Polarity and phase in reflection seismic data: Stratton field

2020 ◽  
Vol 8 (3) ◽  
pp. T599-T609
Author(s):  
Qiang Guo ◽  
Wayne D. Pennington
Keyword(s):  
Seismic Response ◽  
Opposite Polarity ◽  
Thin Layers ◽  
Reflection Seismic ◽  
Seismic Wavelet ◽  
Hydrocarbon Reservoir ◽  
Impedance Contrast ◽  
Anomalous Feature ◽  
Vsp Data ◽  
Lower Impedance

Seismic interpretation is often based on the analysis of amplitude anomalies, which depend strongly on the seismic wavelet presented in the data. However, if the wavelet polarity or phase is unknown or fine-scale impedance variations are complex, interpretation of the anomaly can be ambiguous. The Stratton data volume contains a dome-like feature that may be interpreted as the top of a potential gas target, the top of a buried tight reef, or as a thin layer of either higher or lower impedance, depending on the interpreter’s assumption of polarity and phase. This observation provoked our interest in modeling the seismic response of domes using wavelets of differing polarity and phase on stacked data. Because there appears to be only a single event, perhaps the top of an anomalous feature, and not its base, a “gradational” decrease in impedance contrast with depth is included among our models. We have determined that the seismic response from a layer with an impedance contrast decreasing with depth is quite different from that of a layer with constant impedance contrast when the bed thickness exceeds one quarter of the wavelength; that is, a reflection from the base of a “thick” gradational layer is not visible, as expected. We independently determine the polarity and phase of the Stratton data, finding that the surface-based seismic and VSP data are of opposite polarity (European and American, respectively), and concluding that the dome structure represents the top of a gradational thick bed. A model based on a nearby reservoir containing thin gas, oil, and water zones supports this conclusion. This anomaly in the Stratton data appears to represent a hydrocarbon reservoir with thin layers of gas and oil, each with lower impedance than the surrounding beds but with stepwise decreasing contrast over a sufficient thickness to avoid a basal reflection at these wavelengths.

The seismic response of sediment-filled valleys. Part 1. The case of incident SH waves

1980 ◽  
Vol 70 (4) ◽  
pp. 1263-1286
Author(s):  
Pierre-Yves Bard ◽  
Michel Bouchon
Keyword(s):  
Seismic Response ◽  
Plane Waves ◽  
Rheological Parameters ◽  
Local Surface ◽  
Sh Waves ◽  
Ground Shaking ◽  
Impedance Contrast ◽  
Long Duration ◽  
Irregular Interface ◽  
Lower Impedance

abstract In this study is presented the extension to time domain calculations of the Aki-Larner method (Aki and Larner, 1970), developed to investigate the scattering of plane waves at irregular interface. Seismograms computed at the surface of a soft basin for SH waves vertically incident are compared with results obtained by finite difference, finite element, and asymptotic ray theory methods. The method is then applied to a study of the seismic response of sediment-filled valleys to incident SH waves. Various geometries and rheological parameters are considered. The study shows the important role played by the nonplanar interface, which, when the incident wavelengths are comparable to the depth of the valley, results in the generation of Love waves which may have much larger amplitude than the disturbance associated with the direct incident signal. In the presence of a high-velocity contrast between the sediments and the underlying bedrock, these local surface waves can be reflected several times at the edges of the valley, resulting in a long duration of the ground shaking in the basin. In the case of a lower impedance contrast, these waves may produce disturbances on the outer sides of the valley.

Complex seismic trace analysis of thin beds

Geophysics ◽  
1984 ◽  
Vol 49 (4) ◽  
pp. 344-352 ◽  
Author(s):  
James D. Robertson ◽  
Henry H. Nogami
Keyword(s):  
Instantaneous Frequency ◽  
Trace Analysis ◽  
Frequency Tuning ◽  
Seismic Energy ◽  
High Amplitude ◽  
Opposite Polarity ◽  
Peak Period ◽  
Seismic Wavelet ◽  
Porous Sandstone ◽  
Seismic Sections

Displays of complex trace attributes can help to define thin beds in seismic sections. If the wavelet in a section is zero phase, low impedance strata whose thicknesses are of the order of half the peak‐to‐peak period of the dominant seismic energy show up as anomalously high‐amplitude zones on instantaneous amplitude sections. These anomalies result from the well‐known amplitude tuning effect which occurs when reflection coefficients of opposite polarity a half period apart are convolved with a seismic wavelet. As the layers thin to a quarter period of the dominant seismic energy, thinning is revealed by an anomalous increase in instantaneous frequency. This behavior results from the less well‐known but equally important phenomenon of frequency tuning by beds which thin laterally. Instantaneous frequency reaches an anomalously high value when bed thickness is about a quarter period and remains high as the bed continues to thin. In this paper, complex trace analysis is applied to a synthetic model of a wedge and to a set of broadband field data acquired to delineate thin lenses of porous sandstone. The two case studies illustrate that sets of attribute displays can be used to verify the presence and dimensions of thin beds when definition of the beds is not obvious on conventional seismic sections.

Texture model regression for effective feature discrimination: Application to seismic facies visualization and interpretation

Geophysics ◽  
2004 ◽  
Vol 69 (4) ◽  
pp. 958-967 ◽  
Author(s):  
Dengliang Gao
Keyword(s):  
High Performance ◽  
Fresnel Zone ◽  
Maximum Amplitude ◽  
Seismic Facies ◽  
Image Texture ◽  
Computational Time ◽  
Gas Field ◽  
Reflection Seismic ◽  
Hydrocarbon Reservoir ◽  
Texture Model

The classical approach to feature discrimination requires extraction and classification of multiple attributes. Such an approach is expensive in terms of computational time and storage space, and the results are generally difficult to interpret. With increasing data size and dimensionality, along with demand for high performance and productivity, the effectiveness of a feature‐discrimination methodology has become a critically important issue in many areas of science. To address such an issue, I developed a texture model regression (TMR) methodology. Unlike classical attribute extraction and classification algorithms, the TMR methodology uses an interpreter‐defined texture model as a calibrating filter and regresses the model texture with the data texture at each sample location to create a regression‐gradient volume. The new approach not only dramatically reduces computational cycle time and space but also creates betters results than those obtained from classical techniques, resulting in improved feature discrimination, visualization, and interpretation. Application of the TMR concept to reflection seismic data demonstrates its value in seismic‐facies analysis. In order to characterize reflection seismic images composed of wiggle traces with variable amplitude, frequency, and phase, I introduced two simple seismic‐texture models in this application. The first model is defined by a full cycle of a cosine function whose amplitude and frequency are the maximum amplitude and dominant frequency of wiggle traces in the interval of interest. The second model is defined by a specific reflection pattern known to be associated with a geologic feature of interest, such as gas sand in a hydrocarbon reservoir. I applied both models to a submarine turbidite system offshore West Africa and to a gas field in the deep‐water Gulf of Mexico, respectively. Based on extensive experimentation and comparative analysis, I found that the TMR process with such simple texture models creates superior results, using minimal computational resources. The result is geologically intriguing, easily interpretable, and consistent with general depositional and reservoir‐facies concepts. Such a successful application may be attributable to the sensitivity of image texture to physical texture in the Fresnel zone at an acoustic interface and therefore to lithology, depositional facies, and hydrocarbonsaturation.

Twelve years of vertical birefringence in nine‐component VSP data

Geophysics ◽  
2001 ◽  
Vol 66 (2) ◽  
pp. 582-597 ◽  
Author(s):  
Donald F. Winterstein ◽  
Gopa S. De ◽  
Mark A. Meadows
Keyword(s):  
Seismic Data ◽  
Azimuthal Anisotropy ◽  
Vertical Shear ◽  
S Wave ◽  
Seismic Profiles ◽  
Surface Reflection ◽  
Vertical Seismic Profiles ◽  
Reflection Seismic ◽  
San Andreas ◽  
Vsp Data

Since 1986, when industry scientists first publicly showed data supporting the presence of azimuthal anisotropy in sedimentary rock, we have studied vertical shear‐wave (S-wave) birefringence in 23 different wells in western North America. The data were from nine‐component vertical seismic profiles (VSPs) supplemented in recent years with data from wireline crossed‐dipole logs. This paper summarizes our results, including birefringence results in tabular form for 54 depth intervals in 19 of those 23 wells. In the Appendix we present our conclusions about how to record VSP data optimally for study of vertical birefringence. We arrived at four principal conclusions about vertical S-wave birefringence. First, birefringence was common but not universal. Second, birefringence ranged from 0–21%, but values larger than 4% occurred only in shallow formations (<1200 m) within 40 km of California’s San Andreas fault. Third, at large scales birefringence tended to be blocky. That is, both the birefringence magnitude and the S-wave polarization azimuth were often consistent over depth intervals of several tens to hundreds of meters but then changed abruptly, sometimes by large amounts. Birefringence in some instances diminished with depth and in others increased with depth, but in almost every case a layer near the surface was more birefringent than the layer immediately below it. Fourth, observed birefringence patterns generally do not encourage use of multicomponent surface reflection seismic data for finding fractured hydrocarbon reservoirs, but they do encourage use of crossed‐dipole logs to examine them. That is, most reservoirs were birefringent, but none we studied showed increased birefringence confined to the reservoir.

scholarly journals The Possible use of Equivalent Homogeneous Subsoil Models for 1D Seismic Response Analyses in Seismic Microzonation Studies

2021 ◽  
Author(s):  
Stefania Fabozzi ◽  
Albarello Dario ◽  
Pagliaroli Alessandro ◽  
Moscatelli Massimiliano
Keyword(s):  
Seismic Response ◽  
Soil Profile ◽  
Weighted Average ◽  
Seismic Microzonation ◽  
Thin Layers ◽  
Homogeneous Layer ◽  
Heterogeneous Soil ◽  
Harmonic Average ◽  
Actual Configuration ◽  
Nonlinear Curve

Abstract The possibility is here explored to use an ‘equivalent’ homogeneous configuration to simulate 1D seismic response of heterogeneous engineering-geological bodies when relatively weak seismic impedance contrasts (150 m/s) only exist above the seismic bedrock. This equivalent configuration is obtained by considering an equivalent Vs value the harmonic average of the actual Vs values and a linear combination of G/G 0 and D curves relative to the lithotechnical components present in the actual configuration. To evaluate feasibility of this approach, a wide set of numerical simulations was carried out by randomly generating subsoil layering including sequences of alternating thin layers of geotechnical units ( e.g., sands and clays) each characterized by a characteristic nonlinear curve. Outcomes of these simulations are compared with those provided by considering a single homogeneous layer characterized by equivalent nonlinear curves obtained as a weighted average of the original curves. By comparing the heterogeneous and the homogeneous columns seismic response in terms of amplification factors and fundamental period, the results confirm the possibility to model a 1D column characterized by a generic lithostratigraphic succession with an equivalent one without introducing significative errors that, at least for the studied cases, do not exceed the 6%. This conclusion is substantially confirmed by extending the comparison to a real case, i.e. the 113 m-thick heterogeneous soil profile at Mirandola site (Norther Italy), presented in the last part.

Repeatability issues of 3-D VSP data

Geophysics ◽  
1999 ◽  
Vol 64 (6) ◽  
pp. 1673-1679 ◽  
Author(s):  
Martin Landrø
Keyword(s):  
Vertical Component ◽  
Time Lapse ◽  
Management Tool ◽  
Data Set ◽  
Hydrocarbon Reservoir ◽  
Vertical Seismic Profiling ◽  
Positioning Errors ◽  
Vsp Data ◽  
The Difference ◽  
Pressure Changes

Increased repeatability is recognized as one major issue for improving the time‐lapse seismic technology as a reservoir management tool. A 3-D vertical seismic profiling (VSP) data set, acquired over a period of two days, is used to analyze how repeatable a permanent installed geophone array can be and how repeatability changes with inaccuracies in source positioning. It is found that for a frequency range between 3.5 and 50 Hz, the difference root‐mean‐square (rms) level between two recorded traces belonging to two different shots is about 8%. This fact shows that there is a potential for acquiring very accurate time‐lapse seismic data by using a permanently installed downhole geophone array. Repeatability variation with increasing shot separation distances is analyzed, showing a rapid decrease in repeatability as the accuracy of the positioning of the repeat survey decreases. Horizontal geophone components show approximately the same degree of repeatability compared to the vertical component, but horizontal geophone data is slightly more sensitive to positioning errors. The results show that repeated 3-D VSP surveys (preferably using permanently installed geophone arrays) might be an efficient tool for detailed and precise monitoring of fluid and pressure changes within a hydrocarbon reservoir.

Estimation of the depth-domain seismic wavelet based on velocity substitution and a generalized seismic wavelet model

Geophysics ◽  
2021 ◽  
pp. 1-50
Author(s):  
Jie Zhang ◽  
Xuehua Chen ◽  
Wei Jiang ◽  
Yunfei Liu ◽  
He Xu
Keyword(s):  
Least Squares ◽  
Seismic Data ◽  
Reservoir Characterization ◽  
Regularization Parameter ◽  
Estimation Method ◽  
Model Parameters ◽  
Wavelet Estimation ◽  
Seismic Wavelet ◽  
Hydrocarbon Reservoir ◽  
Convolution Model

Depth-domain seismic wavelet estimation is the essential foundation for depth-imaged data inversion, which is increasingly used for hydrocarbon reservoir characterization in geophysical prospecting. The seismic wavelet in the depth domain stretches with the medium velocity increase and compresses with the medium velocity decrease. The commonly used convolution model cannot be directly used to estimate depth-domain seismic wavelets due to velocity-dependent wavelet variations. We develop a separate parameter estimation method for estimating depth-domain seismic wavelets from poststack depth-domain seismic and well log data. This method is based on the velocity substitution and depth-domain generalized seismic wavelet model defined by the fractional derivative and reference wavenumber. Velocity substitution allows wavelet estimation with the convolution model in the constant-velocity depth domain. The depth-domain generalized seismic wavelet model allows for a simple workflow that estimates the depth-domain wavelet by estimating two wavelet model parameters. Additionally, this simple workflow does not need to perform searches for the optimal regularization parameter and wavelet length, which are time-consuming in least-squares-based methods. The limited numerical search ranges of the two wavelet model parameters can easily be calculated using the constant phase and peak wavenumber of the depth-domain seismic data. Our method is verified using synthetic and real seismic data and further compared with least-squares-based methods. The results indicate that the proposed method is effective and stable even for data with a low S/N.

Phase decomposition

2016 ◽  
Vol 4 (3) ◽  
pp. SN1-SN10 ◽  
Author(s):  
John Castagna ◽  
Arnold Oyem ◽  
Oleg Portniaguine ◽  
Understanding Aikulola
Keyword(s):  
Phase Changes ◽  
Thin Layers ◽  
Rock Properties ◽  
Bright Spot ◽  
Phase Decomposition ◽  
Phase Component ◽  
Zero Crossings ◽  
Seismic Wavelet ◽  
Component Amplitude ◽  
Zero Phase

Any seismic trace can be decomposed into a 2D function of amplitude versus time and phase. We call this process phase decomposition, and the amplitude variation with time for a specific seismic phase is referred to as a phase component. For seismically thin layers, phase components are particularly useful in simplifying seismic interpretation. Subtle lateral impedance variations occurring within thin layers can be greatly amplified in their seismic expression when specific phase components are isolated. For example, the phase component corresponding to the phase of the seismic wavelet could indicate isolated interfaces or any other time symmetrical variation of reflection coefficients. Assuming a zero-phase wavelet, flat spots and unresolved water contacts may show directly on the zero-phase component. Similarly, thin beds and impedance ramps will show up on components that are 90° out of phase with the wavelet. In the case of bright spots caused by hydrocarbons in thin reservoirs because these occur when the reservoir is of an anomalously low impedance, it is safe to assume that the brightening caused by hydrocarbons occurs on the component [Formula: see text] out of phase with the wavelet. Amplitudes of other phase components associated with bright reflection events, resulting perhaps from differing impedances above and below the reservoir, thus obscure the hydrocarbon signal. Assuming a zero-phase wavelet, bright-spot interpretation is thus greatly simplified on the [Formula: see text] phase component. Amplitude maps for the Teal South Field reveal that the lateral distribution of amplitudes is greatly different for the original seismic data and the [Formula: see text] phase component, exhibiting very different prospectivity and apparent areal distribution of reservoirs. As the impedance changes laterally, the interference pattern for composite seismic events also changes. Thus, waveform peaks, troughs, and zero crossings, may not be reliable indicators of formation top locations. As the waveform phase changes laterally due to lateral rock properties variations, the position of a formation top on the waveform also changes. By picking horizons on distinct phase components, this ambiguity is reduced, and more consistent horizon picking is enabled.

scholarly journals Modeling the effects of fracture infill on frequency-dependent anisotropy and AVO response of a fractured porous layer

2021 ◽  
Author(s):  
Yan-Xiao He ◽  
Xin-Long Li ◽  
Gen-Yang Tang ◽  
Chun-Hui Dong ◽  
Mo Chen ◽  
...  
Keyword(s):  
Incident Angle ◽  
Transverse Isotropy ◽  
Rock Physics ◽  
Dispersive Media ◽  
Frequency Dependent ◽  
Hydrocarbon Reservoir ◽  
Impedance Contrast ◽  
Fracture Fluid ◽  
Rock Physics Modeling ◽  
Physics Modeling

AbstractIn a fractured porous hydrocarbon reservoir, wave velocities and reflections depend on frequency and incident angle. A proper description of the frequency dependence of amplitude variations with offset (AVO) signatures should allow effects of fracture infills and attenuation and dispersion of fractured media. The novelty of this study lies in the introduction of an improved approach for the investigation of incident-angle and frequency variations-associated reflection responses. The improved AVO modeling method, using a frequency-domain propagator matrix method, is feasible to accurately consider velocity dispersion predicted from frequency-dependent elasticities from a rock physics modeling. And hence, the method is suitable for use in the case of an anisotropic medium with aligned fractures. Additionally, the proposed modeling approach allows the combined contributions of layer thickness, interbedded structure, impedance contrast and interferences to frequency-dependent reflection coefficients and, hence, yielding seismograms of a layered model with a dispersive and attenuative reservoir. Our numerical results show bulk modulus of fracture fluid significantly affects anisotropic attenuation, hence causing frequency-dependent reflection abnormalities. These implications indicate the study of amplitude versus angle and frequency (AVAF) variations provides insights for better interpretation of reflection anomalies and hydrocarbon identification in a layered reservoir with vertical transverse isotropy (VTI) dispersive media.

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