the terms “oilfield” and “oilfield operation” may be used interchangeably with the terms “field” and “field operation” to refer to a field having any types of valuable fluids or minerals and field operations relating to any of such subterranean assets.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
In general, in one aspect, one or more embodiments relate to seismic interpretation. A seismic volume of a subterranean formation of a field is obtained. The seismic volume includes a set of seismic traces of the subterranean formation. Through the seismic volume based on a similarity criterion of seismic values in the set of seismic traces, an estimated horizon is generated based on a selected seed while maintaining tracking data tracking the generating of the estimated horizon. A first selection of a selected point in the estimated horizon is received, and, from the tracking data, an ancestral path from the selected point to the selected seed is extracted. The ancestral path includes a sequence of derived points that are recursively derived from the selected seed based on the similarity criterion. A subset of the set of seismic traces is selected based on the subset comprising points along the ancestral path, and displayed, within a graphic window on a physical display, the subset of the set of seismic traces. The subset of the set of seismic traces is annotated with the ancestral path.
The appended drawings illustrate several embodiments of quality control of 3D horizon auto-tracking in seismic volume and are not to be considered limiting of its scope, for quality control of 3D horizon auto-tracking in seismic volume may admit to other equally effective embodiments.
Embodiments are shown in the above-identified drawings and described below. In describing the embodiments, like or identical reference numerals are used to identify common or similar elements. The drawings are not necessarily to scale and certain features and certain views of the drawings may be shown exaggerated in scale or in schematic in the interest of clarity and conciseness.
During the field operations, data may be collected for analysis and/or monitoring of the operations. Such data may include, for instance, information regarding subterranean formations, equipment, and historical and/or other data. Data concerning the subterranean formation may be collected using a variety of sources. Such formation data may be static or dynamic. Static data relates to, for instance, formation structure and geological stratigraphy that define geological structures of the subterranean formation. Dynamic data relates to, for instance, fluids flowing through the geologic structures of the subterranean formation over time. Such static and/or dynamic data may be collected to learn more about the formations and the valuable assets contained therein.
Collecting data may be performed using seismic surveying. Seismic surveying may be performed by imparting energy to the earth at one or more source locations, for example, by way of controlled explosion, mechanical input etc. Return energy is then measured at surface receiver locations at varying distances and azimuths from the source location. The travel time of energy from source to receiver, via reflections and refractions from interfaces of subsurface strata, indicates the depth and orientation of such strata. Seismic data, as collected via the receiver, within a volume of interest may be referred to as seismic volume. A seismic volume may be displayed as seismic images based on different sampling resolutions and viewing orientations as well as subject to various different seismic amplitude processing techniques to enhance or highlight seismic reflection patterns.
The data may be used to predict downhole conditions and make decisions concerning field operations. Such decisions may involve well planning, well targeting, well completions, operating levels, production rates and other operations and/or operating parameters. A large number of variables and large quantities of data to consider in analyzing field operations may exist. Because of the large number of variables and large quantities of data, modeling the behavior of the field operation to determine the desired course of action may be useful. Various aspects of field operations, such as geological structures, downhole reservoirs, wellbores, surface facilities, as well as other portions of the field operation, may be modeled. The modeling may be used to perform field operations. Further, during the ongoing operations, the operating parameters may be adjusted as field conditions change and new information is received.
Seismic images may indirectly show the distribution of material deposited over large areas. The spatial and/or temporal variability of stacking patterns or sequences, observed in seismic images relates to depositional environments and post-depositional processes, such as erosion and tectonic activity. In other words, reflection patterns in the seismic images link depositional environments and vertical stacking order to sequence of deposition in the subterranean formation. During seismic interpretation, relative timing of the seismic image reflection patterns enables the geological history of the subsurface to be deciphered and leads to the estimation of probable sedimentary characteristics. In this manner, a potential hydrocarbon reservoir may be identified and analyzed based on interpretation and analysis of seismic reflection data. However, performing seismic data interpretation over large seismic volumes may be a daunting task, particularly if done manually.
One aspect of seismic interpretation is picking subsurface horizons, or simply referred to as “picking”. In other words picking involves selecting points in the seismic images of the subsurface formations that correspond to a subsurface horizon. While interpreting seismic lines (that is, a two-dimensional vertical slice or a “vertical seismic section”) may be accomplished by viewing and picking one line at a time, the picking may be performed by clicking the cursor on a few selected points along a horizon and letting the machine pick the rest of the points on that line. Automated picking may increase both productivity and accuracy over manual picking. In an automatic system for tracking a bedding plane (i.e., a horizon) in a horizontal slice of three-dimensional (3D) data, a user selects or “inputs” at least one “seed point”, which is then “expanded” in four directions within the 3D data until the expanded point reached the boundaries of a user specified zone.
As shown in
In one or more embodiments, data acquisition tools (102-1), (102-2), (102-3), and (102-4) are positioned at various locations along the field (100) for collecting data of the subterranean formation (104), referred to as survey operations. In particular, these data acquisition tools are adapted to measure the subterranean formation (104) and detect the characteristics of the geological structures of the subterranean formation (104). For example, data plots (108-1), (108-2), (108-3), and (108-4) are depicted along the field (100) to demonstrate the data generated by these data acquisition tools. Specifically, the static data plot (108-1) is a seismic two-way response time. Static plot (108-2) is core sample data measured from a core sample of the formation (104). Static data plot (108-3) is a logging trace, referred to as a well log. Production decline curve or graph (108-4) is a dynamic data plot of the fluid flow rate over time. Other data may also be collected, such as historical data, user inputs, economic information, and/or other measurement data and other parameters of interest.
To capture the seismic two-way response time in the static data plot (108-1), the data acquisition tools (102-1) may be a seismic truck that is adapted to measure properties of the subterranean formation based on sound vibrations. One such sound vibration (e.g., 186, 188, 190) generated by a source (170) reflects off a plurality of horizons (e.g., 172, 174, 176) in the subterranean formation (104). Each of the sound vibrations (e.g., 186, 188, 190) are received by one or more sensors (e.g., 180, 182, 184), such as geophone-receivers, situated on the earth's surface. The geophones produce electrical output signals, which may be transmitted, for example, as input data to a computer (192) on the seismic truck (102-1). Responsive to the input data, the computer (192) may generate a seismic data output, such as the seismic two-way response time.
Further as shown in
In one or more embodiments, the surface unit (202) is operatively coupled to the data acquisition tools (102-1), (102-2), (102-3), (102-4), and/or the wellsite systems (204-1), (204-2), (204-3). In particular, the surface unit (202) is configured to send commands to the data acquisition tools (102-1), (102-2), (102-3), (102-4), and/or the wellsite systems (204-1), (204-2), (204-3) and to receive data therefrom. In one or more embodiments, the surface unit (202) may be located at the wellsite systems (204-1), (204-2), (204-3) and/or remote locations. The surface unit (202) may be provided with computer facilities for receiving, storing, processing, and/or analyzing data from the data acquisition tools (102-1), (102-2), (102-3), (102-4), the wellsite systems (204-1), (204-2), (204-3), and/or other part of the field (100). The surface unit (202) may also be provided with or functionally for actuating mechanisms at the field (100). The surface unit (202) may then send command signals to the field (100) in response to data received, for example to control and/or optimize various field operations described above.
In one or more embodiments, the surface unit (202) is communicatively coupled to an E&P computer system (208). In one or more embodiments, the data received by the surface unit (202) may be sent to the E&P computer system (208) for further analysis. Generally, the E&P computer system (208) is configured to analyze, model, control, optimize, or perform management tasks of the aforementioned field operations based on the data provided from the surface unit (202). In one or more embodiments, the E&P computer system (208) is provided with functionality for manipulating and analyzing the data, such as performing seismic interpretation or borehole resistivity image log interpretation to identify geological surfaces in the subterranean formation (104) or performing simulation, planning, and optimization of production operations of the wellsite systems (204-1), (204-2), (204-3). In one or more embodiments, the result generated by the E&P computer system (208) may be displayed for user viewing using a two-dimensional (2D) display, 3D display, or other suitable displays. Although the surface unit (202) is shown as separate from the E&P computer system (208) in
As shown in
In one or more embodiments, the seismic traces (e.g., data plot (108-1) depicted in
Within the 3D volume, the seismic traces may be represented as vertical lines of seismic amplitude versus time or distance along the Z-axis of the 3D volume. In other words, a 3D volume may be, at least in part, composed of seismic traces. A seismic trace represents the response of the elastic wave field to velocity and density contrasts across interfaces of layers of rock or sediments as energy travels from a source through the subsurface to a receiver or receiver array. Specifically, each individual trace is a representation of seismic amplitude versus time of an acoustic reflection from geological structures in the subterranean formation. For example, the seismic amplitude may be represented as color or shading pattern, while the time progression may be represented by the vertical line through the seismic volume. Other representations of seismic traces may be used without departing from the scope of one or more embodiments. A seismic trace in a sequence along the X direction is referred to as a “line” or “in-line” in seismic interpretation. A seismic trace in a sequence along the Y direction is referred to as a “cross-line.” A “horizon slice” is a slice (i.e., either a flat surface or a non-planar surface) in the 3D volume that is identified by the seismic interpretation user as corresponding to a horizon (e.g., one of the horizons (172, 174, 176)) in the subterranean formation (104) depicted in
In one or more embodiments, the 3D horizon auto-tracking tool (230) is configured to facilitate seismic interpretation to identify a horizon slice from the seismic volume (227) as an interpreted horizon (e.g., the interpreted horizon (229)). Specifically, the interpreted horizon, also referred to as an estimated horizon, is a 2D surface in the seismic volume (227) that estimates locations of the horizon in the subterranean formation. As shown in
In one or more embodiments, the seismic interpretation user selects at least one seed point in a seismic trace of the 3D volume. In other words, the seismic interpretation user considers the selected seed point to approximate where the seismic trace intersects the target horizon being identified. Using a pre-determined auto-tracking algorithm, the 3D auto-tracking module (222) expands the user selected seed point in four directions along potentially varying depths within the 3D volume until reaching the boundaries of a user specified zone. Specifically, neighboring un-interpreted seismic traces near each seed point may be evaluated based on certain criteria (referred to as auto-tracking criteria), such as signal similarity within a certain time/depth window. A candidate pick is selected at the time/depth location of neighbor traces if the auto-tracking criteria are satisfied. In other words, the time/depth location of neighbor traces is picked to approximate where the neighbor traces intersect with the target horizon being identified. Once a neighboring seismic trace has been successfully interpreted (auto-tracked), the candidate pick on the neighboring seismic trace may be used as a new seed point (referred to as a derivative seed point) for subsequent traces. The auto-tracking algorithm may continue to process the nearest neighbor traces until the traces in the user specified zone are either interpreted or rejected. In one or more embodiments, the user selected seed point(s) and the derivative seed point(s) are stored in the data repository (235) as the seeds (228). The resultant interpreted seismic traces form the interpreted horizon (229). An example of picking a subsurface horizon is depicted in
In one or more embodiments, the auto-tracking quality control module (225) provides validation of automated horizon results generated by the 3D auto-tracking module (222). The term “ancestral relationship” may refer to the order and geometry in which candidate picks are selected after successfully passing the auto-tracking criteria applied to original seeds and derivative seeds. In other words, when a derivative seed is used to select a next candidate pick, the derivative seed is in ancestral relationship with the candidate pick as the derivative seed becomes an ancestor of the next candidate pick and any subsequent picks from the next candidate pick.
In one or more embodiments, the validation results of the auto-tracking quality control module (225) are a set of unique paths through the 3D volume that connect each interpreted point back to an original seed point via the interpreted point's ancestral map. The unique paths may be referred to as an ancestral path. Each path may trace the optimum correlation through the 3D volume from original to final auto tracked value. Visually, each ancestral path may appear to the seismic interpretation user as a meandering stream from original to final auto-tracked value endpoints. The ancestral path may be used to evaluate the accuracy of the 3D auto-tracking module (222) by viewing any available seismic data in either 2D or 3D views. Changes and refinements made to the ancestral paths are then incorporated with previous inputs to become new seeds for subsequent auto-tracking operations. An example of the ancestral path is depicted in
In one or more embodiments, the 3D horizon auto-tracking tool (230) is configured to provide to the seismic interpretation user one or more displays (e.g., 2D display, 3D display, etc.) during the seismic interpretation. For example, the displays may include the seismic volume (227), the seeds (228), and the interpreted horizon (229).
In one or more embodiments, E&P computer system (208) includes the field task engine (231) that is configured to generate a field operation control signal based at least on the interpreted horizon (229). As noted above, the field operation equipment depicted in
The E&P computer system (208) may include one or more system computers, which may be implemented as a server or any conventional computing system. However, those skilled in the art, having benefit of this disclosure, will appreciate that implementations of various technologies described herein may be practiced in other computer system configurations, including hypertext transfer protocol (HTTP) servers, hand-held devices, multiprocessor systems, microprocessor-based or programmable consumer electronics, network personal computers, minicomputers, mainframe computers, and the like.
While specific components are depicted and/or described for use in the units and/or modules of the E&P computer system (208) and the 3D horizon auto-tracking tool (230), a variety of components with various functions may be used to provide the formatting, processing, utility and coordination functions for the E&P computer system (208) and the 3D horizon auto-tracking tool (230). The components may have combined functionalities and may be implemented as software, hardware, firmware, or combinations thereof.
Initially in Element 301, a seismic volume is obtained that includes a set of seismic traces of a subterranean formation of a field. For example, the set of seismic traces may be obtained from the subterranean formation using the data acquisition tool, as shown in
In Element 302, an estimated horizon is generated through the seismic volume using an auto-tracking algorithm that is based on a similarity criterion of seismic values in the set of seismic traces. In particular, a user selects one or more user selected seeds. The 3D auto-tracking module auto-tracks to select neighboring point to be candidate picks based on the auto-tracking criteria. Thus, the candidate picks are assumed to be part of an estimated horizon. The process may iteratively repeat from the candidate picks to select additional neighboring picks. In one or more embodiments, the estimated horizon is generated based on a selected seed while maintaining tracking data tracking the generating of the estimated horizon. In other words, as candidate picks are selected, tracking data is maintained. Specifically, the tracking data describes ancestral relationships among the user selected seed and auto-tracked picks generated using the auto-tracking algorithm. In one or more embodiments, the ancestral relationship is described based on an ancestral tree having ancestral paths.
In one or more embodiments, the estimated horizon is generated using the 3D auto-tracking module (222) depicted in
In Element 303, an ancestral path is extracted from the tracking data. Specifically, the ancestral path identifies intervening picks from a user selected point on the estimated horizon to the selected seed from which the estimated horizon was generated. In one or more embodiment, the ancestral path includes a sequence of derived points (i.e., auto-tracked picks) that are recursively derived from the selected seed based on the auto-tracking criterion. For example, a seismic interpretation user may select the user selected point in a study area of the estimated horizon to verify the validity of the auto-tracking results in the study area. Extracting the ancestral path may be performed by receiving the user selected point from the user. For example, the user may select the point from a display of the estimated horizon in the 3D seismic volume. When the user selects the user selected point, the tracking data is accessed to determine each precedent derivative seed in the ancestral path from that point that ultimately resulted in the user selected point being a part of the estimated horizon. An example of the ancestral path is described in reference to
In Element 304, a subset of the set of seismic traces is selected based on the subset including points along the ancestral path. In Element 305, the subset of the set of seismic traces is displayed within a graphic window on a physical display. In one or more embodiments, the subset of the set of seismic traces is annotated with the ancestral path. As noted above, the ancestral path may be a meandering path zigzagged across the estimated horizon. Accordingly, the subset of the set of seismic traces follows the meandering path and forms a folded graphical image, referred to as the ancestral path seismic section. In one or more embodiments, displaying the subset of the set of seismic traces starts with converting the folded graphical image into an unfolded graphical image on a 2D plane (i.e., a flat 2D surface). The conversion may be performed based on a spatial mapping algorithm that maps a folded coordinate system on a folded 2D surface onto a Euclidean coordinate system on the unfolded 2D plane. In other words, the folded graphical image is “stretched” flat onto the 2D surface. Accordingly, the unfolded graphical image on a 2D surface is displayed to facilitate viewing by the seismic interpretation user.
An example of the selecting and displaying the subset of seismic traces is described in reference to
In Element 306, an adjustment of the estimated horizon is received to generate a revised estimated horizon. In one or more embodiments, the adjustment includes an auto-tracked pick selected by the seismic interpretation user from the ancestral path. For example, the seismic interpretation user may select this auto-tracked pick while viewing the unfolded graphical image to verify the validity of the auto-tracking results in the study area. Specifically, this auto-tracked pick is selected by the seismic interpretation user as an error of the estimated horizon. For example, the seismic interpretation user may deem the auto-tracked pick to be an error and not reflect an actual horizon.
In one or more embodiments, the adjustment further includes an indication from the seismic interpretation user to remove a portion of the ancestral path downstream to the selected auto-tracked pick in an opposite direction from the user selected seed. In other words, any portion of the estimated horizon that is selected based on the auto-tracked pick and, therefore, has the selected auto-tracked pick in the portion's ancestral path, is removed. In addition, the seismic interpretation user may also indicate to remove an incorrect portion of the estimated horizon that is derived from the removed portion of the ancestral path. The remaining portion of the estimated horizon is referred to as the validated portion of the estimated horizon. In one or more embodiments, the validated portion of the estimated horizon is expanded into a revised estimated horizon using the auto-tracking algorithm. For example, a boundary of the validated portion of the estimated horizon is created by removing the incorrect portion of the estimated horizon. Accordingly, points along the boundary may be used as derived seeds by the auto-tracking algorithm to expand the validated portion of the estimated horizon.
In one or more embodiments, Elements 303, 304, 305, and 306 are performed using the auto-tracking quality control module (225) depicted in
In Element 307, a field operation is performed based at least on the estimated horizon and/or the revised estimated horizon. For example, the field operation may be performed using the field task engine (231) of the E&P computer system (208) depicted in
Initially in Element 311, a seismic volume is obtained that includes a set of seismic traces of a subterranean formation of a field. For example, the set of seismic traces may be obtained from the subterranean formation using the data acquisition tool, as shown in
In Element 312, an estimated horizon is generated through the seismic volume using an auto-tracking algorithm that is based on a similarity criterion of seismic values in the set of seismic traces. In one or more embodiments, the estimated horizon is generated based on a selected seed. In one or more embodiments, the estimated horizon is generated using the 3D auto-tracking module (222) depicted in
In Element 313, a grid is generated that superimposes the estimated horizon. In one or more embodiments, the grid includes grid lines along the X direction and Y direction within the seismic volume. In one or more embodiments, the resolution of the grid is specified by a seismic interpretation user. In one or more embodiments, the width of each grid line is specified by the seismic interpretation user.
In Element 314, a portion of the set of seismic traces that intersect the grid lines of the grid is displayed. Specifically, the seismic amplitudes are displayed for points within the width of each grid line.
In Element 315, in response to presenting the limited portion of the estimated horizon, an adjustment of the estimated horizon is received from the seismic interpretation user to generate a revised estimated horizon. In one or more embodiments, the adjustment includes an auto-tracking error that is identified within the limited portion of the seismic horizon by the seismic interpretation user. For example, the seismic interpretation user may inspect the entirety of the limited portion of the estimated horizon to locate the auto-tracking error. In another example, the seismic interpretation user may inspect the limited portion of the estimated horizon on a grid line by grid line basis to locate the auto-tracking error. In one or more embodiments, the portion of the grid line downstream from the auto-tracking error is marked for removal, while the portion of the grid line up stream from the auto-tracking error is marked as validated. For example, the removal portion and the validated portion may be determined based on the ancestral tree of the estimated horizon, as shown in
In Element 316, a revised estimated horizon is generated by removing the portion of the grid line marked for removal. In addition, any point on the estimated horizon that does not belong to the grid is also removed from the estimated horizon. In other words, the validated portion of each grid line of the grid is exclusively retained in the revised estimated horizon.
In Element 317, a determination is made as to whether additional iteration of estimated horizon validation is to be performed. If the determination is positive, i.e., an additional iteration is to be performed, the method proceeds to Element 318. If the determination is negative, i.e., no additional iteration is to be performed, the method proceeds to Element 319, where a field operation is performed based on the estimated revised horizon.
In Element 318, the resolution of the grid is adjusted before returning to Element 313 for the next iteration of validating the estimated horizon. For example, the resolution of the grid may be increased based on input from the seismic interpretation user.
An example of adjusting the estimated horizon to generate the revised estimated horizon is described in reference to
In Element 319, a field operation is performed based at least on the estimated horizon and/or the revised estimated horizon. For example, the field operation may be performed using the field task engine (231) of the E&P computer system (208) depicted in
Further, as shown in
As noted above, for any auto-tracked horizon point within the seismic volume (400), a unique ancestral path leading to the point A (i.e., the user selected seed) exists. In addition, if the pick B (403-2) is identified by the seismic interpretation user as an incorrect pick during the quality control process, the pick B (403-2) and picks derived from the pick B (403-2) are removed from the interpreted horizon. For example, the pick C (403-3), pick D (403-4), pick E (403-5), pick F (403-6), intervening picks (e.g., intervening pick A (404), intervening pick B (405)), as well as any other pick derived from them are removed.
Further as shown in
The estimated horizon validated portion (431-3) and the estimated horizon removed portion (431-2) are separated by the by the boundary (431-6). As noted above, the estimated horizon validated portion (431-3) may be expanded into a revised estimated horizon (not shown) using the auto-tracking algorithm. For example, one or more points along the boundary (431-6) may be used as derived seeds by the auto-tracking algorithm to expand the validated portion of the estimated horizon. In another example, after removing the user selected pick error (421-5), the seismic interpretation user may select a different point on the seismic trace Y (421-8) as additional seed for the auto-tracking algorithm.
Further as shown in
In addition to viewing the ancestral path and the ancestral path seismic section shown in
Once the seismic interpreter user completes the review of the seismic section intersecting the estimated horizon (421-2) along the grid line X (441-3), another seismic section intersecting the estimated horizon (421-2) along the grid line Y (441-4) may be displayed for review. In addition, other seismic sections intersecting the estimated horizon (421-2) along the remaining grid lines (either X direction or Y direction) of the coarse grid (441-5) may also be displayed for review. For example, the seismic interpreter user may select any seismic section in any order for review. Once the review based on the coarse grid (441-5) is completed, the estimated horizon (421-2) is revised to retain the validated portion of each grid line of the coarse grid (441-5) exclusively. In other words, the removed portions of grid lines of the coarse grid (441-5), as well as any points not included on the coarse grid (441-5) are removed from the estimated horizon (421-2). The validated portions of the grid lines of the coarse grid (441-5) are then used as seeds to perform another iteration of the auto-tracking process to generate a revised estimated horizon.
The workflow described above may be repeated based on the revised estimated horizon using a finer grid resolution, such as the resolution of the fine grid (441-6) shown in
Embodiments of quality control of 3D horizon auto-tracking in seismic volume may be implemented on a computing system. Any combination of mobile, desktop, server, embedded, or other types of hardware may be used. For example, the computing system may be one or more mobile devices (e.g., laptop computer, smart phone, personal digital assistant, tablet computer, or other mobile device), desktop computers, servers, blades in a server chassis, or any other type of computing device or devices that includes at least the minimum processing power, memory, and input and output device(s) to perform one or more embodiments. For example, as shown in
The computing system (600) may also include one or more input device(s) (610), such as a touchscreen, keyboard, mouse, microphone, touchpad, electronic pen, or any other type of input device. Further, the computing system (600) may include one or more output device(s) (608), such as a screen (e.g., a liquid crystal display (LCD), a plasma display, touchscreen, cathode ray tube (CRT) monitor, projector, or other display device), a printer, external storage, or any other output device. One or more of the output device(s) may be the same or different from the input device. The computing system (600) may be connected to a network (612) (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, mobile network, or any other type of network) via a network interface connection (not shown). The input and output device(s) may be locally or remotely (e.g., via the network (612)) connected to the computer processor(s) (602), memory (604), and storage device(s) (606). Many different types of computing systems exist, and the aforementioned input and output device(s) may take other forms.
Software instructions in the form of computer readable program code to perform embodiments may be stored, in whole or in part, temporarily or permanently, on a non-transitory computer readable medium such as a CD, DVD, storage device, a diskette, a tape, flash memory, physical memory, or any other computer readable storage medium. Specifically, the software instructions may correspond to computer readable program code that when executed by a processor(s), is configured to perform embodiments of quality control of 3D horizon auto-tracking in seismic volume.
Further, one or more elements of the aforementioned computing system (600) may be located at a remote location and connected to the other elements over a network (612). Further, embodiments may be implemented on a distributed system having a plurality of nodes, where each portion of quality control of 3D horizon auto-tracking in seismic volume may be located on a different node within the distributed system. In one embodiment of quality control of 3D horizon auto-tracking in seismic volume, the node corresponds to a distinct computing device. The node may correspond to a computer processor with associated physical memory. The node may correspond to a computer processor or micro-core of a computer processor with shared memory and/or resources.
The systems and methods provided relate to the acquisition of hydrocarbons from an oilfield. It will be appreciated that the same systems and methods may be used for performing subsurface operations, such as mining, water retrieval, and acquisition of other underground fluids or other geomaterials from other fields. Further, portions of the systems and methods may be implemented as software, hardware, firmware, or combinations thereof.
While quality control of 3D horizon auto-tracking in seismic volume has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope as disclosed herein. Accordingly, the scope is as described by the attached claims.
This application claims priority under 35 U.S.C. §119(e) to U.S. Provisional Patent Application Serial Number 61/935,145, filed on Feb. 3, 2014 and entitled, “QUALITY CONTROL OF 3D HORIZON AUTO-TRACKING IN SEISMIC VOLUME.” U.S. Provisional Patent Application Ser. No. 61/935,145 is incorporated herein by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 61935145 | Feb 2014 | US |
