Introduction to the special section on seismic-amplitude data and well logs

2014 ◽  
Vol 33 (5) ◽  
pp. 494-496
Author(s):  
Carlos Torres-Verdín
Keyword(s):  
Special Section ◽  
Well Logs ◽  
Seismic Amplitude ◽  
Amplitude Data

Estimating tilted fracture weaknesses from azimuthal differences in seismic amplitude data

Geophysics ◽  
2020 ◽  
Vol 85 (3) ◽  
pp. R135-R146
Author(s):  
Huaizhen Chen ◽  
Tiansheng Chen ◽  
Kristopher A. Innanen
Keyword(s):  
Reflection Coefficient ◽  
Tilt Angle ◽  
Seismic Data ◽  
Fractured Reservoirs ◽  
Transverse Isotropy ◽  
Elastic Response ◽  
Moderate Degree ◽  
Fractured Reservoir ◽  
Seismic Amplitude ◽  
Amplitude Data

Tilted transverse isotropy (TTI) provides a useful model for the elastic response of a medium containing aligned fractures with a symmetry axis oriented obliquely in the vertical and horizontal coordinate directions. Robust methods for determining the TTI properties of a medium from seismic observations to characterize fractures are sought. Azimuthal differencing of seismic amplitude data produces quantities that are particularly sensitive to TTI properties. Based on the linear slip fracture model, we express the TTI stiffness matrix in terms of the normal and tangential fracture weaknesses. Perturbing stiffness parameters to simulate an interface separating an isotropic medium and a TTI medium, we derive a linearized P-to-P reflection coefficient expression in which the influence of tilt angle and fracture weaknesses separately emerge. We formulate a Bayesian inversion approach in which amplitude differences between seismic data along two azimuths, interpreted in terms of the reflection coefficient approximation, are used to determine fracture weaknesses and tilt angle. Tests with simulated data confirm that the unknown parameter vector involving fracture weakness and tilted fracture weaknesses is stably estimated from seismic data containing a moderate degree of additive Gaussian noise. The inversion approach is applied to a field surface seismic data acquired over a fractured reservoir; from it, interpretable tilted fracture weaknesses, consistent with expected reservoir geology, are obtained. We determine that our inversion approach and the established inversion workflow can produce the properties of systems of tilted fractures stably using azimuthal seismic amplitude differences, which may add important information for characterization of fractured reservoirs.

Seismic attributes and structural interpretation—it takes two to tango...

2012 ◽  
Vol 52 (1) ◽  
pp. 437 ◽  
Author(s):  
Guillaume Backé ◽  
Ernest Swierczek ◽  
Justin MacDonald ◽  
Adam Bailey ◽  
David Tassone ◽  
...  
Keyword(s):  
Structural Information ◽  
Median Filter ◽  
Seismic Attributes ◽  
3D Seismic ◽  
Seismic Amplitude ◽  
The North ◽  
Amplitude Data ◽  
Fracture Models ◽  
Processing Techniques

In this paper, different 3D seismic attributes calculated to improve the accuracy and robustness of structural interpretations in several energy-rich Australian basins are compared. Detailed and precise fault and fracture maps are crucial not only for initial petroleum play assessment, but also for fault seal analysis and reservoir integrity studies. Robust fault and fracture models are also needed to improve the design of reservoir simulation programs and to manage the long-term containment of gas in geological formations. Different attributes (including coherency, dip-steered similarity, dip-steered median filter, dip-steered variance, apparent dip, and dip-steered most-positive and most-negative curvatures) from an array of 3D seismic datasets to better image structural fabrics, such as normal and different fractures patterns, in the North Perth, Cooper, Ceduna, Otway and Gippsland basins have been calculated. The results provide a remarkable improvement in the quality and precision of structural maps using this multi-attribute mapping workflow by comparison with more conventional maps produced, solely using seismic amplitude data. The key to the successful application of multi-attribute structural analysis, however, remains with the ability of the interpreter to identify meaningful structural information from a large volume of data. Thus, the structural expertise of the interpreter remains as the cornerstone to making geological sense of the various seismic processing techniques available.

Amplitude map analysis using forward modeling in sandstone and carbonate reservoirs

Geophysics ◽  
1993 ◽  
Vol 58 (10) ◽  
pp. 1428-1441 ◽  
Author(s):  
Dennis B. Neff
Keyword(s):  
Tuning Curve ◽  
Forward Modeling ◽  
Carbonate Reservoirs ◽  
Model Type ◽  
Seismic Amplitude ◽  
Modeling Process ◽  
Fluid Saturation ◽  
Amplitude Data ◽  
Map Analysis ◽  
Amplitude Versus

The extent to which seismic amplitude maps can contribute to the analysis of hydrocarbon reservoirs was investigated for clastic and carbonate reservoirs worldwide. By using a petrophysical‐based, forward modeling process called incremental pay thickness (IPT) modeling, five lithology types were quantitatively analyzed for the interplay of seismic amplitude versus lithology, porosity, hydrocarbon pore fluid saturation, bedding geometries, and reservoir thickness. The studies identified three common tuning curve shapes (concave, convex, and bilinear) that were primarily dependent upon the lithology model type and the average net porosity therein. While the reliability of pay and porosity predictions from amplitude maps varied for each model type, all analyses showed a limited thickness range for which amplitude data could successfully predict net porosity thickness or hydrocarbon pore volume. The investigation showed that systematic forward modeling is required before amplitude maps can be properly interpreted.

Techniques and best practices in multiattribute display

2015 ◽  
Vol 3 (1) ◽  
pp. B1-B23 ◽  
Author(s):  
Kurt J. Marfurt
Keyword(s):  
Central Basin ◽  
Seismic Amplitude ◽  
West Texas ◽  
3D Data ◽  
Amplitude Data ◽  
Data Volume ◽  
Similar Images ◽  
True Color ◽  
Central Basin Platform ◽  
Display Technique

All color monitors display images by mixing red, green, and blue (RGB) components. These RGB components can be defined mathematically in terms of hue, lightness, and saturation (HLS) components. A fourth alpha-blending (also called opacity) component provides a means to corender multiple images. Most, but not all, modern commercial interpretation workstation software vendors provide multiattribute display tools using an opacity model. A smaller subset of vendors provide tools to interactively display two or three attributes using HLS, CMY, and RGB color models. I evaluated a technique (or trick) to simulate the HLS color model using monochromatic color bars and only opacity. This same trick only approximates true color blending of RGB or CMY components. There are three basic objectives in choosing which attributes to display together. The first objective is to understand the correlation of one attribute to another, and most commonly, of a given attribute to the original seismic amplitude data. The second objective is to visualize the confidence or relevance of a given attribute by modulating it with a second attribute. The third objective is to provide a more integrated image of the seismic data volume by choosing attributes that are mathematically independent but correlated through the underlying geology. I developed the interpretation value of the HLS display technique on a 3D data volume acquired over the Central Basin Platform of west Texas exhibiting faults, fractures, folds, channels, pinch outs, and karst features. To be a useful “technique,” I need to demonstrate these workflows within a specific package. Although I implemented the workflow in Petrel 2014, similar images can be generated using any software with flexible opacity capabilities. I also developed a short list of attribute combinations that are particularly amenable to corendering in HLS.

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