Fracture Characterization – A Fully Integrated Study, from Borehole Imagery, Cores and Seismic Data to Production Logs

2009 ◽  
Author(s):  
M. Panien ◽  
E. Portier ◽  
F. Marcy ◽  
L. Ghilardini ◽  
T. Dehaeck ◽  
...  
Keyword(s):  
Seismic Data ◽  
Fracture Characterization ◽  
Fully Integrated ◽  
Integrated Study

Characterization of layered anisotropic media from prestack PS-wave-reflection data

Geophysics ◽  
2006 ◽  
Vol 71 (5) ◽  
pp. D171-D182 ◽  
Author(s):  
Jason E. Gumble ◽  
James E. Gaiser
Keyword(s):  
Gulf Of Mexico ◽  
Seismic Data ◽  
Equivalent Model ◽  
Time Shift ◽  
Layer By Layer ◽  
Converted Wave ◽  
Data Set ◽  
Fracture Characterization ◽  
Anisotropic Models ◽  
Hti Media

Anisotropy and fracture characterization in individual layers is realized through iterative layer stripping corrections of four, converted-wave (PS-wave) synthetic reflection seismic data sets, generated from azimuthally anisotropic (HTI and TTI) models, and a four component (4-C) data set from the Teal South, Gulf of Mexico. The corrections were applied on a layer-by-layer basis to evaluate the efficacy of constant polarization rotation and time-shift operators. Equivalent isotropic models were compared to anisotropic models after layer-stripping corrections using rms amplitude and shear-wave-splitting time-difference maps to quantify and identify inherent errors in estimating seismic polarization parameters. For HTI media radial and transverse components of PS data that have had layer-stripping corrections applied, exhibit incorrect symmetry and orientations. This may adversely affect inversion and/or amplitude-variation with angle offset (AVO) and amplitude versus azimuth (AVA)analysis. Layer-stripping corrections applied to fast and slow ([Formula: see text] and [Formula: see text], respectively) components exhibit the correct symmetry and orientation. Time differences between PS1 and PS2 are computed using crosscorrelation. Previous studies have addressed some of the problems associated with layer-stripping corrections for the case of vertical fractures (HTI media) and poststack layer-stripping analyses. This study includes an equivalent model with dipping fractures (TTI media) and extends the scope to encompass the effects of anisotropy on prestack data. The results from an application of the same technique are also applied to a limited set of 4-C data from the Teal South project in the Gulf of Mexico. Results are consistent with those of previous studies involving solely poststack 4-C rotation analysis in terms of average, or zero offset, time differences and symmetry orientation. Offset and azimuth amplitude/traveltime variations, however, indicate that there is more information contained in prestack seismic data than 4-C rotation can comprehend.

Fracture characterization of deep tight gas sands using azimuthal velocity and AVO seismic data in Saudi Arabia

2003 ◽  
Vol 22 (5) ◽  
pp. 469-475 ◽  
Author(s):  
Fernando A. Neves ◽  
Ahmed Al-Marzoug ◽  
Jung J. Kim ◽  
Ed L. Nebrija
Keyword(s):  
Saudi Arabia ◽  
Seismic Data ◽  
Azimuthal Velocity ◽  
Tight Gas ◽  
Fracture Characterization ◽  
Tight Gas Sands

A new Fourier azimuthal amplitude variation fracture characterization method: Case study in the Haynesville Shale

Geophysics ◽  
2018 ◽  
Vol 83 (1) ◽  
pp. WA101-WA120 ◽  
Author(s):  
Anthony Barone ◽  
Mrinal K. Sen
Keyword(s):  
Seismic Data ◽  
Large Scale ◽  
Rock Fracture ◽  
Crack Density ◽  
Fracture Density ◽  
Success Rates ◽  
High Fracture ◽  
Fracture Characterization ◽  
Free Data ◽  
Seismic Reflectivity

We have evaluated a novel fracture characterization technique using azimuthal amplitude variations (AVAz) present in 3D seismic data, and we implemented it using synthetic and real seismic data targeting the Haynesville Shale. The method we evaluated overcomes many common AVAz limitations and differs from standard AVAz approaches in the following ways: (1) It was explicitly designed to model vertically fractured transverse isotropic (VFTI) media; (2) it can correctly resolve the fracture strike azimuth without a 90° ambiguity and uses a new magnitude-based method that is invariant to the sign of seismic reflectivity [Formula: see text]; and (3) it incorporates advanced inversion techniques to estimate a novel fracture density proxy that responds linearly to crack density. Our method is based on a newly derived relationship that relates seismic reflectivity directly to rock/fracture properties in VFTI media. We validated our method through rigorous testing on more than 400 synthetic seismic data sets. These synthetic tests indicate that our method excels at estimating fracture azimuth and fracture density from surface seismic data with overall success rates around 80%–85% for noisy data and 90%–95% for noise-free data. Applying our method to field data from the Haynesville Shale indicates that the dominant fracture set is oriented at approximately [Formula: see text] relative to geodetic north, i.e., rotated slightly counterclockwise of east–west. We assume a constant azimuth of 80° throughout our relatively small 20 square miles study area, and our method clearly identifies a general area with unusually high fracture density as well as several smaller subzones of dense fracturing. These smaller features appear to be connected by a pervasive large-scale fracture network covering the area with dominant features aligned at roughly parallel and perpendicular to our calculated fracture azimuth. Although we could not directly confirm these fracture characteristics, our results largely agree with previously published information about fracturing in our study area.

Fracture characterization in the Delaware Basin using wide-azimuth seismic data

2019 ◽  
Author(s):  
Colin M. Sayers ◽  
Lennert D. den Boer ◽  
Adam Koesoemadinata ◽  
Edan Gofer ◽  
Michael Shoemaker
Keyword(s):  
Seismic Data ◽  
Fracture Characterization ◽  
Delaware Basin
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