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Journal articles on the topic 'Seismic amplitude'
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Meng, Fan Chao, Xiao Ming Yuan, and Hui Xue. "Effect of Loading Amplitude on Soil Deformation under Irregular Waves and Fixed-Number Waves." Applied Mechanics and Materials 256-259 (December 2012): 2015–18. http://dx.doi.org/10.4028/www.scientific.net/amm.256-259.2015.
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Through series of dynamic triaxial tests, the relationships of soil deformations under irregular seismic loading and fixed-number constant amplitude loading are analyzed. The effect of loading amplitudes on the relationships is presented. The results shows: (1) soil deformation under irregular seismic loading obviously differs from that under constant amplitude sinusoidal loading, and the strain history is mainly controlled by the performance of ground motion; (2) if 20 cycles of constant amplitude loading is employed instead of irregular seismic loading to correct residual deformation under real seismic loading, loading amplitudes have no effect on soil deformation under irregular waves and fix-number waves.
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Farfour, Mohammed. "Amplitude components analysis: Theory and application." Leading Edge 39, no. 1 (January 2020): 62a1–62a6. http://dx.doi.org/10.1190/tle39010062.1.
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Seismic data are rich in information about subsurface formations and their pore content. This information can be retrieved from the amplitude or frequencies of seismic signals. Spectral decomposition is a seismic interpretation technique that enables interpreters to decompose the broadband of seismic signals into constituent frequencies. Likewise, amplitude components analysis (ACA) is an approach proposed to compute amplitude constituent components as a function of offset. The approach uses amplitude-variation-with-offset approximations to extract amplitude components that compose the amplitudes in stacked sections. ACA can be used to screen seismic data for possible hidden anomalies that may be associated with hydrocarbons. ACA also helps predict seismic responses at angles where data are not recorded or are of poor quality. Because abnormal expressions associated with hydrocarbons can be observed in clastic and carbonate formations, the approach can look for the expressions in both types of reservoir rocks.
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Farfour, Mohammed. "Amplitude components analysis: Theory and application." Leading Edge 39, no. 1 (January 2020): 62a1–62a6. http://dx.doi.org/10.1190/tle39010062a1.1.
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Seismic data are rich in information about subsurface formations and their pore content. This information can be retrieved from the amplitude or frequencies of seismic signals. Spectral decomposition is a seismic interpretation technique that enables interpreters to decompose the broadband of seismic signals into constituent frequencies. Likewise, amplitude components analysis (ACA) is an approach proposed to compute amplitude constituent components as a function of offset. The approach uses amplitude-variation-with-offset approximations to extract amplitude components that compose the amplitudes in stacked sections. ACA can be used to screen seismic data for possible hidden anomalies that may be associated with hydrocarbons. ACA also helps predict seismic responses at angles where data are not recorded or are of poor quality. Because abnormal expressions associated with hydrocarbons can be observed in clastic and carbonate formations, the approach can look for the expressions in both types of reservoir rocks.
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Protasov, M. I., and V. A. Cheverda. "True-amplitude seismic imaging." Doklady Earth Sciences 407, no. 2 (March 2006): 441–45. http://dx.doi.org/10.1134/s1028334x06030214.
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Yu, Gary. "Offset‐amplitude variation and controlled‐amplitude processing." GEOPHYSICS 50, no. 12 (December 1985): 2697–708. http://dx.doi.org/10.1190/1.1441890.
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The partition of plane seismic waves at plane interfaces introduces changes in seismic amplitude which vary with angle of incidence. These amplitude variations are a function of the elastic parameters of rocks on either side of the interface. Controlled‐amplitude processing is designed to obtain the true amplitude information which is geologic in origin. The offset‐amplitude information may be successfully used to predict the fluid type in reservoir sands. Various tests were carried out on a seismic profile from the Gulf Coast. The processing comparison emphasized the effects and pitfalls of trace equalization, coherent noise, offset, and surface‐related problems. Two wells drilled at amplitude anomaly locations confirmed the prediction of hydrocarbons from offset‐amplitude analysis. Furthermore, controlled‐amplitude processing provided clues in evaluating reservoir quality, which was not evident on the conventional relative amplitude data.
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Payson Todd, C., James Simmons, and Ali Tura. "Target-oriented model-based seismic footprint analysis and mitigation." Interpretation 8, no. 4 (June 26, 2020): SR1—SR15. http://dx.doi.org/10.1190/int-2019-0078.1.
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Compensating for the effects of an acquisition footprint can be one of the most daunting problems when using seismic attributes for quantitative interpretation. This is especially true for unconventional plays because they are on land with accompanying irregular acquisition geometries. Additionally, in such plays, the physical property changes are often small, making the seismic amplitude fidelity critical. We have developed a methodology that integrates a 1D elastic prestack synthetic model with 3D acquisition geometry to accurately model the seismic footprint produced by irregular or insufficient sampling of primary reflectivity. The stacked amplitude response of the modeled survey is then used to mitigate the poststack footprint on the field seismic. Modeling and removing this element of the acquisition footprint quantitatively improve the interpretive value of the mapped seismic amplitudes. In our study area, correlation between seismic amplitudes and well control increased from an [Formula: see text] of 0.053 before correction to an [Formula: see text] of 0.629 after. Our approach is especially effective in situations in which the spatial frequency of the footprint overlaps that of the geologic signal. Geological feature: Acquisition related seismic amplitude artifacts Seismic appearance: Smoothly varying amplitude changes Alternative interpretations: Bed thickness variation Features with similar appearance: Carbonate porosity Formation: Niobrara Formation, mixed chalks and marlstones Age: Upper Cretaceous Location: Wattenberg Field, Denver Basin, north central Colorado Seismic data: Joint acquisition between Anadarko Petroleum and Colorado School of Mines, Reservoir Characterization Project Analysis tools: Elastic prestack seismic modeling
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Akhmedov, T. R., A. M. Mamedova, and A. A. Mamedov. "Improving the information content of seismic data and increasing the depth of investigation by choosing the optimal length of the amplitude adjustment operator." IOP Conference Series: Earth and Environmental Science 1045, no. 1 (June 1, 2022): 012136. http://dx.doi.org/10.1088/1755-1315/1045/1/012136.
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Abstract The article is devoted to the role of digital automatic amplitude control in increasing the depth of seismic exploration. It is noted that the depth of productive strata is gradually increasing, at the same time, more powerful explosive sources are being replaced by relatively weak non-explosive ones. Naturally, during processing, it is necessary to pay close attention to the choice of parameters for adjusting the amplitudes. The article provides basic information about the form and amplitude of seismic vibrations, lists the main empirical formulas that characterize the dependence of the amplitudes of seismic vibrations on time. It is noted that when registering seismic vibrations, one has to deal with minimal soil displacements caused by the arrival of a seismic wave at the observation point, which must be amplified millions of times and their adjustment. In this regard, in the digital processing of seismic data, a technique was developed for recovering the true amplitudes, more precisely, the true amplitude ratio. Adjustment while maintaining the true ratio of amplitudes is used only when it is required to study the dynamics of the wave field (dynamic digital processing). The optimal choice of the length of the adjustment operator (or window) is of paramount importance, since with a small adjustment interval (less than 0.1 s), a loss of dynamic expressiveness of the recording may occur, and this is clearly shown in model studies. The article considers the efficiency of choosing the length of the optimal adjustment operator on the example of the Kurovdag area, which has complex both surface and deep seismogeological conditions. A summary of the Kurovdag field is given. An amplitude compensation function for spherical divergence is given, and to compensate for the effects associated with changes in reception and excitation conditions, a surface-matched amplitude adjustment was performed after removing amplitude bursts. A fragment of the time section is given before and after the optimal adjustment of the amplitudes according to the seismograms of the Kurovdag area, which clearly demonstrates how the information content of the time section increases and, thereby, the depth of the seismic exploration: before the optimal digital automatic adjustment of the amplitudes at times of 3.25 - 3.5 sec, no seismic horizons, while after this procedure, dynamically well-defined seismic horizons appear at the same times, reflecting the structure of the medium at great depths.
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Miharno, Fatimah. "ANALISA POTENSI MINYAK DAN GAS BUMI DENGAN ATRIBUT SEISMIK PADA BATUAN KARBONAT LAPANGAN *ZEFARA* CEKUNGAN SUMATRA SELATAN." KURVATEK 1, no. 2 (May 23, 2017): 21–31. http://dx.doi.org/10.33579/krvtk.v1i2.250.
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ABSTRACT*Zefara* Field formation Baturaja on South Sumatra Basin is a reservoir carbonate and prospective gas. Data used in this research were 3D seismik data, well logs, and geological information. According to geological report known that hidrocarbon traps in research area were limestone lithological layer as stratigraphical trap and faulted anticline as structural trap. The study restricted in effort to make a hydrocarbon accumulation and a potential carbonate reservoir area maps with seismic attribute. All of the data used in this study are 3D seismic data set, well-log data and check-shot data. The result of the analysis are compared to the result derived from log data calculation as a control analysis. Hydrocarbon prospect area generated from seismic attribute and are divided into three compartments. The seismic attribute analysis using RMS amplitude method and instantaneous frequency is very effective to determine hydrocarbon accumulation in *Zefara* field, because low amplitude from Baturaja reservoir. Low amplitude hints low AI, determined high porosity and high hydrocarbon contact (HC). Keyword: Baturaja Formation, RMS amplitude seismic attribute, instantaneous frequency seismic attribute
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Smalera, Norbert. "Attribute analysis as a tool for determining the areas of the late diagenetic Main Dolomite deposits and assessing the stability of the seismic signal parameters." Geology, Geophysics and Environment 48, no. 2 (July 5, 2022): 111–32. http://dx.doi.org/10.7494/geol.2022.48.2.111.
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The results of the lithofacial analysis of data from the Moracz 3D seismic survey were among the main premises leading to the positioning of the new petroleum exploration well in that area. Unfortunately, the reservoir properties of the drilled part of the Main Dolomite carbonates differed significantly from those anticipated by the analysis of the amplitudes of the seismic signal recorded. Such surprisingly negative results impelled the reinterpretation of 3D seismic data. Hence, a number of analyses of the amplitudes, the frequencies, and the variability of phase shift were carried out in order to determine the influence of these parameters on the lithofacial interpretation of seismic data. The results revealed a fundamental error of amplitude with the extraction maps. It appeared that the distribution of amplitudes is not essentially controlled by the reservoir properties of the Main Dolomite carbonates but by the fault shadow effect coming from Mesozoic graben in the overburden. In addition, a large diversity of frequency spectra was found, which, combined with the small thickness of the exploration level, could have contributed to incorrect identification of seismic reflections. There was also a change in seismic signatures from the same reflection in different parts of the survey, raising doubts about the distribution of the phase rotation. In order to recognize phase rotation diversity, a new seismic data analysis was based upon the selected Triassic sediments of high impedance. The obtained maps demonstrated significant variability within the data volume due to attenuation. The reinterpreted data from the Moracz 3D seismic survey proved the uneven and unstable distribution of amplitudes, frequencies, and phase which resulted in erroneous conclusions of petroleum exploration. After modeling with the use of different frequency ranges, an analysis of the amplitude extraction of the horizons related to the Main Dolomite was performed. Then the amplitude ratio attribute was selected which eliminated the influence of the regional amplitude and frequency distribution and showed the distribution of dolomite properties more reliably than the amplitude extraction maps.
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Singh, Ram Janma. "Exploration application of seismic amplitude analysis in the Krishna-Godavari Basin, east coast of India." Interpretation 2, no. 4 (November 1, 2014): SP5—SP20. http://dx.doi.org/10.1190/int-2013-0197.1.
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Seismic amplitude anomalies are attractive exploration targets in the Krishna-Godavari Basin offshore India. These bright spots mostly have very high amplitudes, so confident interpretations have been possible. We distinguished between hydrocarbon-bearing sands, water-bearing sands, and high-impedance nonreservoir bodies. Also, we mapped channel architecture and accurately predicted reservoir thickness. Strong amplitude anomalies, prospective seismic character based on an understanding of data phase and polarity, flat spots, and amplitude versus offset have all provided valuable evidence.
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Kumar, Dhananjay, Zeyu Zhao, Douglas J. Foster, Danica Dralus, and Mrinal K. Sen. "Frequency-dependent AVO analysis using the scattering response of a layered reservoir." GEOPHYSICS 85, no. 2 (January 9, 2020): N1—N16. http://dx.doi.org/10.1190/geo2019-0167.1.
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Sensitivity of reservoir properties to broadband seismic amplitudes can be weak, which makes interpretation ambiguous. Examples of challenging interpretation scenarios include distinguishing blocky reservoirs from fining sequences, low gas saturation from high gas saturation, and variable reservoir quality. Some of these rock and fluid changes might indicate stronger sensitivity to amplitudes over narrow frequency bands, which is a characteristic of frequency-dependent amplitude variation with offset (FAVO). We have developed a FAVO model for reservoir characterization, following a seismic scattering phenomenon through a set of isotropic elastic layers. The frequency dependency in our model comes from the time delays due to wave propagation within layers. The FAVO modeled response is a complex-valued amplitude varying with angle and frequency, and it is a function of the seismic velocities and thicknesses of individual layers, along with the conventional AVO response at all interfaces. Our FAVO seismic analysis consists of two main steps: (1) forward modeling using well logs to understand rock and fluid sensitivity to amplitudes to identify tuning frequencies with maximum amplitude excursions and (2) seismic analysis at tuning frequencies. With well-log models, we observed that the frequency-dependent tuning response is primarily dependent on the lithology stacking pattern of a reservoir; in the cases studied, the fluid and reservoir quality have secondary effects on the frequency dependence of the amplitudes. We evaluate synthetic models and field data from the Columbus Basin, Trinidad, to illustrate our frequency-dependent seismic analysis methods. For one of the sandstone reservoirs, a frequency-dependent attribute indicates better spatial resolution of the anomaly than a conventional amplitude extraction. FAVO attributes are complementary to conventional AVO attributes.
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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.
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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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Sengupta, M. K., and C. A. Rendleman. "Case study: The importance of gas leakage in interpreting amplitude‐versus‐offset (AVO) analysis." GEOPHYSICS 56, no. 11 (November 1991): 1886–95. http://dx.doi.org/10.1190/1.1443000.
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The amplitude‐versus‐offset (AVO) method has been shown to indicate the presence of gas sands if the reflection amplitude from the seal/reservoir‐sand interface, measured in a common midpoint (CMP) gather, increases rapidly with increasing shot‐to‐geophone distance (or offset). However, in a few instances, it has been observed that the seismic reflection amplitude does not increase with offset and may even decrease if there is widespread gas leakage above the hydrocarbon reservoir causing partial gas saturation in the overburden sediments. Gas‐charged sediments are known to attenuate seismic energy. Depending on the size and shape of this gas leakage zone, there may be higher attenuation of seismic amplitudes with increasing offset. We present one such case that involves a prominent “bright‐spot” amplitude anomaly corresponding to a 56‐ft‐thick (17 m‐thick) gas sand in the Gulf of Mexico slope. The reflection amplitude for the sand top was found to decrease with increasing offset. There is also evidence of gas leakage into the sediments above the reservoir. Color amplitude displays of the seismic section show a low‐amplitude diffused zone above the bright‐spot amplitude anomaly, which suggests gas leakage. Further evidence of gas leakage can be inferred from the significant gas content (including heavier hydrocarbons) observed in the mud log. Gas leakage is also confirmed by gather modeling in which the effects of leakage‐caused attenuation are accounted for in matching the variation of seismic amplitude with offset.
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Contreras, Arturo, Carlos Torres-Verdín, and Tim Fasnacht. "Sensitivity analysis of data-related factors controlling AVA simultaneous inversion of partially stacked seismic amplitude data: Application to deepwater hydrocarbon reservoirs in the central Gulf of Mexico." GEOPHYSICS 72, no. 1 (January 2007): C19—C29. http://dx.doi.org/10.1190/1.2399353.
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We consider the inversion of synthetic and recorded seismic amplitude variation with angle AVA data to appraise the influence of several data-related factors that control the vertical resolution and accuracy of the estimated spatial distributions of elastic properties. We use measurements acquired in deepwater hydrocarbon reservoirs in the central Gulf of Mexico to generate synthetic seismic amplitude data and evaluate inversion results with both synthetic and recorded seismic amplitudes. Detailed sensitivity analysis of synthetic amplitude data indicates that, even in the most ideal scenario (perfectly migrated data, isotropic media, noise-free seismic amplitude data, sufficient far-angle coverage, and accurate estimates of angle-dependent wavelets and low-frequency components), input elastic models are not reconstructedaccurately by the inversion of synthetic seismic amplitudes. We attribute this result to the relatively low vertical resolution of the seismic amplitude data. P-wave impedance is the most accurate of the inverted properties, followed by S-impedance and bulk density. Additionally, sufficient far-angle coverage is crucial for the accurate estimation of 1D distributions of S-impedance and bulk density. We show that time alignment of partial-angle stacks for correcting residual NMO effects improves the vertical resolution of the estimated spatial distributions of elastic parameters and consistently decreases the data misfit. Finally, we found that the accuracy of the inverted distributions of elastic parameters is improved substantially by (1) increasing the preserved AVA information via multiple single-angle stacks, (2) correcting the P-wave velocity field used for calculating angles in partial-angle stacking, and (3) excluding far-angle data with low signal-to-noise ratios.
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Brown, Alistair R. "The value of seismic amplitude." Leading Edge 6, no. 10 (October 1987): 30–33. http://dx.doi.org/10.1190/1.1439335.
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Kanasewich, Ernest R., and Suhas M. Phadke. "Imaging discontinuities on seismic sections." GEOPHYSICS 53, no. 3 (March 1988): 334–45. http://dx.doi.org/10.1190/1.1442467.
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In routine seismic processing, normal moveout (NMO) corrections are performed to enhance the reflected signals on common‐depth‐point or common‐midpoint stacked sections. However, when faults are present, reflection interference from the two blocks and the diffractions from their edges hinder fault location determination. Destruction of diffraction patterns by poststack migration further inhibits proper imaging of diffracting centers. This paper presents a new technique which helps in the interpretation of diffracting edges by concentrating the signal amplitudes from discontinuous diffracting points on seismic sections. It involves application to the data of moveout and amplitude corrections appropriate to an assumed diffractor location. The maximum diffraction amplitude occurs at the location of the receiver for which the diffracting discontinuity is beneath the source‐receiver midpoint. Since the amplitudes of these diffracted signals drop very rapidly on either side of the midpoint, an appropriate amplitude correction must be applied. Also, because the diffracted signals are present on all traces, one can use all of them to obtain a stacked trace for one possible diffractor location. Repetition of this procedure for diffractors assumed to be located beneath each surface point results in the common‐fault‐ point (CFP) stacked section, which shows diffractor locations by high amplitudes. The method was tested for synthetic data with and without noise. It proves to be quite effective, but is sensitive to the velocity model used for moveout corrections. Therefore, the velocity model obtained from NMO stacking is generally used for enhancing diffractor locations by stacking. Finally, the technique was applied to a field reflection data set from an area south of Princess well in Alberta.
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Oliveira, Danian Steinkirch de, Paulo Eduardo Miranda Cunha, Luiz Gallisa Guimaraes, and Andre Fabiano Steklain. "High-Resolution Ray Tracing Migration." Brazilian Journal of Geophysics 39, no. 4 (December 6, 2021): 521. http://dx.doi.org/10.22564/rbgf.v39i4.2112.
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ABSTRACT. We present a seismic migration algorithm that calculates travel times and amplitudes based on the paraxial extrapolation of the dynamic ray tracing. We use a target-oriented approach with automatic selection of migration parameters and seismic traces that will compose the image. By associating the ray parameter (slowness vector) with the amplitudes of the seismic data, we reach a new form of migration amplitude conditioner that acts as a filter and may increase the resolution of reflectors and faults. On the other hand, when using the seismic amplitudes as weights, we can estimate the slowness vectors associated with the true seismic reflectors in depth. We apply this method to the synthetic seismic data of the Marmousi velocity model. When comparing the migrated seismic section to the true interval velocity model, we can see a precise matching of the geological features in a high-resolution pattern.Keywords: seismic migration, target-orientation, dynamic ray tracing, paraxial amplitude extrapolation. Migração por Traçado de Raios de Alta ResoluçãoRESUMO. Apresentamos um algoritmo de migração sísmica que calcula tempos e amplitudes de viagem com base na extrapolação paraxial do traçado dinâmico de raios. Utilizamos uma abordagem orientada a alvos com seleção automática dos parâmetros de migração e dos traços sísmicos que irão compor a imagem. Ao associar o parâmetro de raio (vetor de vagarosidade) às amplitudes dos dados sísmicos, chegamos a uma nova forma de condicionador de amplitudes de migração que atua como filtro e pode aumentar a resolução de refletores e falhas. Por outro lado, ao usar as amplitudes sísmicas como pesos, podemos estimar os vetores de vagarosidade associados aos verdadeiros refletores sísmicos em profundidade. Aplicamos este método aos dados sísmicos sintéticos do modelo de velocidade de Marmousi. Ao comparar a seção sísmica migrada com o modelo de velocidades intervalar verdadeiro, podemos ver uma correspondência precisa das feições geológicas em um padrão de alta resolução.Palavras-chave: migração sísmica, orientação ao alvo, traçado dinâmico de raios, extrapolação paraxial de amplitude.
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Mori, Azusa, and Hiroyuki Kumagai. "Estimating plume heights of explosive eruptions using high-frequency seismic amplitudes." Geophysical Journal International 219, no. 2 (August 19, 2019): 1365–76. http://dx.doi.org/10.1093/gji/ggz374.
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SUMMARY Seismic signals during explosive eruptions have been correlated to eruption size or eruption volume flux for individual eruptive episodes. However, the universality of these correlations has yet to be confirmed. We quantified the sources of high-frequency seismic signals associated with sub-Plinian and Vulcanian eruptions at Kirishima (Japan), Tungurahua (Ecuador) and other volcanoes in Japan using a simple approach based on highly scattered seismic waveform characteristics. We found that eruption plume heights scale to seismic source amplitudes and are described by two relations depending on the value of source amplitudes: power-law and exponential relations for plume height >6 km and <6 km, respectively. Though conceptually similar, our scaling relations differ from the previously proposed relation based on reduced displacement. By comparing seismic and geodetic data during sub-Plinian eruptions at Kirishima, we found that the source amplitude is proportional to eruption volume flux. Combining these relations, we show that our scaling relation for Plinian eruptions is consistent with predictions from plume dynamics models. We present a source model to explain the proportionality between the source amplitude and eruption volume flux assuming a vertical crack or a cylindrical conduit as the source. The source amplitude can be estimated in seconds without any complicated data processing, whereas eruption plumes take minutes to reach their maximum heights. Our results suggest that high-frequency seismic source amplitudes are useful for estimating plume heights in real time.
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Baharvand Ahmadi, Amin, and Igor Morozov. "Anisotropic frequency-dependent spreading of seismic waves from first-arrival vertical seismic profile data analysis." GEOPHYSICS 78, no. 6 (November 1, 2013): C41—C52. http://dx.doi.org/10.1190/geo2012-0401.1.
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A model of first-arrival amplitude decay combining geometric spreading, scattering, and inelastic dissipation is derived from a multioffset, 3D vertical seismic profile data set. Unlike the traditional approaches, the model is formulated in terms of path integrals over the rays and without relying on the quality factor ([Formula: see text]) for rocks. The inversion reveals variations of geometric attenuation (wavefront curvatures and scattering, [Formula: see text]) and the effective attenuation parameter ([Formula: see text]) with depth. Both of these properties are also found to be anisotropic. Scattering and geometric spreading (focusing and defocusing) significantly affect seismic amplitudes at lower frequencies and shallower depths. Statistical analysis of model uncertainties quantitatively measures the significance of these results. The model correctly predicts the observed frequency-dependent first-arrival amplitudes at all frequencies. This and similar models can be applied to other types of waves and should be useful for true-amplitude studies, including inversion, inverse [Formula: see text]-filtering, and amplitude variations with offset analysis. With further development of petrophysical models of internal friction and elastic scattering, attenuation parameters [Formula: see text] and [Formula: see text] should lead to constraints on local heterogeneity and intrinsic physical properties of the rock. These parameters can also be used to build models of the traditional frequency-dependent [Formula: see text] for forward and inverse numerical viscoelastic modeling.
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Denelle, E. "TO TACKLE THE DECONVOLUTION PROBLEM — A POWERFUL METHOD BASED ON MORE GEOLOGICAL HYPOTHESES." APPEA Journal 26, no. 1 (1986): 192. http://dx.doi.org/10.1071/aj85019.
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The new rules of the game in hydrocarbon exploration demand an exact positioning of the seismic markers in order to define the geometry of the targets more than ever before. However, the degree of success will depend to a great extent on how accurately the amplitude of reflection coefficients can be estimated.These new requirements mean that all stages of traditional seismic processing have to be critically evaluated. It can be seen, in particular, when assessing existing deconvolution methods for seismic processing, that they are often ill-conditioned to problems posed by the targets of stratigraphic exploration or by reservoir seismic prospecting. The amplitude of the reflectivity function is often estimated inaccurately.The approach described in this paper abandons the usual hypothesis (white reflectivity spectra) made by deconvolution methods and employs as alternative information the lateral redundancies which are always present on a seismic section. Our method first estimates the location of high amplitude reflectors with good lateral continuity, by means of an elegant automatic picking program. Based on these locations, a generalized inversion can be used to yield the wavelet emitted by the source, and the amplitude of the main reflection coefficients simultaneously for each trace. All the reflection coefficients are then estimated using the amplitudes and the wavelets computed previously.The various stages of this method which is called Deconvolution-Inversion, developed by Total Compagnie Française des Pétroles, are illustrated in the paper by means of both synthetic and real examples. The ability of the method to preserve the amplitudes makes it a powerful tool for stratigraphic and reservoir seismic prospecting purposes.
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Chabyshova, Elmira, and Gennady Goloshubin. "Seismic modeling of low-frequency “shadows” beneath gas reservoirs." GEOPHYSICS 79, no. 6 (November 1, 2014): D417—D423. http://dx.doi.org/10.1190/geo2013-0379.1.
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P-wave amplitude anomalies below reservoir zones can be used as hydrocarbon markers. Some of those anomalies are considerably delayed relatively to the reflections from the reservoir zone. High P-wave attenuation and velocity dispersion of the observed P-waves cannot justify such delays. The hypothesis that these amplitude anomalies are caused by wave propagation through a layered permeable gaseous reservoir is evaluated. The wave propagation through highly interbedded reservoirs suggest an anomalous amount of mode conversions between fast and slow P-waves. The converted P-waves, which propagated even a short distance as slow P-waves, should be significantly delayed and attenuated comparatively, with the fast P-wave reflections. The amplitudes and arrival time variations of conventional and converted P-wave reflections at low seismic frequencies were evaluated by means of an asymptotic analysis. The calculations confirmed that the amplitude anomalies due to converted P-waves are noticeably delayed in time relatively to fast P-wave reflections. However, the amplitudes of the modeled converted P-waves were much lower than the amplitude anomalies observed from exploration cases.
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Sui, Jingkun, Qingcai Zeng, Zhifang Yang, Xiaodong Zheng, and Tianyue Hu. "Amplitude semblance and its fusion with the third-generation coherence for characterization of fractured-vuggy carbonate reservoirs." Journal of Geophysics and Engineering 19, no. 5 (September 10, 2022): 1005–11. http://dx.doi.org/10.1093/jge/gxac061.
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Abstract In the Tarim Basin, the main hydrocarbon reservoirs of Ordovician carbonate rocks are fractured-vuggy reservoirs, of which the underground river type reservoirs are an important type. Seismic coherence attribute can highlight seismic discontinuity caused by tectonic movements, reservoir boundaries, sedimentary body boundaries or other factors. Thus, it is a widely used key technique in seismic interpretation. There are many algorithms to determine the coherence. Typically, the coherence algorithm based on eigen-structure analysis is the most robust, but is sensitive to waveform differences and insensitive to amplitude differences. This paper proposes an amplitude coherence attribute to measure semblance of root-mean-square (RMS) amplitudes of multiple traces and fuses it with the third-generation coherence (C3) to describe the boundary of underground river. Model test and case study prove that the proposed fused algorithm can effectively identify the amplitude and waveform differences in seismic data.
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Julian, Bruce R., and G. R. Foulger. "Earthquake mechanisms from linear-programming inversion of seismic-wave amplitude ratios." Bulletin of the Seismological Society of America 86, no. 4 (August 1, 1996): 972–80. http://dx.doi.org/10.1785/bssa0860040972.
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Abstract The amplitudes of radiated seismic waves contain far more information about earthquake source mechanisms than do first-motion polarities, but amplitudes are severely distorted by the effects of heterogeneity in the Earth. This distortion can be reduced greatly by using the ratios of amplitudes of appropriately chosen seismic phases, rather than simple amplitudes, but existing methods for inverting amplitude ratios are severely nonlinear and require computationally intensive searching methods to ensure that solutions are globally optimal. Searching methods are particularly costly if general (moment tensor) mechanisms are allowed. Efficient linear-programming methods, which do not suffer from these problems, have previously been applied to inverting polarities and wave amplitudes. We extend these methods to amplitude ratios, in which formulation on inequality constraint for an amplitude ratio takes the same mathematical form as a polarity observation. Three-component digital data for an earthquake at the Hengill-Grensdalur geothermal area in southwestern Iceland illustrate the power of the method. Polarities of P, SH, and SV waves, unusually well distributed on the focal sphere, cannot distinguish between diverse mechanisms, including a double couple. Amplitude ratios, on the other hand, clearly rule out the double-couple solution and require a large explosive isotropic component.
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Russell, Brian H. "Prestack seismic amplitude analysis: An integrated overview." Interpretation 2, no. 2 (May 1, 2014): SC19—SC36. http://dx.doi.org/10.1190/int-2013-0122.1.
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In this tutorial, I present an overview of the techniques that are in use for prestack seismic amplitude analysis, current and historical. I show that these techniques can be classified as being based on the computation and analysis of either some type of seismic reflection coefficient series or seismic impedance. Those techniques that are based on the seismic reflection coefficient series, or seismic reflectivity for short, are called amplitude variation with offset methods, and those that are based on the seismic impedance are referred to as prestack amplitude inversion methods. Seismic reflectivity methods include: near and far trace stacking, intercept versus gradient analysis, and the fluid factor analysis. Seismic impedance methods include: independent and simultaneous P and S-impedance inversion, lambda-mu-rho analysis, Poisson impedance inversion, elastic impedance, and extended elastic impedance inversion. The objective of this tutorial is thus to make sense of all of these methods and show how they are interrelated. The techniques will be illustrated using a 2D seismic example over a gas sand reservoir from Alberta. Although I will largely focus on isotropic methods, the last part of the tutorial will extend the analysis to anisotropic reservoirs.
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White, Benjamin, Balan Nair, and Alvin Bayliss. "Random rays and seismic amplitude anomalies." GEOPHYSICS 53, no. 7 (July 1988): 903–7. http://dx.doi.org/10.1190/1.1442527.
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We give an explanation of the phenomenon, sometimes observed in exploration seismology, of anomalously large amplitudes which seem inconsistent with the traveltime curves when the data are interpreted as resulting from reflections from smooth interfaces of piece‐wise homogeneous media. Monte Carlo simulations illustrate how this phenomenon can occur when the homogeneous media have small, smooth, random velocity fluctuations which vary on a length scale which is large compared with a wavelength but small compared with the propagation distance. Synthetic gathers of reflections from a single plane‐stratified layer with and without the random lateral inhomogeneities produce an amplitude anomaly which is related to the random occurrence of a caustic; limit theorems for stochastic differential equations provide a theory. Theoretical curves, giving the probability of first occurrence of this phenomenon along a ray as a function of propagation distance (for plane waves and for point and line sources in two and three dimensions) are qualitatively similar: they have an initial flat portion where amplitude anomalies are very unlikely, rise to a peak at the distance most likely for first occurrence, and decay exponentially to zero, thus predicting that the phenomenon will occur at some finite distance with probability one.
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Ford, Jonathan, Angelo Camerlenghi, Francesca Zolezzi, and Marilena Calarco. "Seismic amplitude response to internal heterogeneity of mass-transport deposits." Solid Earth 14, no. 2 (February 22, 2023): 137–51. http://dx.doi.org/10.5194/se-14-137-2023.
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Abstract. Compared to unfailed sediments, mass-transport deposits are often characterised by a low-amplitude response in single-channel seismic reflection images. This “acoustic transparency” amplitude signature is widely used to delineate mass-transport deposits and is conventionally interpreted as a lack of coherent internal reflectivity due to a loss of preserved internal structure caused by mass-transport processes. In this study we examine the variation in the single-channel seismic response with changing heterogeneity using synthetic 2-D elastic seismic modelling. We model the internal structure of mass-transport deposits as a two-component random medium, using the lateral correlation length (ax) as a proxy for the degree of internal deformation. The average internal reflectivity is held approximately constant with increasing deformation by fixing the two component sediment lithologies to have realistic P-wave velocity and density based on sediment core measurements from the study area. For a controlled single-source synthetic model a reduction in observed amplitude with reduced ax is consistently observed across a range of vertical correlation lengths (az). For typical autonomous underwater vehicle (AUV) sub-bottom profiler acquisition parameters, in a simulated mass-transport deposit with realistic geostatistical properties, we find that when ax≈1 m, recorded seismic amplitudes are, on average, reduced by ∼25 % relative to unfailed sediments (ax≫103 m). We also observe that deformation significantly larger than core scale (ax>0.1 m) can generate a significant amplitude decrease. These synthetic modelling results should discourage interpretation of the internal structure of mass-transport deposits based on seismic amplitudes alone, as acoustically transparent mass-transport deposits may still preserve coherent, metre-scale internal structure. In addition, the minimum scale of heterogeneity required to produce a significant reduction in seismic amplitudes is likely much larger than the typical diameter of sediment cores, meaning that acoustically transparent mass-transport deposits may still appear well stratified and undeformed at core scale.
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Cheng, Xuansheng, De Li, Peijiang Li, Xiaoyan Zhang, and Guoliang Li. "Dynamic Response of Base-Isolated Concrete Rectangular Liquid-Storage Structure Under Large Amplitude Sloshing." Archives of Civil Engineering 63, no. 1 (March 28, 2017): 33–45. http://dx.doi.org/10.1515/ace-2017-0003.
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AbstractConsidering concrete nonlinearity, the wave height limit between small and large amplitude sloshing is defined based on the Bernoulli equation. Based on Navier-Stokes equations, the mathematical model of large amplitude sloshing is established for a Concrete Rectangle Liquid-Storage Structure (CRLSS). The results show that the seismic response of a CRLSS increases with the increase of seismic intensity. Under different seismic fortification intensities, the change in trend of wave height, wallboard displacement, and stress are the same, but the amplitudes arc not. The areas of stress concentration appear mainly at the connections between the wallboards, and the connections between the wallboard and the bottom.
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Gritto, Roland, Ali Elobaid Elnaiem, Fateh Alrahman Mohamed, and Fadhil Sadooni. "Seismic detection and characterization of a man-made karst analog — A feasibility study." GEOPHYSICS 86, no. 3 (March 19, 2021): WA35—WA48. http://dx.doi.org/10.1190/geo2020-0377.1.
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At the site of a water drainage shaft on the campus of Qatar University that serves as a man-made karst analog, two seismic imaging techniques were adapted to use resonant scattered waves recorded during active-source seismic surveys and during passive ambient-noise surveys. Data acquisition included two seismic transmission surveys that encompassed the shaft and a passive ambient-noise survey that extended across the top of the shaft. Seismic imaging of band-pass-filtered resonance waves correctly estimated the location and dimension of the shaft. Furthermore, the method detected the presence and the location of a horizontal drainage pipe and gravel bed connecting neighboring water shafts. Ambient-noise data were analyzed by computing amplitude values of the seismic records in spectral passbands. The results indicated an amplification of seismic amplitudes above the shaft for low-frequency passbands and a sharp decrease in amplitude values for high-frequency passbands. The high- and low-amplitude values displayed as a function of the receiver position allowed for accurate detection and location of the shaft in space. Ground truthing of the imaging results confirmed the accuracy of the seismic techniques, whereas numerical modeling supported the interpretation of the ambient-noise data. The techniques used do not require knowledge of the seismic velocities in the subsurface, but they depend on a priori information about the approximate location of the target.
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Rietveld, Walter E., Jan H. Kommedal, and Kurt J. Marfurt. "The effect of 3-D prestack seismic migration on seismic coherence and amplitude variability." GEOPHYSICS 64, no. 5 (September 1999): 1553–61. http://dx.doi.org/10.1190/1.1444659.
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We compare the effect of 3-D poststack versus 3-D prestack imaging on seismic coherence, seismic amplitude, and seismic amplitude variation. We find that the improved resolution and amplitude preservation of the prestack imaging result in more sharply defined terminations and hence better delineation by coherence and amplitude gradients even though the (macro) velocity models used in both imaging approaches are laterally invariant [v(z)].
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Zhou, Bing, and Stewart A. Greenhalgh. "Crosshole seismic inversion with normalized full‐waveform amplitude data." GEOPHYSICS 68, no. 4 (July 2003): 1320–30. http://dx.doi.org/10.1190/1.1598125.
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We investigate a simple scheme for full‐waveform amplitude spectrum inversion of crosshole seismic data with an unknown source wavelet. The method is based on our 2D/2.5D finite‐element method of acoustic‐wave modeling. The normalized amplitude data, defined as the spectral ratio of the original trace amplitude to the average amplitude for the entire common shot gather, are used for full‐waveform inversion in the frequency domain. In essence, the normalization of amplitudes removes the source wavelet and is easily carried out in the time domain or frequency domain from crosshole seismic surveying. Two synthetic models, simulating, respectively, a dipping fracture model and a complicated sedimentary structure, are examined with the inversion scheme. The numerical results show that clear images of the targets can be obtained by using the single‐ and multiple‐frequency data. For comparison, two other amplitude inversion schemes in which the source signatures are known and estimated with an iterative procedure were carried out for the same models. The results show that the iteratively source‐estimated procedure also produces satisfactory images of the velocity structure and yields an approximate amplitude of the source wavelet. With the multifrequency data, three such schemes yield very competitive results.
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Shadlow, James. "A description of seismic amplitude techniques." Exploration Geophysics 45, no. 3 (September 2014): 154–63. http://dx.doi.org/10.1071/eg13070.
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Azevedo, Leonardo, Rúben Nunes, Amílcar Soares, Guenther Schwedersky Neto, and Teresa S. Martins. "Geostatistical seismic Amplitude‐versus‐angle inversion." Geophysical Prospecting 66, S1 (December 26, 2017): 116–31. http://dx.doi.org/10.1111/1365-2478.12589.
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Taylor, S. R., A. A. Velasco, H. E. Hartse, and W. S. Phillips. "Amplitude Corrections for Regional Seismic Discriminants." Pure and Applied Geophysics 159, no. 4 (February 1, 2002): 623–50. http://dx.doi.org/10.1007/s00024-002-8652-8.
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Kneib, Guido, and Serge A. Shapiro. "Viscoacoustic wave propagation in 2-D random media and separation of absorption and scattering attenuation." GEOPHYSICS 60, no. 2 (March 1995): 459–67. http://dx.doi.org/10.1190/1.1443783.
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Wave theoretical analysis of scalar, time‐harmonic waves propagating in a constant density medium with isotropic, random velocity fluctuations and being scattered mainly in the forward direction yields a simple and robust procedure that combines the logarithm of the mean wave amplitude with the mean logarithm of the wave amplitude to perform a separation of scattering attenuation and absorption effects. Finite‐difference simulations of wave propagation in 2-D random media with a Voigt‐body rheology illustrate the evolution of wave field fluctuations and demonstrate that the separation procedure works for a wide range of seismic albedos. In the case of no absorption, the logarithms of seismic amplitudes will have a nonlinear dependence on the travel distance if the wavefield fluctuations are small compared to the amplitude of the coherent field. If these fluctuations are large, the logarithms of seismic amplitudes will tend to constant levels independent of the travel distance. In the case of random viscoacoustic media and at propagation distances larger than the inverse of the scattering coefficient of the coherent field, and apart from geometrical spreading, the overall amplitude decrease will be predominated by absorption, even if the absorption coefficient is one order smaller than the scattering coefficient of the coherent field.
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Daley, Thomas M., Roland Gritto, Ernest L. Majer, and Phillip West. "Tube‐wave suppression in single‐well seismic acquisition." GEOPHYSICS 68, no. 3 (May 2003): 863–69. http://dx.doi.org/10.1190/1.1581038.
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Single‐well seismic imaging is significantly hampered by the presence of borehole tube waves. A tube‐wave suppressor has been tested using single‐well seismic equipment at the Lost Hills (California) oil field. The suppressor uses a gas‐filled bladder kept slightly above borehole fluid pressure. Field tests show a measurable reduction in tube‐wave energy as compared to body waves propagating in the surrounding reservoir rock. When using a high‐frequency (500–4000 Hz) piezoelectric source, the P‐wave–tube‐wave amplitude ratio was increased by 33 dB. When using a lower frequency (50–350 Hz) orbital vibrator source, the S‐wave–tube‐wave amplitude ratio was increased by 21 dB while the P‐wave–tube‐wave amplitude ratio was increased by 23 dB. These reductions in tube‐wave amplitudes significantly improve single‐well data quality.
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Ursin, Bjørn, and Martin Tygel. "Zero-offset seismic amplitude decomposition and migration." GEOPHYSICS 72, no. 4 (July 2007): S187—S193. http://dx.doi.org/10.1190/1.2741366.
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In an anisotropic medium, a normal-incidence wave is multiply transmitted and reflected down to a reflector where the phase-velocity vector is parallel to the interface normal. The ray code of the upgoing wave is equal to the ray code of the downgoing wave in reverse order. The geometric spreading, KMAH index, and transmission and reflection coefficients of the normal-incidence ray can be expressed in terms of products or sums of the corresponding quantities of the one-way normal and normal-incidence-point (NIP) waves. Here, we show that the amplitude of the ray-theoretic Green’s function for the reflected wave also follows a similar decomposition in terms of the amplitude of the Green’s function of the NIP wave and the normal wave. We use this property to propose three schemes for true-amplitude poststack depth migration in anisotropic media where the image represents an estimate of the zero-offset reflection coefficient. The first is a map migration procedure in which selected primary zero-offset reflections are converted into depth with attached true amplitudes. The second is a ray-based, Kirchhoff-type full migration. The third is a wave equation continuation algorithm to reverse-propagate the recorded wavefield in a half-velocity model with half the elastic constants and double the density. The image is formed by taking the reverse-propagated wavefield at time equal to zero followed by a geometric spreading correction.
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Verma, Sumit, Satinder Chopra, Thang Ha, and Fangyu Li. "A review of some amplitude-based seismic geometric attributes and their applications." Interpretation 10, no. 1 (January 12, 2022): B1—B12. http://dx.doi.org/10.1190/int-2021-0136.1.
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Seismic interpreters frequently use seismic geometric attributes, such as coherence, dip, curvature, and aberrancy for defining geologic features, including faults, channels, angular unconformities, etc. Some of the commonly used coherence attributes, such as cross correlation or energy-ratio similarity, are sensitive to only waveform shape changes, whereas the dip, curvature, and aberrancy attributes are based on changes in reflector dips. There is another category of seismic attributes, which includes attributes that are sensitive to amplitude values. Root-mean-square amplitude is one of the better-known amplitude-based attributes, whereas coherent energy, Sobel-filter similarity, normalized amplitude gradients, and amplitude curvature are among lesser-known amplitude-based attributes. We have computed not-so-common amplitude-based attributes on the Penobscot seismic survey from the Nova Scotia continental shelf consisting of the east coast of Canada, to bring out their interpretive value. We analyze seismic attributes at the level of the top of the Wyandot Formation that exhibits different geologic features, including a synthetic transfer zone with two primary faults and several secondary faults, polygonal faults associated with differential compaction, as well as fixtures related to basement-related faults. The application of the amplitude-based seismic attributes defines such features accurately. We take these applications forward by describing a situation in which some geologic features do not display any bending of reflectors but only exhibit changes in amplitude. One such example is the Cretaceous Cree Sand channels present in the same 3D seismic survey used for the previous applications. We compute amplitude curvature attributes and identify the channels, whereas these channels are not visible on the structural curvature display. In both of the applications, we observe that appropriate corendering not-so-common amplitude-based seismic attributes lead to convincing displays, which can be of immense aid in seismic interpretation and help define the different subsurface features with more clarity.
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Burnett, R. C. "Seismic amplitude anomalies and AVO analyses at Mestena Grande Field, Jim Hogg Co., Texas." GEOPHYSICS 55, no. 8 (August 1990): 1015–25. http://dx.doi.org/10.1190/1.1442914.
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Mestena Grande field is located in northeast Jim Hogg Co., Texas. It produces gas and condensate, primarily from the middle member of the Middle Eocene Queen City formation. The producing zone is a deep, thin, high impedance sandstone which generates amplitude anomalies on the stacked data. AVO (amplitude versus offset) analyses were performed to investigate those anomalies and determine if they could aid in field development or exploration along the trend. Modeling the AVO response of a productive well has predicted an amplitude decrease with offset from a high impedance sandstone. However, amplitudes increase with offset on the crest of the field. At Mestena Grande field, three categories of seismic amplitudes correspond with production with only one exception. The first category exhibits strong amplitudes on the stacked data and amplitudes increase with offset. This amplitude category is seen around the best wells in the field. Second are the moderate amplitudes which do not increase with offset that surround the wells producing at moderate rates. The third category is characterized by very weak amplitudes which decrease with offset, occurring near all but one of the dry holes. The disagreement between the results of the modelling and the real data is attributed to the lack of accurate shear wave velocities and the presence of very thin beds.
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Zhang, Rui, Xiaolei Song, Sergey Fomel, Mrinal K. Sen, and Sanjay Srinivasan. "Time-lapse seismic data registration and inversion for CO2 sequestration study at Cranfield." GEOPHYSICS 78, no. 6 (November 1, 2013): B329—B338. http://dx.doi.org/10.1190/geo2012-0386.1.
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The time-lapse seismic survey for [Formula: see text] sequestration study at Cranfield can be problematic because of misalignments between time-lapse data sets. Such misalignments can be caused by the seismic data processing workflow and may result in the wrong interpretation of time-lapse seismic amplitude differences. We propose an efficient local-correlation-based warping method of registering the time-lapse poststack data sets, which can align these data sets without changing original amplitudes. Application of our registration method to Cranfield time-lapse data demonstrates its effectiveness in separating time-shift character from seismic amplitude signature. After registration, time-lapse differences show an improved consistency in vertical cross sections and a more localized distribution of difference amplitudes along the horizon, allowing us to apply a high-resolution basis pursuit inversion (BPI) for acoustic impedances. Inversion results show that decreases in acoustic impedances occur mostly at the top of the injection interval, which can be used as an indicator of rock properties to detect a subsurface [Formula: see text] plume.
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Helbig, Klaus. "Fifty years of amplitude control." GEOPHYSICS 63, no. 2 (March 1998): 750–62. http://dx.doi.org/10.1190/1.1444375.
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The amplitudes of seismic waves have always been a foremost concern of the seismologist to which considerable ingenuity was devoted. In the 1920s the problem was to magnify the ground motion sufficiently for detection. This was done at first by simple levers that moved mechanical pens. But at the start of exploration seismology, this had already been superseded by optical levers, photographic recording, and (soon after) electromechanical transduction followed by amplification. From the 1930s to about the early ’60s, devices of increasing complexity were introduced to compress the large amplitude difference between the first arrivals and the weakest reflections of interest to the limited dynamic range of the recording medium: first the paper record, then magnetic storage media, and finally the digital magnetic tape. This period can be identified with techniques known as automatic gain control (AGC). Soon after the introduction of digital recording techniques, the emphasis shifted: with intermediate digital storage, the limit to the dynamic range was no longer controlled by the properties of the storage medium. Now everything that passed through the acquisition unit could, in principle, be stored on magnetic disk or tape. At that time the aim became to record the ground motion as faithfully as possible. There were several technical developments on the way to achieve “true amplitudes” that, in turn, made exploration concepts like bright spots, seismic stratigraphy, and amplitude‐versus‐offset evaluation possible. However, the most significant innovation was what became known as floating‐point amplifier. It dominated seismic acquisition for about 25 years. Floating‐point representation of seismic signals allowed storage of the entire dynamic range in relatively economic words of about 18 bits. During the last decade, the quest for ever‐greater resolution—and the availability of mass‐produced components for hi‐fi audio equipment—led to the introduction of the sigma‐delta (Σ-δ) converter. With this device, the full range of the seismic signal (or rather the geophone output) is recorded in binary fixed‐point formats with 24 bits. With this development, the full seismic signal can be stored without distortion or loss of resolution.
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Wang, Zhikai, Satish C. Singh, and Mark Noble. "True-amplitude versus trace-normalized full waveform inversion." Geophysical Journal International 220, no. 2 (November 26, 2019): 1421–35. http://dx.doi.org/10.1093/gji/ggz532.
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SUMMARY Full waveform inversion (FWI) is a powerful method to estimate high-resolution physical parameters of the subsurface by iteratively minimizing the misfit between the observed and synthetic seismic data. Standard FWI algorithms measure seismic misfit between amplitude-preserved seismic data (true-amplitude FWI). However, in order to mitigate the variations in sources and recording systems acquired on complex geological structures and the physics that cannot be modelled using an approximation of the seismic wave equation, the observed and synthetic seismic data are normalized trace-by-trace and then used to perform FWI. Trace-by-trace normalization removes the amplitude effects related to offset variations and only keeps the phase information. Furthermore, trace-by-trace normalization changes the true amplitude difference because of different normalization factors used for the corresponding synthetic and observed traces. In this paper, we study the performance of true-amplitude FWI and trace-normalized-residual-based FWI in the time domain. The misfit function of trace-normalized-residual-based FWI is defined such that the adjoint source used in gradient calculation is the trace-normalized seismic residual. We compare the two inversion schemes with synthetic seismic data simulated on laterally invariant models and the more complex 2-D Marmousi model. In order to simulate realistic scenarios, we perform the elastic FWI ignoring attenuation to noisy seismic data and to the synthetic data modelled using a viscoelastic modelling scheme. Comparisons of seismic data and adjoint sources show that trace-by-trace normalization increases the magnitude of seismic data at far offsets, which are usually more cycle-skipped than those at near offsets. The inverted results on linear-gradient models demonstrate that trace-by-trace normalization increases the non-linearity of FWI, so an initial model with sufficient accuracy is required to guarantee the convergence to the global minimum. The inverted results and the final seismic residuals computed using seismic data without trace-by-trace normalization demonstrate that true-amplitude FWI provides inverted models with higher accuracy than trace-normalized-residual-based FWI, even when the unknown density is updated using density–velocity relationship in inversion or in the presence of noise and complex physics, such as attenuation.
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Stovas, Alexey. "Geometric spreading in orthorhombic media." GEOPHYSICS 83, no. 1 (January 1, 2018): C61—C73. http://dx.doi.org/10.1190/geo2016-0710.1.
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Geometric spreading is an important factor that needs to be taken into account in the analysis of seismic amplitudes. In particular, when using any modification of amplitude variation with offset or amplitude versus azimuth methods, the effect of geometric spreading is crucial to isolate the effect of reflection from a particular interface. The relative geometric spreading controls the amplitude of seismic waves passing through a velocity model. In the case of an anisotropic medium, geometric spreading becomes very complicated. Usually, geometric spreading is computed from ray tracing. I have derived simple analytical formulas to compute the relative geometric spreading of P-waves in a stack of acoustic orthorhombic layers with azimuthal variations in symmetry planes. I also analyzed the kinematic properties of the derived equations and performed sensitivity analysis with respect to three anelliptic parameters. A simple and accurate approximation for the relative geometric spreading is derived and tested against well-known approximation. My approximations give insight into the role that anelliptic parameters play into the azimuthal distribution of amplitudes and can be used for amplitude analysis in multilayered orthorhombic models.
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Hatherly, P. J. "Attenuation measurements on shallow seismic refraction data." GEOPHYSICS 51, no. 2 (February 1986): 250–54. http://dx.doi.org/10.1190/1.1442084.
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Techniques of making seismic attenuation measurements are of interest in engineering geophysics because they allow rock type and quality to be estimated. The measurements may be made on field data from spectral amplitudes, amplitude decay curves, or observed pulse broadening. With shallow seismic refraction data, attenuation is best measured from the pulse broadening. I discuss the problem and demonstrate a computer technique for making routine measurements.
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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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Kwietniak, Anna, Kamil Cichostępski, and Kaja Pietsch. "Resolution enhancement with relative amplitude preservation for unconventional targets." Interpretation 6, no. 3 (August 1, 2018): SH59—SH71. http://dx.doi.org/10.1190/int-2017-0196.1.
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Our primary objective was to evaluate a method that enhances the resolution of 3D seismic data that does not disturb the relative amplitude preservation. The formations that are the subject of the analysis are Lower Silurian: the Jantar Formation and the Ordovician Sasino Formation (the onshore part of the Baltic Basin, northern Poland). Both formations are seismically thin layers and have been recent targets for unconventional exploration. Resolution enhancement designed to help the structural interpretation may enable precise structural interpretation of thinly layered intervals. The method that we applied is poststack spectral blueing. To verify the effectiveness of the spectral blueing procedure, we designed an algorithm that compares the amplitude values along evenly distributed seismic traces. The algorithm addresses the preservation of the relative amplitude ratio. We did not want to disturb the amplitude values by the enhancement algorithm and introduce information that would be false for seismic inversion analysis. Hence, it was crucial for us to obtain the enhanced seismic volume suitable for structural interpretation that holds relative amplitude relation criterion. The algorithm helped obtain the optimal enhanced seismic volume that is preferable for the structural interpretation of seismic data and possibly could be used successfully for a seismic inversion process. With the optimal enhanced seismic volume, we were able to conduct a more accurate structural interpretation — an entirely new seismic horizon that indicates that the top of one of the formations under analysis was clearly visible and thus possible for interpretation. We applied the acoustic inversion to the original and the enhanced seismic data — the latter enabled the determination of two additional anomalous zones that had not been previously possible to distinguish within the seismic volume.
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Peterson, J. E., and A. Davey. "Crossvalidation method for crosswell seismic tomography." GEOPHYSICS 56, no. 3 (March 1991): 385–89. http://dx.doi.org/10.1190/1.1443055.
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Crosswell seismic tomography is used to determine the variation of elastic wave velocity or attenuation between two boreholes and, if possible, boreholes and the surface from which they are drilled. In a transmission tomographic survey, traveltimes or amplitudes are measured for many raypaths between the boreholes and the surface. The data are inverted for velocity and attenuation, respectively. In this paper we only discuss traveltimes, but the methods are equally applicable to amplitude inversions.
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Mayrand, Louis J., and Bernd Milkereit. "Automated editing and true-amplitude stacking of seismic data." Canadian Journal of Earth Sciences 25, no. 11 (November 1, 1988): 1811–23. http://dx.doi.org/10.1139/e88-171.
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Lateral changes in recording conditions often require that trace amplitudes be balanced, with consequent loss of information on the lateral amplitude variation of reflected energy. We present a quality-control and automated editing algorithm that recognizes source and geophone coupling problems and different noise levels along the survey line. Problem traces are discarded, and true-amplitude stacking of the remaining ones is possible with constant scaling factors. Application of the algorithm to one of the Vancouver Island LITHOPROBE profiles gives a nominal signal-to-noise improvement of 15 dB and a better understanding of recording problems in the field. Our analysis shows that the varying strength of a reflection from near the top of the subducting Juan de Fuca plate cannot be explained by changing recording conditions alone. Results suggest that the extra effort involved in the automated optimization of common midpoint stacks of low signal-to-noise deep seismic data is warranted only if lateral amplitude information is to be preserved.
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Widyantoro, Adi, and Matthew Saul. "Shaly sand rock physics analysis and seismic inversion implication." APPEA Journal 54, no. 2 (2014): 503. http://dx.doi.org/10.1071/aj13076.
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The analysis of well data from the Enfield field of the Exmouth Sub-basin, WA, indicates that both cementation and pore-filling clay appear to have a stiffening effect on the reservoir sands. The elastic contrast between brine sand and the overlying shale is often small and the large amplitudes observed from seismic data are associated with hydrocarbon content. More detailed rock physics and depth trend analysis of elastic and petrophysical properties, however, indicate significant spatial variability in the cap rock shales across the field with different sand shale mixtures, causing changes in the elastic response of the rock. Areas where shales are softer produce weak seismic amplitude contrasts even with high hydrocarbon saturation; the amplitude response being similar to areas with stiffer shales and brine-filled sands. The variations in reservoir quality are, therefore, masked by the distribution of the brine, oil and gas, as well as the variations in the cap rock. The Enfield rock physics analysis provides an example of reducing amplitude ambiguity over lithology-fluid variation and improves the chance of successful interpretation of the results of seismic inversion.
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Brown, Alistair R. "Pitfalls in the study of seismic amplitude." Interpretation 6, no. 4 (November 1, 2018): SL15—SL20. http://dx.doi.org/10.1190/int-2018-0051.1.
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Amplitude is the key to all seismic interpretation objectives other than structure. Amplitude tells us about stratigraphic bodies, fluid content, and porosity zones. But amplitude is also affected by data collection, data processing, surface conditions, the geology of the overburden, and shallower reservoirs. So, amplitude contains much ambiguity, which can lead to interpretation pitfalls. We may use different types of amplitude, and we may call these amplitude attributes. We may or may not select the type of amplitude optimally for the current interpretation problem. Amplitude is full of information, but can we see what is important? Does the amplitude of our objective stand out sufficiently from other effects? Is our reservoir too thin? We must consider the different display options and use the one that is the most applicable to the interpretation task at hand. Gradational colors are preferred, but there are many color schemes that hinder rather than help the interpretive thought process.
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Burkhart, Tucker, Andrew R. Hoover, and Peter B. Flemings. "Time‐lapse (4-D) seismic monitoring of primary production of turbidite reservoirs at South Timbalier Block 295, offshore Louisiana, Gulf of Mexico." GEOPHYSICS 65, no. 2 (March 2000): 351–67. http://dx.doi.org/10.1190/1.1444731.
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Two seismic surveys acquired over South Timbalier Block 295 field (offshore Louisiana) record significant differences in amplitude that are correlated to hydrocarbon production at multiple reservoir levels. The K8 sand, a solution‐gas‐drive reservoir, shows increases in seismic amplitude associated with gas exsolution. The K40 sand, a water‐drive reservoir, shows decreases in seismic amplitude associated with increases in water saturation. A methodology is presented to optimize the correlation between two seismic surveys after they have been individually processed (poststack) This methodology includes rebinning, crosscorrelation, band‐pass filtering, and cross‐equalization. A statistical approach is developed to characterize the correlation between the seismic surveys. This statistical analysis is used to discriminate seismic amplitude differences that record change in rock and fluid properties from those that could be the result of miscorrelation of the seismic data. Time‐lapse seismic analysis provides an important new approach to imaging hydrocarbon production; it may be used to improve reservoir characterization and guide production decisions.