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1
Santos, Lúcio T., Jörg Schleicher, Martin Tygel, and Peter Hubral. "Seismic modeling by demigration." GEOPHYSICS 65, no. 4 (July 2000): 1281–89. http://dx.doi.org/10.1190/1.1444819.
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Kirchhoff‐type, isochron‐stack demigration is the natural asymptotic inverse to classical Kirchhoff or diffraction‐stack migration. Both stacking operations can be performed in true amplitude by an appropriate selection of weight functions. Isochron‐stack demigration is closely related to seismic modeling with the Kirchhoff integral. The principal objective of this paper is to show how demigration can be used to compute synthetic seismograms. The idea is to attach to each reflector in the model an appropriately stretched (i.e., frequency‐shifted) spatial wavelet. Its amplitude is proportional to the reflection coefficient, transforming the original reflector model into an artificially constructed true‐amplitude, depth‐migrated section. The seismic modeling is then realized by a true‐amplitude demigration operation applied to this artificially constructed migrated section. A simple but typical synthetic data example indicates that modeling by demigration yields results superior to conventional zero‐order ray theory or classical Kirchhoff modeling.
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Syaifuddin, Firman, Andri Dian Nugraha, Zulfakriza, and Shindy Rosalia. "Synthetic Modeling of Ambient Seismic Noise Tomography Data." IOP Conference Series: Earth and Environmental Science 873, no. 1 (October 1, 2021): 012096. http://dx.doi.org/10.1088/1755-1315/873/1/012096.
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Abstract Ambient seismic noise tomography is one of the most widely used methods in seismological studies today, especially after a comprehensive Earth noise model was published and noise analysis was performed on the IRIS Global Seismographic Network. Furthermore, the Power Spectral Density technique was introduced to identify background seismic noise in the United States. Many studies have been carried out using the ambient seismic noise tomography method which can be broadly grouped into several groups based on the objectives and research targets, such as to determine the structure of the earth’s crust and the upper mantle, to know the thickness of the sedimentary basins, to know the tectonic settings and geological structures, to know volcanic systems and geothermal systems, knowing near-surface geological features and as a monitoring effort the Ambient Noise Tomography method carried out by repeated measurements or time lapse. In this study, we investigate the characteristics of the ambient noise seismic tomography method, both its advantages and limitations of the method by utilizing synthetic data modeling using a simple geological model. Synthetic data is generated based on 1D dispersion curve forward modelling and the forward modeling of surface waves travel time for each period, which is then convoluted with the wavelets of each periods, then doing reverse correlation using a reference signal to produce synthetic recording data. We found that the estimate target depth and vertical resolution depend on the recorded data periods and the synthetic data modeling can be used as a basis in determining the acquisition design.
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Stemland, Helene Meling, Tor Arne Johansen, and Bent Ole Ruud. "Potential Use of Time-Lapse Surface Seismics for Monitoring Thawing of the Terrestrial Arctic." Applied Sciences 10, no. 5 (March 9, 2020): 1875. http://dx.doi.org/10.3390/app10051875.
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The terrestrial Arctic is warming rapidly, causing changes in the degree of freezing of the upper sediments, which the mechanical properties of unconsolidated sediments strongly depend upon. This study investigates the potential of using time-lapse surface seismics to monitor thawing of currently (partly) frozen ground utilizing synthetic and real seismic data. First, we construct a simple geological model having an initial temperature of −5 °C, and infer constant surface temperatures of −5 °C, +1 °C, +5 °C, and +10 °C for four years to this model. The geological models inferred by the various thermal regimes are converted to seismic models using rock physics modeling and subsequently seismic modeling based on wavenumber integration. Real seismic data reflecting altered surface temperatures were acquired by repeated experiments in the Norwegian Arctic during early autumn to mid-winter. Comparison of the surface wave characteristics of both synthetic and real seismic data reveals time-lapse effects that are related to thawing caused by varying surface temperatures. In particular, the surface wave dispersion is sensitive to the degree of freezing in unconsolidated sediments. This demonstrates the potential of using surface seismics for Arctic climate monitoring, but inversion of dispersion curves and knowledge of the local near-surface geology is important for such studies to be conclusive.
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Neff, Dennis B. "Incremental pay thickness modeling of hydrocarbon reservoirs." GEOPHYSICS 55, no. 5 (May 1990): 556–66. http://dx.doi.org/10.1190/1.1442867.
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The one-dimensional convolution model or synthetic seismogram provides more information about the seismic waveform expression of hydrocarbon reservoirs when petrophysical data (porosity, shale volume, water saturation, etc.) are systematically integrated into the seismogram generation process. Use of this modeling technique, herein called Incremental Pay Thickness (IPT) modeling, has provided valuable insights concerning the seismic response of several offshore Gulf of Mexico amplitude anomalies. Through integration of the petrophysical data, comparisons between seismic waveform response and expected reservoir pay thickness are extended to include estimates of gross pay thickness, net pay thickness, net porosity feet of pay, and hydrocarbons in place. These 1-D synthetic data easily convert to 2-D displays that often show exceptional waveform correlations between the synthetic and actual seismic data. Anomalous observed waveform responses include complex tuning curves; diagnostic isochron measurements even in unresolved thin-bed reservoirs; and extreme variations in the seismic expression of hydro-carbon-fluid contacts. While IPT modeling examples illustrate both the variability and nonuniqueness of seismic responses to hydrocarbon reservoirs, they often show good seismic predictability of pay thickness if the appropriate choice of amplitude-isochron versus pay thickness is made (i.e., peak amplitude, trough amplitude, or average amplitude versus gross pay thickness, net pay thickness, net porosity feet of pay, or hydrocarbons in place).
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Pradhan, Anshuman, and Tapan Mukerji. "Consistency and prior falsification of training data in seismic deep learning: Application to offshore deltaic reservoir characterization." GEOPHYSICS 87, no. 3 (April 11, 2022): N45—N61. http://dx.doi.org/10.1190/geo2021-0568.1.
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Deep learning (DL) applications of seismic reservoir characterization often require the generation of synthetic data to augment available sparse labeled data. An approach for generating synthetic training data consists of specifying probability distributions modeling prior geologic uncertainty on reservoir properties and forward modeling the seismic data. A prior falsification approach is critical to establish the consistency of the synthetic training data distribution with real seismic data. With the help of a real case study of facies classification with convolutional neural networks (CNNs) from an offshore deltaic reservoir, we have highlighted several practical nuances associated with training DL models on synthetic seismic data. We highlight the issue of overfitting of CNNs to the synthetic training data distribution and propose regularization strategies to address it. We demonstrate the efficacy of our proposed strategies by training the CNN on synthetic data and making robust predictions with real 3D partial stack seismic data.
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Chen, Ganglin, Gianni Matteucci, Bill Fahmy, and Chris Finn. "Spectral-decomposition response to reservoir fluids from a deepwater West Africa reservoir." GEOPHYSICS 73, no. 6 (November 2008): C23—C30. http://dx.doi.org/10.1190/1.2978337.
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We study the spectral-decomposition response to reservoir fluids from a deepwater West Africa reservoir through a systematic modeling approach. Our workflow starts from selecting the seismic data (far-angle seismic images) that show more pronounced fluid effect based on amplitude-versus-offset (AVO) analysis. Synthetic seismic forward modeling performed at the control well established the quality of the seismic well tie. Reservoir wedge modeling, spectral decomposition of the field and synthetic seismic data, and theoretical analyses were conducted to understand the spectral-decomposition responses. The reservoir fluid type is a main factor controlling the spectral response. For this deepwater reservoir, the amplitude contrast between oil sand and brine sand is higher at low frequencies [Formula: see text]. In addition, synthetic modeling can help identify the possible frequency band where the amplitude contrast between hydrocarbon sand and brine sand is higher. When properly included in a comprehensive direct-hydrocarbon-indicator (DHI)–AVO evaluation, spectral decomposition can enhance the identification of hydrocarbons.
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Gao, Hui, Xinming Wu, Jinyu Zhang, Xiaoming Sun, and Zhengfa Bi. "ClinoformNet-1.0: stratigraphic forward modeling and deep learning for seismic clinoform delineation." Geoscientific Model Development 16, no. 9 (May 9, 2023): 2495–513. http://dx.doi.org/10.5194/gmd-16-2495-2023.
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Abstract. Deep learning has been widely used for various kinds of data-mining tasks but not much for seismic stratigraphic interpretation due to the lack of labeled training datasets. We present a workflow to automatically generate numerous synthetic training datasets and take the seismic clinoform delineation as an example to demonstrate the effectiveness of using the synthetic datasets for training. In this workflow, we first perform stochastic stratigraphic forward modeling to generate numerous stratigraphic models of clinoform layers and corresponding porosity properties by randomly but properly choosing initial topographies, sea level curves, and thermal subsidence curves. We then convert the simulated stratigraphic models into impedance models by using the velocity–porosity relationship. We further simulate synthetic seismic data by convolving reflectivity models (converted from impedance models) with Ricker wavelets (with various peak frequencies) and adding real noise extracted from field seismic data. In this way, we automatically generate a total of 3000 diverse synthetic seismic datasets and the corresponding stratigraphic labels such as relative geologic time models and facies of clinoforms, which are all made publicly available. We use these synthetic datasets to train a modified encoder–decoder deep neural network for clinoform delineation in seismic data. Within the network, we apply a preconditioning process of structure-oriented smoothing to the feature maps of the decoder neural layers, which is helpful to avoid generating holes or outliers in the final output of clinoform delineation. Multiple 2D and 3D synthetic and field examples demonstrate that the network, trained with only synthetic datasets, works well to delineate clinoforms in seismic data with high accuracy and efficiency. Our workflow can be easily extended for other seismic stratigraphic interpretation tasks such as sequence boundary identification, synchronous horizon extraction, and shoreline trajectory identification.
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Arntsen, Børge, Lars Wensaas, Helge Løseth, and Christian Hermanrud. "Seismic modeling of gas chimneys." GEOPHYSICS 72, no. 5 (September 2007): SM251—SM259. http://dx.doi.org/10.1190/1.2749570.
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We propose a simple acoustic model explaining the main features of gas chimneys. The main elements of the model consist of gas diffusing from a connected fracture network and into the surrounding shale creating an inhomogeneous gas saturation. The gas saturation results in an inhomogeneous fluctuating compressional velocity field that distorts seismic waves. We model the fracture network by a random-walk process constrained by maximum fracture length and angle of the fracture with respect to the vertical. The gas saturation is computed from a simple analytical solution of the diffusion equation, and pressure-wave velocities are locally obtained assuming that mixing of shale and gas occurs on a scale much smaller than seismic wavelengths. Synthetic seismic sections are then computed using the resulting inhomogeneous velocity model and shown to give rise to similar deterioration in data quality as that found in data from real gas chimneys. Also, synthetic common-midpoint (CMP) gathers show the same distorted and attenuated traveltime curves as those obtained from a real data set. The model shows clearly that the features of gas chimneys change with geological time (a model parameter in our approach), the deterioration of seismic waves being smallest just after the creation of the gas chimney. It seems likely that at least some of the features of gas chimneys can be explained by a simple elastic model in combination with gas diffusion from a fracture network.
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Payne, M. A. "Shear‐wave logging to enhance seismic modeling." GEOPHYSICS 56, no. 12 (December 1991): 2129–38. http://dx.doi.org/10.1190/1.1443027.
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In an effort to understand better the amplitude variation with offset for reflections from an oil sand and the sensitivity of the AVO response to shear‐wave velocity variations, I studied synthetic and field gathers collected from an onshore field in the Gulf of Mexico basin. A wave‐equation‐based modeling program generated the synthetic seismic gathers using both measured and estimated shear‐wave velocities. The measured shear‐wave velocities came from a quadrupole sonic tool. The estimated shear‐wave velocities were obtained by applying published empirical and theoretical equations which relate shear‐wave velocities to measured compressional‐wave velocities. I carefully processed the recorded seismic data with a controlled‐amplitude processing stream. Comparison of the synthetic gathers with the processed field data leads to the conclusion that the model containing the measured shear‐wave velocities matches the field data much better than the model containing the estimated shear‐wave velocities. Therefore, existing equations which relate shear‐wave velocities to compressional‐wave velocities yield estimates which are not sufficiently accurate for making quantitative comparisons of synthetic and field gathers. Even small errors in the shear‐wave velocities can have a large impact on the output. Such errors can lead to an incomplete and perhaps inaccurate understanding of the amplitude‐versus‐offset response. This situation can be remedied by collecting shear‐wave data for use in amplitude‐versus‐offset modeling, and for building databases to generate better shear‐wave velocity estimator equations.
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Panea, Ionelia, Stefan Prisacari, Victor Mocanu, Mihnea Micu, and Marius Paraschivoiu. "The use of seismic modeling for the geologic interpretation of deep seismic reflection data with low signal-to-noise ratios." Interpretation 5, no. 1 (February 1, 2017): T23—T31. http://dx.doi.org/10.1190/int-2016-0046.1.
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We have performed a deep seismic reflection study, DACIA-PLAN, based on the data recorded along a crooked line across the southeastern Romanian Carpathians. The signal-to-noise ratio (S/N) of these data varies along the seismic profile, and its variation is considered to be an effect of the rough topography, complex subsurface geology, and varying surface conditions encountered during seismic data acquisition. The migrated time section that covers the mountainous area is clear, without visible reflections, making the geologic interpretation very difficult. We used a seismic modeling technique to explain the poor S/N of the recorded data and to generate synthetic seismic sections that can be useful for the geologic interpretation of the field seismic section (migrated time section). We used ray-tracing modeling to obtain the expected seismic expression of horizons of interest. Subsurface illumination modeling indicates that the complex subsurface geology and irregularly deployed sources and receivers are responsible for the incomplete and/or uneven illumination of the subsurface and can lead to strong amplitude variations. We then used 2.5D acoustic finite-difference modeling to analyze the effect of a crooked line on seismic wave propagation. The synthetic shot gathers prove that crooked line arrival times for reflected and head waves contain static time shifts relative to a straight line regular sampling geometry. Some geologic interfaces of interest are not well-imaged on the synthetic seismic section, and this is considered to be an effect of poor positioning during seismic data acquisition. We used the velocity model from the tomographic inversion of first-arrival traveltimes and synthetic and field crooked line deep seismic reflection data to create a structural image for the southeastern Romanian Carpathians and the Focsani Basin, which tie well with the geologic model built for this area on the basis of geologic and well data only.
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Carcione, José M., Icilio R. Finetti, and Davide Gei. "Seismic modeling study of the Earth's deep crust." GEOPHYSICS 68, no. 2 (March 2003): 656–64. http://dx.doi.org/10.1190/1.1567235.
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We use seismic modeling methods to validate the interpretation of deep‐crust seismic exploration. An approximation of the stacked section is obtained with the nonreflecting wave equation and the exploding‐reflector approach. Using this technique and ray‐tracing algorithms, we obtain a geological model by comparing the synthetic section with the real stacked section. An isotropic constitutive equation is assumed in this phase. The exact synthetic stacked section is then obtained by applying the standard processing sequence to a set of synthetic common‐shot profiles computed with the variable‐density acoustic wave equation. We introduce elliptical P‐wave anisotropy and the effects of small‐scale inhomogeneities by using a von Kármán autocovariance probability function that simulates scattering Q effects. Verification of the geological model by poststack migration constitutes an additional test. The methodology, which is suitable for areas of complex geology, is applied to a seismic line acquired in the northern Apennines as part of the Italian deep‐crust exploration project, CROP. This area is particularly difficult to interpret because of the presence of a complex tectonic setting.
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Cahoj, Marcus P., Sumit Verma, Bryce Hutchinson, and Kurt J. Marfurt. "Pitfalls in seismic processing: An application of seismic modeling to investigate acquisition footprint." Interpretation 4, no. 2 (May 1, 2016): SG1—SG9. http://dx.doi.org/10.1190/int-2015-0164.1.
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The term acquisition footprint is commonly used to define patterns in seismic time and horizon slices that are closely correlated to the acquisition geometry. Seismic attributes often exacerbate footprint artifacts and may pose pitfalls to the less experienced interpreter. Although removal of the acquisition footprint is the focus of considerable research, the sources of such artifact acquisition footprint are less commonly discussed or illustrated. Based on real data examples, we have hypothesized possible causes of footprint occurrence and created them through synthetic prestack modeling. Then, we processed these models using the same workflows used for the real data. Computation of geometric attributes from the migrated synthetics found the same footprint artifacts as the real data. These models showed that acquisition footprint could be caused by residual ground roll, inaccurate velocities, and far-offset migration stretch. With this understanding, we have examined the real seismic data volume and found that the key cause of acquisition footprint was inaccurate velocity analysis.
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Alfarraj, Motaz, and Ghassan AlRegib. "Semisupervised sequence modeling for elastic impedance inversion." Interpretation 7, no. 3 (August 1, 2019): SE237—SE249. http://dx.doi.org/10.1190/int-2018-0250.1.
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Recent applications of machine learning algorithms in the seismic domain have shown great potential in different areas such as seismic inversion and interpretation. However, such algorithms rarely enforce geophysical constraints — the lack of which might lead to undesirable results. To overcome this issue, we have developed a semisupervised sequence modeling framework based on recurrent neural networks for elastic impedance inversion from multiangle seismic data. Specifically, seismic traces and elastic impedance (EI) traces are modeled as a time series. Then, a neural-network-based inversion model comprising convolutional and recurrent neural layers is used to invert seismic data for EI. The proposed workflow uses well-log data to guide the inversion. In addition, it uses seismic forward modeling to regularize the training and to serve as a geophysical constraint for the inversion. The proposed workflow achieves an average correlation of 98% between the estimated and target EI using 10 well logs for training on a synthetic data set.
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Dietrich, Michel, and Michel Bouchon. "Measurements of attenuation from vertical seismic profiles by iterative modeling." GEOPHYSICS 50, no. 6 (June 1985): 931–49. http://dx.doi.org/10.1190/1.1441972.
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We present a numerical simulation of vertical seismic profiles (VSP) using the discrete horizontal wavenumber representation of seismic wave fields. The theoretical seismograms are computed in the acoustic case for flat layered media, and they include the effects of absorption and velocity dispersion. A study using the synthetic seismograms was conducted to investigate the accuracy and resolution of attenuation measurements from VSP data. It is shown that in finely layered media estimates of the anelastic attenuation obtained by use of the reduced spectral ratio method are usually inaccurate when the attenuation is measured over a small vertical extent. An iterative method is presented which improves the resolution of the measurements of intrinsic dissipation. This method allows determination for synthetic data of the quality factor over depth intervals of about one wavelength of the dominant seismic frequency.
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Galetti, Erica, David Halliday, and Andrew Curtis. "A simple and exact acoustic wavefield modeling code for data processing, imaging, and interferometry applications." GEOPHYSICS 78, no. 6 (November 1, 2013): F17—F27. http://dx.doi.org/10.1190/geo2012-0443.1.
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Improvements in industrial seismic, seismological, acoustic, or interferometric theory and applications often result in quite subtle changes in sound quality, seismic images, or information which are nevertheless crucial for improved interpretation or experience. When evaluating new theories and algorithms using synthetic data, an important aspect of related research is therefore that numerical errors due to wavefield modeling are reduced to a minimum. We present a new MATLAB code based on the Foldy method that models theoretically exact, direct, and scattered parts of a wavefield. Its main advantage lies in the fact that while all multiple scattering interactions are taken into account, unlike finite-difference or finite-element methods, numerical dispersion errors are avoided. The method is therefore ideal for testing new theory in industrial seismics, seismology, acoustics, and in wavefield interferometry in particular because the latter is particularly sensitive to the dynamics of scattering interactions. We present the theory behind the Foldy acoustic modeling method and provide examples of its implementation. We also benchmark the code against a good finite-difference code. Because our Foldy code was written and optimized to test new theory in seismic interferometry, examples of its application to seismic interferometry are also presented, showing its validity and importance when exact modeling results are needed.
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Yang, Jingkang, Jianhua Geng, and Luanxiao Zhao. "A frequency-decomposed nonstationary convolutional model for amplitude-versus-angle-and-frequency forward waveform modeling in attenuative media." GEOPHYSICS 85, no. 6 (October 13, 2020): T301—T314. http://dx.doi.org/10.1190/geo2019-0338.1.
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The conventional convolutional model (CCM) is widely applied to generate synthetic seismic data for numerous applications including amplitude variation with offset forward modeling, seismic well tie, and inversion. This approach assumes frequency-independent reflection coefficients and time-invariant seismic wavelets in laterally homogeneous elastic media. We have extended CCM to heterogeneous poroelastic media in which reflection coefficients are frequency dependent and the seismic wave is attenuated as it propagates. First, we decompose the seismic wavelet into monofrequency components through the Fourier transform. Then, to account for the attenuation effects at the reflection interfaces, we multiply the frequency-dependent reflection coefficients series with an attenuation function of frequency-variant quality factor [Formula: see text]. Finally, we convolve this product results with a monofrequency wavelet and sum all of the frequencies together to obtain the synthetic seismograms. The advantage of the proposed frequency-decomposed nonstationary convolutional model is that it takes into account the effects of attenuation on the wave reflections and propagation in attenuative media. In addition, it uses the frequency-dependent [Formula: see text] instead of the constant [Formula: see text] that is used by the traditional nonstationary convolutional model. The technique has been applied to amplitude-versus-angle-and-frequency forward waveform modeling in attenuative media, and it shows good agreement between synthetic and real data on seismic well ties.
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Sarma, G. S., K. Mallick, and V. R. Gadhinglajkar. "Nonreflecting boundary condition in finite‐element formulation for an elastic wave equation." GEOPHYSICS 63, no. 3 (May 1998): 1006–16. http://dx.doi.org/10.1190/1.1444378.
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Numerical modeling of seismic wavefields using finite‐difference or finite‐element methods requires truncation of the model to finite computational domains. It is well known that the edges of such truncated models give boundary reflections on the synthetic seismograms. An essential step to successful numerical modeling is to eliminate these reflections. We present a simple scheme that eliminates such boundary reflections when computing synthetics. We also demonstrate the efficiency and robustness of our method on a variety of geological models.
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Verma, Sumit, Onur Mutlu, Thang Ha, William Bailey, and Kurt J. Marfurt. "Calibration of attribute anomalies through prestack seismic modeling." Interpretation 3, no. 4 (November 1, 2015): SAC55—SAC70. http://dx.doi.org/10.1190/int-2015-0072.1.
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Seismic modeling is commonly used in determining subsurface illumination of alternative seismic survey designs, in the calibration of seismic processing and imaging algorithms, and in the design of effective processing workflows. Seismic modeling also forms the mathematical kernel of impedance inversion and is routinely used to predict the amplitude-variation-with-offset response as a function of rock and fluid properties. However, the use of seismic modeling in seismic attribute studies is less common. We have evaluated four case studies in which 2D synthetic common shot gathers were computed (acoustic or elastic) and processed (including migration) to evaluate possible interpretation hypotheses. The modeling we used in our study shows that the lack of continuous coherence anomalies in a faulted Chicontepec Basin survey was due to overprinting by coherent interbed multiples. Attributes computed from the resulting processed model data revealed that subtle curvature anomalies in a Mississippi Lime survey were due to karst collapse rather than to velocity pushdown related to vertical gas migration. Impedance attributes computed from a Woodford Shale model favored the hypothesis of increased porosity correlated with the occurrence of subtle faults rather than amplitude dimming due to poor fault imaging. Finally, modeling of a fractured basement survey in the Texas Panhandle survey indicated that headwave suppression preserved the basement fracture response while increasing the signal-to-noise ratio. Seismic attribute study on seismic modeling results helped significantly in testing possible interpretation hypotheses in all of our case studies.
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Vizeu, Fernando, Joao Zambrini, Anne-Laure Tertois, Bruno de Albuquerque da Graça e Costa, André Queiroz Fernandes, and Anat Canning. "Synthetic seismic data generation for automated AI-based procedures with an example application to high-resolution interpretation." Leading Edge 41, no. 6 (June 2022): 392–99. http://dx.doi.org/10.1190/tle41060392.1.
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This paper discusses the generation of synthetic 3D seismic data for training neural networks to solve a variety of seismic processing, interpretation, and inversion tasks. Using synthetic data is a way to address the shortage of seismic data, which are required for solving problems with machine learning techniques. Synthetic data are built via a simulation process that is based on a mathematical representation of the physics of the problem. In other words, using synthetic data is an indirect way to teach neural networks about the physics of the problem. An important incentive for using synthetic data to solve problems with artificial intelligence methods is that with real seismic data the ground truth is always unknown. When generating synthetic seismic data, we first build the model and then calculate the data, so the answer (model) is always known and always exact. We describe a methodology for generating on-the-fly simulated postmigration (1D modeling) synthetic data in 3D, which are high resolution and look similar to real data. A wide range of models is covered by generating an unlimited number of data examples. The synthetic data are built from impedance models that are constructed through geostatistical simulation of real well logs. With geostatistical simulation, we can describe various geologic variance models in 3D and obtain realistic images. To cover a broad range of scenarios, we need to generalize the seismic data story by randomly perturbing many parameters including structures, conformity styles, dip-strike directions, variograms, measured input logs, frequencies, phase spectra, etc.
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Gochioco, Lawrence M. "Modeling studies of interference reflections in thin‐layered media bounded by coal seams." GEOPHYSICS 57, no. 9 (September 1992): 1209–16. http://dx.doi.org/10.1190/1.1443336.
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High‐resolution seismic data collected over a major U.S. coal basin indicated potential complex problems associated with interference reflections. These problems differed from those normally encountered in the exploration of oil and gas because of differences in the geologic boundary conditions. Modeling studies were conducted to investigate the effects of overlapping primary reflections and the composite reflection that result from stacking individual wavelets. A modified empirical formula of Lindseth’s linear relationship between acoustic impedance and velocity is used to extrapolate velocity information from density logs to provide appropriate geophysical properties for modeling. The synthetic seismograms generated from density and synthetic sonic logs correlated well with the processed seismic data. A 150-Hz Ricker wavelet is used to convolve with the computer models, and the models showed that certain anomalous composite reflections result from the superposition of overlapping primary reflections. Depending on the traveltime delay of latter primary reflections, constructive or destructive interference could significantly alter the signature of the initial reflection associated with the bed of interest, which may lead to misinterpretations if not properly identified. The stratigraphic modeling technique further enhances the interpretation process and shows a close correlation with the seismic data, suggesting that more precise analytical methods need to be used to interpret, sometimes complex, high‐resolution seismic data.
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Lecomte, Isabelle, Paul Lubrano Lavadera, Ingrid Anell, Simon J. Buckley, Daniel W. Schmid, and Michael Heeremans. "Ray-based seismic modeling of geologic models: Understanding and analyzing seismic images efficiently." Interpretation 3, no. 4 (November 1, 2015): SAC71—SAC89. http://dx.doi.org/10.1190/int-2015-0061.1.
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Often, interpreters only have access to seismic sections and, at times, well data, when making an interpretation of structures and depositional features in the subsurface. The validity of the final interpretation is based on how well the seismic data are able to reproduce the actual geology, and seismic modeling can help constrain that. Ideally, modeling should create complete seismograms, which is often best achieved by finite-difference modeling with postprocessing to produce synthetic seismic sections for comparison purposes. Such extensive modeling is, however, not routinely affordable. A far more efficient option, using the simpler 1D convolution model with reflectivity logs extracted along verticals in velocity models, generates poor modeling results when lateral velocity variations are expected. A third and intermediate option is to use the various ray-based approaches available, which are efficient and flexible. However, standard ray methods, such as the normal-incidence point for unmigrated poststack sections or image rays for simulating time-migrated poststack results, cannot deal with complex and detailed targets, and will not reproduce the realistic (3D) resolution effects of seismic imaging. Nevertheless, ray methods can also be used to estimate 3D spatial prestack convolution operators, so-called point-spread functions. These are functions of the survey, velocity model, and wavelet, among others, and therefore they include 3D angle-dependent illumination and resolution effects. Prestack depth migration images are thus rapidly simulated by spatial convolution with detailed 3D reflectivity models, which goes far beyond the limits of 1D convolution modeling. This 3D convolution modeling should allow geologists to better assess their interpretations and draw more definitive conclusions.
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Udin, Yana, and Wiwit Suryanto. "Identification of Seismic Response to Aquifer System with A Synthetic Modelling Approach." IOP Conference Series: Earth and Environmental Science 1071, no. 1 (August 1, 2022): 012019. http://dx.doi.org/10.1088/1755-1315/1071/1/012019.
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Abstract The microseismic method is relatively new in groundwater exploration, especially in Indonesia. This study will examine the response of microseismic to groundwater aquifer systems. This study aims to analyze the response of seismic waves and to interpret the seismic wave response characteristics to the aquifer system model. The modeling of the aquifer system was carried out using seismic stratigraphy data. This data was used as input data to model the exposed HVSR curve using the Microtrem program in MATLAB. The study of physical parameters and supporting parameters of the aquifer layer and the air contained in it was carried out to support this modeling. The aquifer system modeling was carried out with various parameters, including saturation, porosity, and thickness of the aquifer layer. Furthermore, an analysis of the model is carried out to determine the response characteristics of the aquifer system to microseismic waves. The results show that the frequency range as a marker of the presence of the aquifer ranges from 2-4 Hz, which is determined by parameters within a specific value.
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Chen, Bo, and Xiaofeng Jia. "Staining algorithm for seismic modeling and migration." GEOPHYSICS 79, no. 4 (July 1, 2014): S121—S129. http://dx.doi.org/10.1190/geo2013-0262.1.
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In seismic migration, some structures such as those in subsalt shadow zones are not imaged well. The signal in these areas may be even weaker than the artifacts elsewhere. We evaluated a method to significantly improve the signal-to-noise ratio (S/N) in poorly illuminated areas of the model. We constructed a “phantom” wavefield: an extension of the wavefield to the complex domain. The imaginary wavefield was synchronized with the real wavefield, but it contained only the events relevant to a target region of the model, which was specified using a staining algorithm. The real wavefield interacted with the entire model. However, all structures except for the target were transparent to the imaginary wavefield, which is excited only when the real wavefront arrives at the target structure. The real and the imaginary source wavefields were crosscorrelated with the regular receiver wavefield. The results were revealed in two images: the conventional reverse time migration image and an image of the target region only. Synthetic experiments showed that the S/N of the target structures was improved significantly, with other structures effectively muted.
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Maresh, Jennifer, Robert S. White, Richard W. Hobbs, and John R. Smallwood. "Seismic attenuation of Atlantic margin basalts: Observations and modeling." GEOPHYSICS 71, no. 6 (November 2006): B211—B221. http://dx.doi.org/10.1190/1.2335875.
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Paleogene basalts are present over much of the northeastern Atlantic European margin. In regions containing significant thicknesses of layered basalt flows, conducting seismic imaging within and beneath the volcanic section has proven difficult, largely because the basalts severely attenuate and scatter seismic energy. We use data from a vertical seismic profile (VSP) from well 164/07-1 that penetrated [Formula: see text] of basalt in the northern Rockall Trough west of Britain to measure the seismic attenuation caused by the in-situ basalts. The effective quality factor [Formula: see text] of the basalt layer is found from the VSP to be 15–35, which is considerably lower (more attenuative) than the intrinsic attenuation measured on basalt samples in the laboratory. We then run synthetic seismogram models to investigate the likely cause of the attenuation. Full waveform 1D modeling of stacked sequences of lava flows based on rock properties from the same well indicates that much of the seismic attenuation observed from the VSP can be accounted for by the scattering effects of multiple thin layers with high impedance contrasts. Phase-screen seismic modeling of the rugose basalt surface at the top-of-basalt sediment interface, with the magnitude and wavelength of the relief constrained by a 3D seismic survey around the well, suggests that surface scattering from this interface plays a much smaller role than internal scattering in attenuating the seismic signal as it passes through the basalt sequence.
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Shen, Yi, Jack Dvorkin, and Yunyue Li. "Improving seismic QP estimation using rock-physics constraints." GEOPHYSICS 83, no. 3 (May 1, 2018): MR187—MR198. http://dx.doi.org/10.1190/geo2016-0665.1.
Full textAbstract:
Our goal is to accurately estimate attenuation from seismic data using model regularization in the seismic inversion workflow. One way to achieve this goal is by finding an analytical relation linking [Formula: see text] to [Formula: see text]. We derive an approximate closed-form solution relating [Formula: see text] to [Formula: see text] using rock-physics modeling. This relation is tested on well data from a clean clastic gas reservoir, of which the [Formula: see text] values are computed from the log data. Next, we create a 2D synthetic gas-reservoir section populated with [Formula: see text] and [Formula: see text] and generate respective synthetic seismograms. Now, the goal is to invert this synthetic seismic section for [Formula: see text]. If we use standard seismic inversion based solely on seismic data, the inverted attenuation model has low resolution and incorrect positioning, and it is distorted. However, adding our relation between velocity and attenuation, we obtain an attenuation model very close to the original section. This method is tested on a 2D field seismic data set from Gulf of Mexico. The resulting [Formula: see text] model matches the geologic shape of an absorption body interpreted from the seismic section. Using this [Formula: see text] model in seismic migration, we make the seismic events below the high-absorption layer clearly visible, with improved frequency content and coherency of the events.
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Lanteaume, Cyprien, François Fournier, Matthieu Pellerin, and Jean Borgomano. "Testing geologic assumptions and scenarios in carbonate exploration: Insights from integrated stratigraphic, diagenetic, and seismic forward modeling." Leading Edge 37, no. 9 (September 2018): 672–80. http://dx.doi.org/10.1190/tle37090672.1.
Full textAbstract:
Carbonates are considered complex, heterogeneous at all scales, and unfortunately often poorly seismically imaged. We propose a methodology based on forward-modeling approaches to test the validity of common exploration assumptions (e.g., chronostratigraphic value of seismic reflectors) and of geologic interpretations (e.g., stratigraphic correlations and depositional and diagenetic architecture) that are determined from a limited amount of data. The proposed workflow includes four main steps: (1) identification and quantification of the primary controls on carbonate deposition and the prediction of the carbonate stratigraphic architecture (through stratigraphic forward modeling); (2) identification of diagenetic processes and prediction of the spatial distribution of diagenetic products (diagenetic forward modeling); (3) quantification of the impact of diagenesis on acoustic and reservoir properties; and (4) computation of synthetic seismic models based on various scenarios of stratigraphic and diagenetic architectures and comparison with actual seismic. The likelihood of a given scenario is tested by quantifying the misfit between the modeled versus the real seismic. This workflow illustrates the relevance of forward-modeling approaches for building realistic models that can be shared by the various disciplines of carbonate exploration (sedimentology, stratigraphy, diagenesis, seismic, geomodeling, and reservoir).
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Poormirzaee, Rashed, Babak Sohrabian, and Pejman Tahmasebi. "Seismic refraction data analysis using machine learning and numerical modeling for characterization of dam construction sites." GEOPHYSICS 87, no. 2 (December 27, 2021): U21—U28. http://dx.doi.org/10.1190/geo2020-0935.1.
Full textAbstract:
Seismic refraction is a cost-effective tool to reveal subsurface compressional wave (P-wave) velocity. Inversion of traveltimes for estimating a realistic velocity model is a significant step in the processing of seismic refraction data. The results of the seismic data inversion are stochastic; thus, using prior information or complementary geophysical data can have a significant role in estimating the structural properties based on the observed data. Nevertheless, sufficient prior information or auxiliary data are not available in many geophysical sites. In such situations, developing advanced computational modeling is a vital step in providing primary information and improving the results. To this aim, a new inversion framework through hybrid committee artificial neural networks (CANNs) and the flower pollination (FP) optimization algorithm is introduced for inversion of refracted seismic traveltimes. Synthetic models generated by a forward-modeling approach are used to train the machine-learning model. Then, model parameters, such as the number of layers, thicknesses, and P-wave velocities, are predicted using a committee machine constructed based on several neural networks, which is achieved by averaging and stack generalization methods in which the latter method provides a better result. Then, the CANN results are used in the FP inversion algorithm to estimate the final model because it provides essential prior information on the number of layers and model parameters, which can be used in the FP searching algorithm. Our inversion procedure is tested on different synthetic data sets and applied at a dam site to determine the number of layers and their thicknesses. Our findings indicate a successful performance on synthetic and real data for automatic inversion of seismic refraction data.
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Wang, Fred P., Jiachun Dai, and Charles Kerans. "Modeling dolomitized carbonate‐ramp reservoirs: A case study of the Seminole San Andres unit—Part II, Seismic modeling, reservoir geostatistics, and reservoir simulation." GEOPHYSICS 63, no. 6 (November 1998): 1876–84. http://dx.doi.org/10.1190/1.1444480.
Full textAbstract:
In part I of this paper, we discussed the rock‐fabric/petrophysical classes for dolomitized carbonate‐ramp rocks, the effects of rock fabric and pore type on petrophysical properties, petrophysical models for analyzing wireline logs, the critical scales for defining geologic framework, and 3-D geologic modeling. Part II focuses on geophysical and engineering characterizations, including seismic modeling, reservoir geostatistics, stochastic modeling, and reservoir simulation. Synthetic seismograms of 30 to 200 Hz were generated to study the level of seismic resolution required to capture the high‐frequency geologic features in dolomitized carbonate‐ramp reservoirs. At frequencies <70 Hz, neither the high‐frequency cycles nor the rock‐fabric units can be identified in seismic data because the tuning thickness of seismic data is much greater than the average thickness of high‐frequency cycles of 6 m. At frequencies >100 Hz, major high‐porosity and dense mudstone units can be better differentiated, while the rock‐fabric units within high‐frequency cycles can be captured at frequencies higher than 200 Hz. Seismic inversion was performed on the 30- to 200-Hz synthetic seismograms to investigate the level of seismic resolution required to recover the high‐resolution inverted impedance logs. When seismic data were noise free, wavelets were known and sampling rates were high; deconvolution techniques yielded perfect inversion results. When the seismic data were noisy, the inverted reflectivity profiles were poor and complicated by numerous high‐frequency spikes, which can be significantly removed using the moving averaging techniques. When wavelets were not known, the predictive deconvolution gave satisfactory inversion results. These results suggest that interwell information required for reservoir characterization can be recovered from low‐frequency seismic data by inversion. Outcrop data were collected to investigate effects of sampling interval and scale‐up of block size on geostatistical parameters. Semivariogram analysis of outcrop data showed that the sill of log permeability decreases and the correlation length increases with an increase of horizontal block size. Permeability models were generated using conventional linear interpolation, stochastic realizations without stratigraphic constraints, and stochastic realizations with stratigraphic constraints. The stratigraphic feature of upward‐shoaling sequences can be modeled in stochastic realizations constrained by the high‐frequency cycles and rock‐fabric flow units. Simulations of a fine‐scale Lawyer Canyon outcrop model were used to study the factors affecting waterflooding performance. Simulation results show that waterflooding performance depends strongly on the geometry and stacking pattern of the rock‐fabric units and on the location of production and injection wells.
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Khalid, Perveiz, Irfan Raza, Shahzada Khurram, Muhammad Irfan Ehsan, and Shahbaz Muhammad. "Seismic Characterization to Identify Geological Structures and Petroleum Play in Lower Indus Basin, Pakistan." International Journal of Economic and Environmental Geology 13, no. 4 (December 15, 2022): 29–34. http://dx.doi.org/10.46660/ijeeg.v13i4.50.
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The Cretaceous shale intervals of Talhar and Sembar Formations – distributed in the Lower Indus Basin of Pakistan – are organic-rich shales that can act as shale gas plays. Two-dimensional seismic using synthetic modeling has been carried out in Khewari oil field to identify petroleum plays. This work was completed with the help of eight seismic processed and migrated lines. Based on structural interpretation different geological structures were marked. The seismic character, continuity, and coherency in seismic reflection patterns indicate that the area is under an extensional regime with normal faults pattern associated with horst and graben structure. This structure is favorable for the accumulation of hydrocarbon. The shales of Talhar and Sembar formations are overlying Chilton limestone, which is a proven reservoir. The isopach maps show that Talhar Shales and Sembar Formation are dipping towards the northeast. Precisely to characterize the reflector, a synthetic seismogram was employed to tie well tops and seismic profiles.
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Fliedner, Moritz M., and Robert S. White. "Seismic structure of basalt flows from surface seismic data, borehole measurements, and synthetic seismogram modeling." GEOPHYSICS 66, no. 6 (November 2001): 1925–36. http://dx.doi.org/10.1190/1.1486760.
Full textAbstract:
We use the wide‐angle wavefield to constrain estimates of the seismic velocity and thickness of basalt flows overlying sediments. Wide angle means the seismic wavefield recorded at offsets beyond the emergence of the direct wave. This wide‐angle wavefield contains arrivals that are returned from within and below the basalt flows, including the diving wave through the basalts as the first arrival and P‐wave reflections from the base of the basalts and from subbasalt structures. The velocity structure of basalt flows can be determined to first order from traveltime information by ray tracing the basalt turning rays and the wide‐angle base‐basalt reflection. This can be refined by using the amplitude variation with offset (AVO) of the basalt diving wave. Synthetic seismogram models with varying flow thicknesses and velocity gradients demonstrate the sensitivity to the velocity structure of the basalt diving wave and of reflections from the base of the basalt layer and below. The diving‐wave amplitudes of the models containing velocity gradients show a local amplitude minimum followed by a maximum at a greater range if the basalt thickness exceeds one wavelength and beyond that an exponential amplitude decay. The offset at which the maximum occurs can be used to determine the basalt thickness. The velocity gradient within the basalt can be determined from the slope of the exponential amplitude decay. The amplitudes of subbasalt reflections can be used to determine seismic velocities of the overburden and the impedance contrast at the reflector. Combining wide‐angle traveltimes and amplitudes of the basalt diving wave and subbasalt reflections enables us to obtain a more detailed velocity profile than is possible with the NMO velocities of small‐offset reflections. This paper concentrates on the subbasalt problem, but the results are more generally applicable to situations where high‐velocity bodies overlie a low‐velocity target, such as subsalt structures.
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Apoloner, M. T., and G. Bokelmann. "Modeling and detection of regional depth phases at the GERES array." Advances in Geosciences 41 (August 31, 2015): 5–10. http://dx.doi.org/10.5194/adgeo-41-5-2015.
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Abstract. The Vienna Basin in Eastern Austria is a region of low to moderate seismicity, and hence the seismological network coverage is relatively sparse. Nevertheless, the area is one of the most densely populated and most developed areas in Austria, so accurate earthquake location, including depth estimation and relation to faults is not only important for understanding tectonic processes, but also for estimating seismic hazard. Particularly depth estimation needs a dense seismic network around the anticipated epicenter. If the station coverage is not sufficient, the depth can only be estimated roughly. Regional Depth Phases (RDP) like sPg, sPmP and sPn have been already used successfully for calculating depth even if only observable from one station. However, especially in regions with sedimentary basins these phases prove difficult or impossible to recover from the seismic records. For this study we use seismic array data from GERES. It is 220 km to the North West of the Vienna Basin, which – according to literature – is a suitable distance to recover PmP and sPmP phases. We use array processing on recent earthquake data from the Vienna Basin with local magnitudes from 2.1 to 4.2 to reduce the SNR and to search for RDP. At the same time, we do similar processing on synthetic data specially modeled for this application. We compare real and synthetic results to assess which phases can be identified and to what extent depth estimation can be improved. Additionally, we calculate a map of lateral propagation behavior of RDP for a typical strike-slip earthquake in our region of interest up to 400 km distance. For our study case RDP propagation is strongly azimuthally dependent. Also, distance ranges differ from literature sources. Comparing with synthetic seismograms we identify PmP and PbP phases with array processing as strongest arrivals. Although the associated depth phases cannot be identified at this distance and azimuth, identification of the PbP phases limits possible depth to less than 20 km. Polarization analysis adds information on the first arriving Pn wave for local magnitudes above 2.5.
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Asikin, Ariesty R. K., Awali Priyono, Tutuka Ariadji, Benyamin Sapiie, Mohammad R. Sule, Takeshi Tsuji, Wawan Gunawan A. Kadir, Toshifumi Matsuoka, and Sigit Rahardjo. "Forward Modeling Time-Lapse Seismic based on Reservoir Simulation Result on The CCS Project at Gundih Field, Indonesia." Modern Applied Science 12, no. 1 (December 25, 2017): 75. http://dx.doi.org/10.5539/mas.v12n1p75.
Full textAbstract:
This paper contains reservoir simulation study of carbon storage at Gundih field in Central Java Island, Indonesia. Two different cases of injection simulation were performed and analyzed in this paper. The cases represent the conditions when the smallest and largest volumes of CO2areinjected into the subsurface to see the changes of reservoir that happen after the injection processes. The simulation result shows that when a larger amount of CO2 is injected into the targeted reservoir, it will migrate to the peak of anticline structure located in the southeast of CO2 injection well. The displacement of CO2 in the simulation progress shows that it will not reach the fault location. The geological model for synthetic seismogram calculation is then built based on the simulation reservoir result. The furthest displacement of CO2 is calculated on each case and described as the saturated CO2 layers. Forward modeling is performed to create synthetic seismic gather which will be processed to construct seismic section. The difference between the initial seismic section before the injection process and seismic section including saturated CO2 layer after the injection process will be evaluated by the potential of injected CO2 monitoring using time-lapse seismic survey in the Gundih field.
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Pilikos, Georgios, and A. C. Faul. "Bayesian modeling for uncertainty quantification in seismic compressive sensing." GEOPHYSICS 84, no. 2 (March 1, 2019): P15—P25. http://dx.doi.org/10.1190/geo2018-0145.1.
Full textAbstract:
Compressive sensing is used to improve the efficiency of seismic data acquisition and survey design. Nevertheless, most methods are ad hoc, and their only aim is to fill in the gaps in the data. Algorithms might be able to predict missing receivers’ values, however, it is also desirable to be able to associate each prediction with a degree of uncertainty. We used beta process factor analysis (BPFA) and its variance. With this, we achieved high correlation between uncertainty and respective reconstruction error. Comparisons with other algorithms in the literature and results on synthetic and field data illustrate the advantages of using BPFA for uncertainty quantification. This could be useful when modeling the degree of uncertainty for different source/receiver configurations to guide future seismic survey design.
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Grana, Dario, and Ernesto Della Rossa. "Probabilistic petrophysical-properties estimation integrating statistical rock physics with seismic inversion." GEOPHYSICS 75, no. 3 (May 2010): O21—O37. http://dx.doi.org/10.1190/1.3386676.
Full textAbstract:
A joint estimation of petrophysical properties is proposed that combines statistical rock physics and Bayesian seismic inversion. Because elastic attributes are correlated with petrophysical variables (effective porosity, clay content, and water saturation) and this physical link is associated with uncertainties, the petrophysical-properties estimation from seismic data can be seen as a Bayesian inversion problem. The purpose of this work was to develop a strategy for estimating the probability distributions of petrophysical parameters and litho-fluid classes from seismics. Estimation of reservoir properties and the associated uncertainty was performed in three steps: linearized seismic inversion to estimate the probabilities of elastic parameters, probabilistic upscaling to include the scale-changes effect, and petrophysical inversion to estimate the probabilities of petrophysical variables andlitho-fluid classes. Rock-physics equations provide the linkbetween reservoir properties and velocities, and linearized seismic modeling connects velocities and density to seismic amplitude. A full Bayesian approach was adopted to propagate uncertainty from seismics to petrophysics in an integrated framework that takes into account different sources of uncertainty: heterogeneity of the real data, approximation of physical models, measurement errors, and scale changes. The method has been tested, as a feasibility step, on real well data and synthetic seismic data to show reliable propagation of the uncertainty through the three different steps and to compare two statistical approaches: parametric and nonparametric. Application to a real reservoir study (including data from two wells and partially stacked seismic volumes) has provided as a main result the probability densities of petrophysical properties and litho-fluid classes. It demonstrated the applicability of the proposed inversion method.
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Dietrich, Michel. "Modeling of marine seismic profiles in the t-x and τ-p domains." GEOPHYSICS 53, no. 4 (April 1988): 453–65. http://dx.doi.org/10.1190/1.1442477.
Full textAbstract:
In many cases, comparison of real data with synthetic seismograms provides additional constraints on the velocity‐depth profiles obtained with simple inversion techniques. Obtaining a satisfactory match between the real and computed data usually requires several trials with different models but can be performed rapidly if the theoretical seismograms are themselves easily interpretable, i.e., if the major contributions which make up the synthetic traces can be identified and separated. In horizontally stratified media, modeling is further simplified and is faster if the simulation techniques are implemented in the domain of the intercept time τ and the ray parameter p. The generalized reflection and transmission matrix method is well suited for these purposes and may be used to generate synthetic seismograms in both the t-x and τ-p planes. Computation of plane‐wave seismograms is straightforward and merely corresponds to an inverse Fourier transform of the overall reflectivity matrix for each ray parameter. The construction of point‐source seismograms can be carried out in several ways. In this paper, I combine the generalized reflection and transmission matrix method with a discrete wavenumber integration of the reflectivity function, extending previous work to include fluid‐solid interfaces. The introduction of scaling parameters also simplifies the reflectivity matrices. Simple numerical experiments demonstrate that the relations between the earth model and the corresponding seismic response are simpler in the τ-p domain than in the t-x domain. In particular, calculation of the PP, SP, and SS contributions to the complete seismic response shows that shear and converted waves may have a clearer expression in the τ-p plane than in the t-x plane and can in some cases provide discrimination between several earth models. Finally, the main features of a real marine seismic profile are well reproduced by synthetic sections in both the t-x and τ-p domains.
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Liang, Guanghe, Xinping Cai, and Qianyu Li. "Using high‐order cumulants to extrapolate spatially variant seismic wavelets." GEOPHYSICS 67, no. 6 (November 2002): 1869–76. http://dx.doi.org/10.1190/1.1527086.
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Extraction of seismic wavelets is important for impedance inversion and forward modeling. We propose a method for estimating spatial variant seismic wavelets. The method uses third‐ and fourth‐order cumulants of seismic data. It combines third‐ and fourth‐order moments of seismic wavelets with those obtained by a deterministic method at well locations. We design a multidimensional filter at a well by matching the high‐order cumulants of seismic data to the high‐order moments of seismic wavelets. Applying the filter to the high‐order culumants of other seismic traces away from the well yields the corresponding wavelets. The new method for seismic wavelet extraction is thus constrained by well‐log data. Synthetic tests show that this method can produce accurate spatially varying wavelets. A real data test of the method is also successful.
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Koulakov, Ivan, Tatiana Stupina, and Heidrun Kopp. "Creating realistic models based on combined forward modeling and tomographic inversion of seismic profiling data." GEOPHYSICS 75, no. 3 (May 2010): B115—B136. http://dx.doi.org/10.1190/1.3427637.
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Amplitudes and shapes of seismic patterns derived from tomographic images often are strongly biased with respect to real structures in the earth. In particular, tomography usually provides continuous velocity distributions, whereas major velocity changes in the earth often occur on first-order interfaces. We propose an approach that constructs a realistic structure of the earth that combines forward modeling and tomographic inversion (FM&TI). Using available a priori information, we first construct a synthetic model with realistic patterns. Then we compute synthetic times and invert them using the same tomographic code and the same parameters as in the case of observed data processing. We compare the reconstruction result with the tomographicimage of observed data inversion. If a discrepancy is observed, we correct the synthetic model and repeat the FM&TI process. After several trials, we obtain similar results of synthetic and observed data inversion. In this case, the derived synthetic model adequately represents the real structure of the earth. In a working scheme of this approach, we three authors used two different synthetic models with a realistic setup. One of us created models, but the other two performed the reconstruction with no knowledge of the models. We discovered that the synthetic models derived by FM&TI were closer to the true model than the tomographic inversion result. Our reconstruction results from modeling marine data acquired in the Musicians Seamount Province in the Pacific Ocean indicate the capacity and limitations of FM&TI.
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Grivelet, Pierre A. "Inversion of vertical seismic profiles by iterative modeling." GEOPHYSICS 50, no. 6 (June 1985): 924–30. http://dx.doi.org/10.1190/1.1441971.
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I present an application of iterative modeling to the inversion of vertical seismic profiles (VSPs). This method is derived from linear inversion which allows the extraction from VSP data of an impedance profile as a function of time and thus permits the prediction of impedance ahead of the drill bit. There are two steps in this process: first, detection of the major events on the seismogram which is achieved by a recursive detection algorithm; and second, an optimal estimate of the impedances carried out by a gradient algorithm. Seismic data are band‐limited, and consequently the solution of the inversion is nonunique. This nonuniqueness is handled by assuming a piecewise‐constant or blocked impedance model and by adding a priori constraints. Some synthetic examples are used to illustrate the method, and a field example shows a comparison between an impedance profile extracted from VSP data with this inversion method and an impedance profile from well logging data. In this example the accurate prediction of impedance values illustrates the usefulness of the method.
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Ermert, Laura, Jonas Igel, Korbinian Sager, Eléonore Stutzmann, Tarje Nissen-Meyer, and Andreas Fichtner. "Introducing noisi: a Python tool for ambient noise cross-correlation modeling and noise source inversion." Solid Earth 11, no. 4 (August 28, 2020): 1597–615. http://dx.doi.org/10.5194/se-11-1597-2020.
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Abstract. We introduce the open-source tool noisi for the forward and inverse modeling of ambient seismic cross-correlations with spatially varying source spectra. It utilizes pre-computed databases of Green's functions to represent seismic wave propagation between ambient seismic sources and seismic receivers, which can be obtained from existing repositories or imported from the output of wave propagation solvers. The tool was built with the aim of studying ambient seismic sources while accounting for realistic wave propagation effects. Furthermore, it may be used to guide the interpretation of ambient seismic auto- and cross-correlations, which have become preeminent seismological observables, in light of nonuniform ambient seismic sources. Written in the Python language, it is accessible for both usage and further development and efficient enough to conduct ambient seismic source inversions for realistic scenarios. Here, we introduce the concept and implementation of the tool, compare its model output to cross-correlations computed with SPECFEM3D_globe, and demonstrate its capabilities on selected use cases: a comparison of observed cross-correlations of the Earth's hum to a forward model based on hum sources from oceanographic models and a synthetic noise source inversion using full waveforms and signal energy asymmetry.
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Neff, Dennis B. "Estimated pay mapping using three‐dimensional seismic data and incremental pay thickness modeling." GEOPHYSICS 55, no. 5 (May 1990): 567–75. http://dx.doi.org/10.1190/1.1442868.
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Better estimates of hydrocarbon pay thickness and reservoir distribution are achieved if forward modeling is combined with crossplot cluster analysis before the seismic amplitude and isochron data are converted into estimates of pay thickness. To facilitate this process, an enhanced convolutional modeling technique that incorporates petrophysical data and equations into the synthetic seismogram generation process was developed. These incremental pay thickness (IPT) forward models provide the pertinent seismic and petrophysical values required for crossplot analysis. The crossplot analyses then define which seismic variables (trough amplitude, peak amplitude, time structure, isochron, etc.) are most uniquely related to a pay thickness parameter (gross thickness, net thickness, net porosity thickness, or hydrocarbons in place). Work to date, mostly in offshore Gulf Coast gas sands, has shown significant variation in the crossplot transforms required to convert seismic data to estimated pay maps. As such, an interactive, model‐based, interpretive approach is recommended as an appropriate means to integrate petrophysical, geologic, and 3-D seismic data in the creation of reservoir pay maps.
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Buddo, Igor, Natalya Misyurkeeva, Ivan Shelokhov, Evgeny Chuvilin, Alexey Chernikh, and Alexander Smirnov. "Imaging Arctic Permafrost: Modeling for Choice of Geophysical Methods." Geosciences 12, no. 10 (October 21, 2022): 389. http://dx.doi.org/10.3390/geosciences12100389.
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Knowledge of permafrost structure, with accumulations of free natural gas and gas hydrates, is indispensable for coping with spontaneous gas emission and other problems related to exploration and production drilling in Arctic petroleum provinces. The existing geophysical methods have different potentialities for imaging the permafrost base and geometry, vertical fluid conduits (permeable zones), taliks, gas pockets, and gas hydrate accumulations in the continental Arctic areas. The synthesis of data on cryological and geological conditions was the basis for a geophysical–geological model of northern West Siberia to a depth of 400 m, which includes modern permafrost, lenses of relict permafrost with hypothetical gas hydrates, and a permeable zone that may be a path for the migration of gas–water fluids. The model was used to model synthetic seismic, electrical resistivity tomography (ERT), and transient electromagnetic (TEM) data, thus testing the advantages and drawbacks of the three methods. Electrical resistivity tomography has insufficient penetration to resolve all features and can run only in the summer season. Seismic surveys have limitations in mapping fluid conduits, though they can image a horizontally layered structure in any season. Shallow transient electromagnetic (sTEM) soundings can image any type of features included into the geological model and work all year round. Thus, the best strategy is to use TEM surveys as the main method, combined with seismic and ERT data. Each specific method is chosen proceeding from economic viability and feasibility in the specific physiographic conditions of mountain and river systems.
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Moghaddam, Peyman Poor, Audun Libak, Henk Keers, and Rolf Mjelde. "Efficient and accurate modeling of ocean bottom seismometer data using reciprocity." GEOPHYSICS 77, no. 6 (November 1, 2012): T211—T220. http://dx.doi.org/10.1190/geo2011-0498.1.
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Seismic experiments in which the number of sources is considerably larger than the number of receivers occur regularly. An important example is the collection of crustal scale seismic data using ocean bottom seismometers and marine sources. We describe a method to accurately and efficiently compute synthetic seismograms for such experiments by using finite differences and reciprocity. We show numerically how to decompose an explosive source into its equivalent body force components using the staggered-grid finite-difference technique with a fourth-order approximation for the spatial derivative and a second-order approximation for the temporal derivative. This decomposition results in a source configuration where the equivalent body forces are defined in 12 points around the point where the ex-plosive source is applied. We then use the derived equivalent body forces for the explosive source and seismic reciprocity theorems to convert the common receiver gather to a common shot gather. The method is tested on a structurally complex elastic model of the crust and the results show that it is accurate within floating point precision. The synthetic data are compared to data from a real ocean bottom seismometer experiment conducted across a continent-ocean transition zone. A good fit in terms of traveltime is observed for many of the prominent seismic phases. The amplitude fit of these arrivals is not always as good as the traveltime fit. This indicates that full-waveform modeling of such data can provide useful information about the subsurface that cannot be obtained from traveltime modeling. If enough data are available, the modeling method can be used in full-waveform inversion.
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Majdi, Amir Mustaqim, Seyed Yaser Moussavi Alashloo, Nik Nur Anis Amalina Nik Mohd Hassan, Abdul Rahim Md Arshad, and Abdul Halim Abdul Latiff. "Application Of Finite Difference Eikonal Solver For Traveltime Computation In Forward Modeling And Migration." Bulletin Of The Geological Society Of Malaysia 72 (November 15, 2021): 113–22. http://dx.doi.org/10.7186/bgsm72202109.
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Traveltime is one of the propagating wave’s components. As the wave propagates further, the traveltime increases. It can be computed by solving wave equation of the ray path or the eikonal wave equation. Accurate method of computing traveltimes will give a significant impact on enhancing the output of seismic forward modeling and migration. In seismic forward modeling, computation of the wave’s traveltime locally by ray tracing method leads to low resolution of the resulting seismic image, especially when the subsurface is having a complex geology. However, computing the wave’s traveltime with a gridding scheme by finite difference methods able to overcomes the problem. This paper aims to discuss the ability of ray tracing and fast marching method of finite difference in obtaining a seismic image that have more similarity with its subsurface model. We illustrated the results of the traveltime computation by both methods in form of ray path projection and wavefront. We employed these methods in forward modeling and compared both resulting seismic images. Seismic migration is executed as a part of quality control (QC). We used a synthetic velocity model which based on a part of Malay Basin geology structure. Our findings shows that the seismic images produced by the application of fast marching finite difference method has better resolution than ray tracing method especially on deeper part of subsurface model.
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Cao, Zelin, Xiaxin Tao, Zhengru Tao, and Aiping Tang. "Kinematic Source Modeling for the Synthesis of Broadband Ground Motion Using the f‐k Approach." Bulletin of the Seismological Society of America 109, no. 5 (July 23, 2019): 1738–57. http://dx.doi.org/10.1785/0120180294.
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Abstract A procedure for building a kinematic source model is proposed in this article for the synthesis of broadband ground motion based on the frequency–wavenumber Green’s function. The spatial distribution of slip on the rupture plane is generated by combining asperity slip with random slip. A set of scaling laws recently updated for the global and local parameters of seismic sources is adopted. To characterize the temporal evolution of slip on the rupture plane, different rupture velocities, and rise times are first generated by considering the correlation with slip, and a source time function obtained by rupture dynamics is selected for each subsource. Then, the entire rupture process is set as the object to jointly determine the rise time and rupture velocity for a given slip distribution under the selection criterion that the entire rupture process should radiate the closest seismic energy to the expected energy. To reduce uncertainty, 30 spatiotemporal rupture processes for an earthquake scenario are realized to select a mean source model. To demonstrate the feasibility of the proposed source modeling approach, two California earthquakes, the Whittier Narrows earthquake and the Loma Prieta earthquake, are chosen as case studies. The performance of the obtained source models shows that our modeling approach is advantageous for estimating the size of the rupture plane, emphasizing the effect of asperity, and considering the correlation between temporal rupture parameters and slip. The bias values between the observed and synthetic pseudospectral accelerations are relatively small compared to those for the methods on the Southern California Earthquake Center broadband platform. The synthetics are further compared with the estimates from regional ground‐motion prediction equations for four scenario earthquakes with moment magnitudes of 6.0, 6.5, 7.0, and 7.5. Finally, the sensitivity of the synthetic motion to various rupture parameters is analyzed.
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Van De Coevering, Norbert, Klaas Koster, and Rob Holt. "A skeptic's view of VVAz and AVAz." Leading Edge 39, no. 2 (February 2020): 128–34. http://dx.doi.org/10.1190/tle39020128.1.
Full textAbstract:
We have applied a modern amplitude- and azimuth-preserving seismic data processing workflow to the SEG Advanced Modeling Program (SEAM) Phase II Barrett classic data set — an orthorhombic synthetic seismic model that has extremely dense sampling of all azimuths and offsets. We analyze the resulting prestack depth-migrated offset vector tiles with a variety of methods and software. Note that we only analyze the P-P wave mode, which is the focus of our study. We demonstrate that observed azimuthal changes cannot be correlated with the model's reservoir properties. We have made the migrated data available through SEAM. Compared to modeled data, real onshore seismic data have significantly lower amplitude fidelity, higher noise levels, and more uncertainty in the migration velocity field used for processing. Since we are unable to relate the anisotropy measured from the fully sampled clean SEAM Phase II Barrett synthetic seismic data to the model's known anisotropy, we conclude that it is highly unlikely that azimuthal variations observed on real onshore seismic data will be predictive of reservoir fracture properties.
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Liao, Qingbo, and George A. McMechan. "Multifrequency viscoacoustic modeling and inversion." GEOPHYSICS 61, no. 5 (September 1996): 1371–78. http://dx.doi.org/10.1190/1.1444060.
Full textAbstract:
Modeling and inversion for seismic wavefields that include the attenuation and phase dispersion effects of Q can be implemented in the space‐frequency domain. The viscoacoustic wave equation is solved by the moment method. Absorbing boundary conditions are implemented by reducing Q and adjusting the complex velocity (to reduce Q‐dependent reflectivity) in a zone around the edges of the model grid. Nonlinear inversion is performed using iterative linearized inversions. The residual wavefield at a single frequency is back projected, using an anticausal Green’s function, along the viscoacoustic wavepath in an estimate of the model, to get updated velocity and Q distributions. The model obtained from data at one frequency becomes input to inversion at the next higher frequency. Velocity and Q are inverted simultaneously as they are interdependent. Both modeling and inversion algorithms are successfully tested with synthetic examples; data at two or three frequencies are sufficient to produce reliable images from noise‐free synthetic data.
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Zeng, Hongliu, Yawen He, Charles Kerans, and Xavier Janson. "Seismic chronostratigraphy at reservoir scale: Lessons from a realistic seismic modeling of mixed clastic-carbonate strata in the Permian Basin, West Texas and New Mexico, USA." Interpretation 8, no. 1 (February 1, 2020): T13—T25. http://dx.doi.org/10.1190/int-2019-0053.1.
Full textAbstract:
We tested the validity of tracking seismic events as representations of chronostratigraphic surfaces at the subseismic, high-frequency-cycle level. A high-resolution geocellular model was generated from approximately 400 m of mixed clastic-carbonate sequences in the San Andres and Grayburg Formations in the Permian Basin, with 0.3–0.6 m layering and minimal upscaling. Realistic stratigraphic framework, facies, and velocity volumes were created by geostatistically mapping data from outcrop and subsurface sources while honoring state-of-the-art principles of stratigraphic and sedimentary analyses. Using the synthetic seismic data of different frequencies, the potential and pitfalls of using autotracked seismic horizons in building high-resolution reservoir models were tested. At the reservoir (meter) scale, the seismic reflections from flatter and thicker sediments with less facies and velocity heterogeneities tend to follow geologic-time surfaces; on the contrary, reflections from where thin sediments dip against flat strata with more facies and velocity heterogeneities tend to follow lithostratigraphy. For the latter seismic-guided reservoir modeling is not very precise, even with data as high as 140 Hz frequency. Therefore, for seismic-assisted reservoir prediction and modeling, the interpretation of seismic events is useful, but well calibration is critical.
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Kim, Sooyoon, Soon Jee Seol, Joongmoo Byun, and Seokmin Oh. "Extraction of diffractions from seismic data using convolutional U-net and transfer learning." GEOPHYSICS 87, no. 2 (January 27, 2022): V117—V129. http://dx.doi.org/10.1190/geo2020-0847.1.
Full textAbstract:
Diffraction images can be used for modeling reservoir heterogeneities at or below the seismic wavelength scale. However, the extraction of diffractions is challenging because their amplitude is weaker than that of overlapping reflections. Recently, deep-learning (DL) approaches have been used as a powerful tool for diffraction extraction. Most DL approaches use a classification algorithm that classifies pixels in the seismic data as diffraction, reflection, noise, or diffraction with reflection and takes whole values for the classified diffraction pixels. Thus, these DL methods cannot extract diffraction energy from pixels for which diffractions are masked by reflections. We have developed a DL-based diffraction extraction method that preserves the amplitude and phase characteristics of diffractions. Through the systematic generation of a training data set using synthetic modeling based on t-distributed stochastic neighbor embedding analysis, this technique extracts not only faint diffractions but also diffraction tails overlapped by strong reflection events. We also determine that the DL model pretrained with a basic synthetic data set can be applied to seismic field data through transfer learning. Because the diffractions extracted by our method preserve the amplitude and phase, they can be used for velocity model building and high-resolution diffraction imaging.
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Stafleu, Jan, Wolfgang Schlager, Arnout J. W. Everts, Jeroen A. M. Kenter, Geert Blommers, and Anton van Voorden. "Outcrop topography as a proxy of acoustic impedance in synthetic seismograms." GEOPHYSICS 61, no. 6 (November 1996): 1779–88. http://dx.doi.org/10.1190/1.1444094.
Full textAbstract:
Two‐dimensional seismic models of geologic data are usually based on simplified impedance functions: large “seismic‐scale” lithologic blocks exhibit uniform impedance values, and abrupt changes in impedance occur at the boundaries of these lithologic blocks. For outcrop‐based seismic models, erosional slope topography may be one possible proxy for impedance that is relatively easy to measure in outcrop. In this paper, we use terrestrial photogrammetric techniques to establish the relationship between outcrop topography, expressed as the rock slope angle, and impedance for a marl‐limestone terrain in the Vercors, southeast France. The photogrammetric surveys were combined with sedimentologic descriptions and petrophysical measurements (including P‐wave velocity, bulk‐density, clay content, and porosity). The slope angle along a particular vertical profile was then converted into a pseudoimpedance log, which was subsequently used to construct 1-D synthetic seismograms. A comparison of these new seismograms with published seismic models of the same area revealed the benefits of the new approach, in particular for seismic modeling using high‐frequency source wavelets.
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Viony, Natashia Christy, and Wahyu Triyoso. "Study of Converted-Wave Modeling: AVO Application for Shallow Gas Models." Jurnal Geofisika 16, no. 2 (September 19, 2018): 19. http://dx.doi.org/10.36435/jgf.v16i2.362.
Full textAbstract:
The application of converted-wave seismic method in hydrocarbon exploration has increased significantly. Since the conventional seismic ceases to provide an adequate result in complex geology area and it provides an ambiguous brightspot response. The main principle is that an incident P-wave produces reflected and converted P and SV wave when the downgoing P-wave impinges on an interface. Converted-wave seismic uses the multicomponent receiver that records both of vertical component and horizontal component. The vertical component is assumed to correspond to the compressional PP wave and the horizontal correspond to the PS converted-wave. In this research, a synthetic model with the shallow gas and the salt dome below are constructed. The purpose of this study is to analyze the brightspot due to the presence of shallow gas and its effect to the quality of PP and PS wave reflection below the gas zone. To achieve the goal, both vertical and horizontal seismic data processing are performed. In horizontal data processing, the best gamma function (Vp/Vs) value is estimated to produce the better and reliable image. The result shows that the brightspot response in conventional data doesn’t exist in converted-wave data and the imaging below the gas zone in converted-wave data is better than the conventional due to the attenuation and diffraction effect that caused by gas column. Processing is followed by AVO analysis to compare the AVO response of PP and PS data in characterizing gas reservoir. Both PP and PS AVO curve shows the consistency with synthetic AVO from well data. Gas reservoir is a class 1 AVO anomaly with positive intercept and negative gradient on PP data. However, PS AVO curve does not refer any anomaly. It is because S-wave is not sensitive to the existence of rock saturant.