Patent Application
20210255346
Not applicable.
Not applicable.
The disclosed embodiments relate generally to techniques for seismic imaging of subsurface reservoirs and, in particular, to a method of seismic imaging including amplitude recovery based on modeling.
Seismic exploration involves surveying subterranean geological media for hydrocarbon deposits. A survey typically involves deploying seismic sources and seismic sensors at accessible locations. The sources generate seismic waves, which propagate into the geological medium creating pressure changes and vibrations. Variations in physical properties of the geological medium give rise to changes in certain properties of the seismic waves, such as their direction of propagation and other properties.
Portions of the seismic waves reach the seismic sensors. Some seismic sensors are sensitive to pressure changes (e.g., hydrophones), others (e.g., geophones) to particle motion and industrial surveys may deploy one type of sensor or both. In response to the detected seismic waves, the sensors generate corresponding electrical signals, known as traces, and record them in storage media as seismic data. Seismic data will include a plurality of “shots” (individual instances of the seismic source being activated), each of which is associated with a plurality of traces recorded at the plurality of sensors.
Seismic data is processed to create seismic images that can be interpreted to identify subsurface geologic features including hydrocarbon deposits. Analysis of seismic amplitude-versus-angle (AVA) or amplitude-versus-offset (AVO) is a primary technique for deriving rock properties and hydrocarbon indicators for oil and gas exploration. However, available seismic imaging and processing techniques, such as Kirchhoff migration (KMIG), reverse-time migration (RTM), F-K filtering, and Radon-transform-based multiple attenuation, often are not amplitude compliant by themselves. Acquisition geometry imprints, overburden wave propagation effects, and frequency-dependent processing algorithms result in amplitude distortions. Such distortions interfere with identification of fluid content and mapping of amplitude anomalies. In some migration implementations of KMIG and RTM, attempts are made to compensate acquisition fold and geometric spreading effects, but such compensation is only partial and qualitative. Representative prior art relevant to this work include Rickett (2003), Albertin (2010), and He et al (2018), among others. Some of them propose using synthetic data to model subsurface illumination and use the migration of synthetic data to determine amplitude compensation of field data for AVA or AVO fidelity. Quantitative amplitude compensation for post-migration processing such as Radon multiple attenuation is a less well-mentioned topic.
The ability to define the location of rock and fluid property changes in the subsurface is crucial to our ability to make the most appropriate choices for purchasing materials, operating safely, and successfully completing projects. Project cost is dependent upon accurate prediction of the position of physical boundaries within the Earth. Decisions include, but are not limited to, budgetary planning, obtaining mineral and lease rights, signing well commitments, permitting rig locations, designing well paths and drilling strategy, preventing issues of subsurface integrity by planning proper casing and cementation strategies, and selecting and purchasing appropriate completion and production equipment.
There exists a need for amplitude recovery in seismic images that will allow better seismic interpretation of potential hydrocarbon reservoirs.
In accordance with some embodiments, a method of seismic imaging including receiving a field seismic dataset representative of a subsurface volume of interest and a synthetic seismic dataset wherein the synthetic seismic dataset is generated with no or known attribute variation with angle or other spatial coordinates; applying seismic processing to the field seismic dataset and the synthetic seismic dataset to generate a processed field seismic dataset and a processed synthetic seismic dataset wherein the processed field seismic dataset and the processed synthetic seismic dataset each contain attribute distortion due to the seismic processing; and correcting the attribute distortion in the field seismic dataset based on the distortion assessed from the processed synthetic seismic dataset to generate a corrected processed field dataset is disclosed.
In another aspect of the present invention, to address the aforementioned problems, some embodiments provide a non-transitory computer readable storage medium storing one or more programs. The one or more programs comprise instructions, which when executed by a computer system with one or more processors and memory, cause the computer system to perform any of the methods provided herein.
In yet another aspect of the present invention, to address the aforementioned problems, some embodiments provide a computer system. The computer system includes one or more processors, memory, and one or more programs. The one or more programs are stored in memory and configured to be executed by the one or more processors. The one or more programs include an operating system and instructions that when executed by the one or more processors cause the computer system to perform any of the methods provided herein.
Like reference numerals refer to corresponding parts throughout the drawings.
Described below are methods, systems, and computer readable storage media that provide a manner of seismic imaging. These embodiments are designed to be of particular use for seismic imaging of subsurface volumes in geologically complex areas.
Reference will now be made in detail to various embodiments, examples of which are illustrated in the accompanying drawings. In the following detailed description, numerous specific details are set forth in order to provide a thorough understanding of the present disclosure and the embodiments described herein. However, embodiments described herein may be practiced without these specific details. In other instances, well-known methods, procedures, components, and mechanical apparatus have not been described in detail so as not to unnecessarily obscure aspects of the embodiments.
Seismic imaging of the subsurface is used to identify potential hydrocarbon reservoirs. Advantageously, those of ordinary skill in the art will appreciate, for example, that the embodiments provided herein may be utilized to generate a more accurate digital seismic image (i.e., the corrected digital seismic image). The more accurate digital seismic image may improve hydrocarbon exploration and improve hydrocarbon production. The more accurate digital seismic image may provide details of the subsurface that were illustrated poorly or not at all in traditional seismic images. Moreover, the more accurate digital seismic image may better delineate where different features begin, end, or any combination thereof. As one example, the more accurate digital seismic image may illustrate faults and/or salt flanks more accurately. As another example, assume that the more accurate digital seismic image indicates the presence of a hydrocarbon deposit. The more accurate digital seismic image may delineate more accurately the bounds of the hydrocarbon deposit so that the hydrocarbon deposit may be produced.
Those of ordinary skill in the art will appreciate, for example, that the more accurate digital seismic image may be utilized in hydrocarbon exploration and hydrocarbon production for decision making. For example, the more accurate digital seismic image may be utilized to pick a location for a wellbore. Those of ordinary skill in the art will appreciate that decisions about (a) where to drill one or more wellbores to produce the hydrocarbon deposit, (b) how many wellbores to drill to produce the hydrocarbon deposit, etc. may be made based on the more accurate digital seismic image. The more accurate digital seismic image may even be utilized to select the trajectory of each wellbore to be drilled. Moreover, if the delineation indicates a large hydrocarbon deposit, then a higher number of wellbore locations may be selected and that higher number of wellbores may be drilled, as compared to delineation indicating a smaller hydrocarbon deposit.
Those of ordinary skill in the art will appreciate, for example, that the more accurate digital seismic image may be utilized in hydrocarbon exploration and hydrocarbon production for control. For example, the more accurate digital seismic image may be utilized to steer a tool (e.g., drilling tool) to drill a wellbore. A drilling tool may be steered to drill one or more wellbores to produce the hydrocarbon deposit. Steering the tool may include drilling around or avoiding certain subsurface features (e.g., faults, salt diapirs, shale diapirs, shale ridges, pockmarks, buried channels, gas chimneys, shallow gas pockets, and slumps), drilling through certain subsurface features (e.g., hydrocarbon deposit), or any combination thereof depending on the desired outcome. As another example, the more accurate digital seismic image may be utilized for controlling flow of fluids injected into or received from the subsurface, the wellbore, or any combination thereof. As another example, the more accurate digital seismic image may be utilized for controlling flow of fluids injected into or received from at least one hydrocarbon producing zone of the subsurface. Chokes or well control devices, positioned on the surface or downhole, may be used to control the flow of fluid into and out. For example, certain subsurface features in the more accurate digital seismic image may prompt activation, deactivation, modification, or any combination thereof of the chokes or well control devices so as control the flow of fluid. Thus, the more accurate digital seismic image may be utilized to control injection rates, production rates, or any combination thereof.
Those of ordinary skill in the art will appreciate, for example, that the more accurate digital seismic image may be utilized to select completions, components, fluids, etc. for a wellbore. A variety of casing, tubing, packers, heaters, sand screens, gravel packs, items for fines migration, etc. may be selected for each wellbore to be drilled based on the more accurate digital seismic image. Furthermore, one or more recovery techniques to produce the hydrocarbon deposit may be selected based on the more accurate digital seismic image.
In short, those of ordinary skill in the art will appreciate that there are many decisions (e.g., in the context of (a) steering decisions, (b) landing decisions, (c) completion decisions, (d) engineering control systems and reservoir monitoring in the following but not limited to: Tow Streamer, Ocean Bottom Sensor, VSP, DASVSP, and imaging with both primaries and free surface multiple, etc.) to make in the hydrocarbon industry and making proper decisions based on more accurate digital seismic images should improve the likelihood of safe and reliable operations. For simplicity, the many possibilities, including wellbore location, component selection for the wellbore, recovery technique selection, controlling flow of fluid, etc., may be collectively referred to as managing a subsurface reservoir.
The present invention includes embodiments of a method and system for Modeling-Based Amplitude Recovery (MBAR). MBAR is a processing framework that corrects for amplitude distortions by one or a combination of several amplitude-distorting processing steps. It uses a synthetic dataset purposely created to mimic field data amplitude characteristics desired to be preserved despite amplitude distortions caused by one or more processing steps. The identical processing is applied to both the field and synthetic datasets. The amplitude distortions measured in the processed synthetic dataset are used to correct those in the processed field dataset. The distinction of MBAR from prior art for amplitude-conscious processing is in the design of synthetics for each type of processing, in the manner of how the synthetic data is used to achieve amplitude compliance, in applications to processing methods that are amplitude-distorting but widely employed by the seismic processing industry, and as alternative to existing approaches to some imaging tasks.
MBAR can be applied to many amplitude-linear processing algorithms and linear workflow combinations of amplitude-linear algorithms, such as KMIG, RTM, Radon, FX filtering, and FK filtering.
The synthetic seismic dataset will be designed to experience similar amplitude distortions or processing artifacts that replicate AVA flaws induced by the acquisition or processing of field seismic dataset. For example, the synthetic seismic data will be created with an earth model that has the same dip content as the image from the field seismic data, so will replicate or contain the same overburden wave-propagation distortions. As previously explained, the synthetic seismic dataset for one type of application of MBAR was generated using the same acquisition parameters (i.e., same source and receiver locations) as the field seismic data so it will have the same acquisition footprint. The synthetic dataset does not need to replicate all characters of the field data. It only needs to be sufficient for assessing the degree of processing affliction to those characters. In particular, the synthetic seismic dataset does not need to simulate the (same) AVA due to the fluid or lithology changes in the subsurface. An AVA-free synthetic data may be generated, for example, by Born modeling with density perturbations or simple convolution of a wavelet with a reflectivity model. It is convenient, but not required, to use synthetic data with zero AVA. The key is that the AVA of synthetic is known.
At operation 12, the field seismic data is processed using one or more amplitude-linear processing steps, some or all of which are known to cause amplitude distortion. This results in an output image with amplitude distortion 14. The same processing is applied to the synthetic seismic dataset at operation 13 resulting in synthetic output image with amplitude distortion 15. The amplitude distortion in both the field data output image and the synthetic data output image is due to the processing and will be the same in both cases. For the synthetic case, the amplitudes with and without distortion are known and thus can be used to quantify distortion for correcting field data. Without losing generality, data acquisition can be considered a type of processing (e.g., converting ground motion into electronic signals) and acquisition footprints are types of amplitude distortion by processing.
Operation 16 corrects the amplitude distortion from the field data image to produce an image with AVA that ideally is free of amplitude distortions. This may be accomplished by some version of an inverse process (e.g., division or deconvolution):
Method 100 does not specify the type of amplitude-linear processing that is applied to both field data and synthetic data. Those of skill in the art will realize that there are many processing options that can be used singly or in combination, including, by way of example and not limitation, anti-aliasing, migration, and post-migration data conditioning (PMDC).
In an embodiment, method 100 may be used to mitigate amplitude distortion in migration. For migration, amplitude distortion may occur due to acquisition fold and poor illumination of the subsurface (overburden wave propagation effects). In this embodiment, the synthetic seismic dataset is generated using an earth model with reflectivity that mimic the earth's reflectivity in some way, such as in dip content in the area of interest and uses finite-difference for modeling to compute the amplitude/illumination corrections, as can be found in existing publications. In an embodiment, the earth model may be designed with a set of non-intersecting layers with density perturbation to represent the dip content of the earth model for finite-difference modeling, as shown in
Furthermore, to avoid aliasing in discretizing the layers and to avoid layering-boundary stair-casing effects that impacts the accuracy of finite-difference modeling and prevent interference of adjacent layer boundaries, especially in low-frequency modeling for computational efficiency, instead of a single model with fine layering, this embodiment may use multiple models with thick layers and interlaced boundary positions. An implicit contour function F(x,y,z) with spatial coordinates (x,y,z) can be built with the layer boundaries or picked horizons at specified contours of F(x,y,z). Layer perturbation with alternating constant properties (such as constant-density perturbation ratio Δρ/φ can be created with a function like
Δρ/ρ=A*tan h(S*sin(π*(F−B)/D)*1−(2/π)*a cos[cos(π*(F−B)/D)]
and that with constant-gradient layers can be created by a function like
Δρ/ρ=A*tan h(S*sin(π(F−B)/D)*cos(e(F−B)/D)
where A controls the perturbation strength, D controls the layer thickness, B controls starting position of the layering, and S controls the sharpness and stair-casing at the layer boundaries. Layering with alternating constant Δρ/ρ perturbations produce reflectivities with alternating polarities, while perturbations with constant-gradient perturbations produce reflectivities with the same polarities. The AVA-free synthetic seismic data generated using this method can then be migrated with the same migration algorithm as the field seismic data and the two migrated images can be used in operation 16 of method 100 to create the image with AVA with overburden and acquisition distortions mitigated.
A workflow explaining an embodiment that uses method 100 for post-migration data conditioning (PMDC) is in
Comparison of the amplitude curves at top of CIG 66S (corrected for distortion) with CIG 64S (without distortion) confirms that MBAR has corrected the amplitude distortions observed in CIG 65S (with distortion). The distortions in field data CIG 65 are similarly corrected in CIG 66. Ultimately, the output CIG 67, after undoing stretch 62 and scaling 64 to facilitate denoising 65, has the amplitude distortion removed but has all of the benefits of the processing steps used.
In a similar embodiment, method 100 may be used for anti-aliasing. Oftentimes, seismic data are acquired with sparse source and receiver distributions (collectively called acquisition parameters). The reasons for sparsity vary, such acquisition cost and obstacles in the field. Sparsity can lead to spatial aliasing of images. In this case, method 100 calls for synthetic data generated using an earth model with reflectivity that mimic the earth's reflectivity in some way, such as in dip content in the area of interest. In this embodiment, it is necessary to create two synthetic datasets. For one of the synthetic datasets, the field coordinates of the actual sources and receivers are used. Migration of this synthetic dataset would give a synthetic image with aliasing similar to that of the field data. For the other synthetic dataset, denser sources and receivers would be used. Migration of the second synthetic data would give an unaliased (or at least less aliased) image. Using these two sets of synthetic images, a spatially non-stationary matching filter can be designed that could approximate the unaliased synthetic image given the aliased synthetic image. The matching filter can be applied to the aliased field data image to de-alias the field data image. This is a solution to an existing problem that is sometimes addressed by multi-dimensional interpolation. However, unlike existing approaches, the MBAR approach does not require regularity of the input source and receiver distribution.
To that end, the seismic imaging system 500 includes one or more processing units (CPUs) 502, one or more network interfaces 508 and/or other communications interfaces 503, memory 506, and one or more communication buses 504 for interconnecting these and various other components. The seismic imaging system 500 also includes a user interface 505 (e.g., a display 505-1 and an input device 505-2). The communication buses 504 may include circuitry (sometimes called a chipset) that interconnects and controls communications between system components. Memory 506 includes high-speed random access memory, such as DRAM, SRAM, DDR RAM or other random access solid state memory devices; and may include non-volatile memory, such as one or more magnetic disk storage devices, optical disk storage devices, flash memory devices, or other non-volatile solid state storage devices. Memory 506 may optionally include one or more storage devices remotely located from the CPUs 502. Memory 506, including the non-volatile and volatile memory devices within memory 506, comprises a non-transitory computer readable storage medium and may store seismic data, velocity models, seismic images, and/or geologic structure information.
In some embodiments, memory 506 or the non-transitory computer readable storage medium of memory 506 stores the following programs, modules and data structures, or a subset thereof including an operating system 516, a network communication module 518, and a seismic imaging module 520.
The operating system 516 includes procedures for handling various basic system services and for performing hardware dependent tasks.
The network communication module 518 facilitates communication with other devices via the communication network interfaces 508 (wired or wireless) and one or more communication networks, such as the Internet, other wide area networks, local area networks, metropolitan area networks, and so on.
In some embodiments, the seismic imaging module 520 executes the operations of method 100. Seismic imaging module 520 may include data sub-module 525, which handles the seismic datasets and any earth models. The seismic data and earth models are supplied by data sub-module 525 to other sub-modules.
Processing sub-module 522 contains a set of instructions 522-1 and accepts metadata and parameters 522-2 that will enable it to execute operations 12 and 13 of method 100. The distortion sub-module 523 contains a set of instructions 523-1 and accepts metadata and parameters 523-2 that will enable it to contribute to operation 16 of method 100. Although specific operations have been identified for the sub-modules discussed herein, this is not meant to be limiting. Each sub-module may be configured to execute operations identified as being a part of other sub-modules, and may contain other instructions, metadata, and parameters that allow it to execute other operations of use in processing seismic data and generate the seismic image. For example, any of the sub-modules may optionally be able to generate a display that would be sent to and shown on the user interface display 505-1. In addition, any of the seismic data or processed seismic data products may be transmitted via the communication interface(s) 503 or the network interface 508 and may be stored in memory 506.
Method 100 is, optionally, governed by instructions that are stored in computer memory or a non-transitory computer readable storage medium (e.g., memory 506 in
While particular embodiments are described above, it will be understood it is not intended to limit the invention to these particular embodiments. On the contrary, the invention includes alternatives, modifications and equivalents that are within the spirit and scope of the appended claims. Numerous specific details are set forth in order to provide a thorough understanding of the subject matter presented herein. But it will be apparent to one of ordinary skill in the art that the subject matter may be practiced without these specific details. In other instances, well-known methods, procedures, components, and circuits have not been described in detail so as not to unnecessarily obscure aspects of the embodiments.
The terminology used in the description of the invention herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used in the description of the invention 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 and all 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, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, operations, elements, components, and/or groups thereof.
As used herein, the term “if” may be construed to mean “when” or “upon” or “in response to determining” or “in accordance with a determination” or “in response to detecting,” that a stated condition precedent is true, depending on the context. Similarly, the phrase “if it is determined [that a stated condition precedent is true]” or “if [a stated condition precedent is true]” or “when [a stated condition precedent is true]” may be construed to mean “upon determining” or “in response to determining” or “in accordance with a determination” or “upon detecting” or “in response to detecting” that the stated condition precedent is true, depending on the context.
Although some of the various drawings illustrate a number of logical stages in a particular order, stages that are not order dependent may be reordered and other stages may be combined or broken out. While some reordering or other groupings are specifically mentioned, others will be obvious to those of ordinary skill in the art and so do not present an exhaustive list of alternatives. Moreover, it should be recognized that the stages could be implemented in hardware, firmware, software or any combination thereof.
The foregoing description, for purpose of explanation, has been described with reference to specific embodiments. However, the illustrative discussions above are not intended to be exhaustive or to limit the invention to the precise forms disclosed. Many modifications and variations are possible in view of the above teachings. The embodiments were chosen and described in order to best explain the principles of the invention and its practical applications, to thereby enable others skilled in the art to best utilize the invention and various embodiments with various modifications as are suited to the particular use contemplated.
