Amplitude Versus Azimuth Research Articles

Modelling analysis of the limitation of P-wave AVAZ inversion

The limitation of P-wave amplitude versus azimuth (AVAZ) inversion for fracture attribute parameters was studied by numerical modeling. First, seismic reflection data from multiple azimuths and incident angles were synthetized using anisotropic elastic wave equation modeling performed on a geological model, with a homogeneous isotropic medium overlying an anisotropic medium comprising vertical fractures. Then AVAZ inversion for fracture attribute parameters was performed on the synthetic data, from noise free to a signal-to-noise ratio (SNR) level of 2. The results were analyzed by comparison with the actual attribute parameters of the model. We demonstrate that the fracture azimuth attributes from the AVAZ inversion of noise free data agree well with the actual models, with difference <1°, over incident angle range from 9.8° to 44.2°. Inversion results from noisy data, on the other hand, vary widely and failed to characterize the actual azimuth, though an average of many inversions may still be able to approximate azimuth. In contrast, fracture intensity attributes from AVAZ inversion generally carry large inherent errors. The AVAZ attributes from noise free data underestimate the intensity, using incident angle range of 15° to ~26°, with errors ranging from 8% to ~92%. Using a lager incident angle, within ~26° to 35°, overestimates the intensity, with errors up to ~461%. The inherent errors are so large and variable that the fracture intensity attributes from AVAZ inversion are not suitable for use as direct quantitative interpretation of fracture intensity. However, the relative differences of fracture intensity attributes from AVAZ inversion qualitatively agree with the actual intensity differences and may be exploited as a qualitative measure of fracture intensity variation applied to a very limited range of incident angles. For noisy data, it is difficult to characterize fracture azimuth, not only by a single inversion but also by a statistical mean of multiple inversion results and an effective de-noising processing strategy is a critical step for fracture azimuth inversion.

Time Lapsed AVAZ Seismic Modeling Research on CO2 Storage Monitoring

CCUS (Carbon Capture, Utilization and Storage) now is a lead way to reduce greenhouse effect such as carbon dioxide emission in the world. This paper presents an integrated overview of seismic monitoring technology when CO2 injection process. Mainly is time-lapse seismic method .Time-lapse seismic method is a feasible way to monitor CO2 injection process when CO2 interaction with minerals, which is proved an effective method in CCUS experiments. AVAZ (Amplitude versus Azimuth) seismic method is proved a useful tool to indentify CO2 injection process, which can detect fluid-induced seismic anisotropic response and locating where CO2 flow to in reservoirs, therefore, it’s an effective way to monitor CO2 flow in CO2 monitoring process. Since we develop AVAZ modelling experiment base on rock physics theory to modeling the time-lapse AVAZ seismic reservoir response. The research show fluid saturation and pressure behave two main factors influence modeling seismic AVAZ response. Meanwhile the AVAZ response can also be detect by seismic AVAZ data.

Polynomial amplitude versus azimuth inversion in horizontally transverse isotropic media, as tested on fractured coal seams in the Surat Basin

A new technique of amplitude versus azimuth (AVAZ) seismic inversion in horizontally transverse isotropic (HTI) media is presented. AVAZ is an effective method of characterising anisotropic variation within individual reflectors as well as characterising fractures. The compressional wave reflectivity equation in HTI media has been reformulated into a parabolic form that allows for fast and efficient inversion. The isotropic component of the azimuthal reflectivity has been separated precisely from the anisotropic component and the anisotropic component has been decoupled exactly into its constituent elliptic and anelliptic components. The exact isotropic, elliptic and anelliptic amplitude versus offset (AVO) gradient equations in HTI media are presented herein and the amount of error associated with previous approximations is also defined under the assumption of weak anisotropy. A method of calculating Thomsen’s weak anisotropy parameters using these AVO gradient terms is then outlined. Compared with the elliptic method, there is reduced error incorporated in the new AVAZ method and the error relationships of this method are compared with the Fourier method. Data from an open file 3D wide azimuth seismic survey in the Surat Basin were inverted to demonstrate the effectiveness of the techniques which are presented herein. Seismic amplitudes from six azimuthal stacks were extracted over two horizons and inverted around a well where full-wave sonic and density logs were acquired. For both horizons, the error between the inverted anisotropy parameters from seismic and the inverted anisotropy parameters from wire line logs were found to be less than 5% for both horizons.

Precise 3D seismic steering and production rates in the Wilrich tight gas sands of West Central Alberta

We evaluate the controls on production performance of the Wilrich tight gas sand play in West Central Alberta, and show that careful steering using 3D seismic to place the wellbore within the upper reservoir is the most important geophysical contribution to production outcomes. Geologic, geophysical, drilling, and production data from more than 20 wells are used in the analysis. The completion and production parameters within the study area are relatively invariant, creating a control experiment relative to other productivity factors. We thus isolate the effects of varying bottom hole pressures, porosity, wellbore length, number of stimulations, mud gas response, gamma ray measurements while drilling, mud weight, curvature, amplitude versus offset (AVO), amplitude versus azimuth (AVAz), velocity versus azimuth (VVAz), and position of the horizontal wellbore within the reservoir. These variables are treated separately and in a multivariate fashion to determine their relative and combined effect on the productivity of the wells. Several methods of statistical evaluation are used to test confidence in the results. The Wilrich sand is approximately 20-m thick, and it was expected that the multistage fracture stimulation would have minimized the importance of vertical permeability variations by adequately accessing the entire vertical reservoir section. Such is not the case; precise placement of the wellbore in the most permeable stratigraphy of the thin reservoir is of material importance. The pressure and porosity strongly affect the production performance, but to a lesser degree than vertical position within the reservoir. This suggests that stratigraphic concerns as they relate to permeability variation can be critical, even in thin fracture-stimulated reservoirs. Interesting relationships were observed between the AVAz and curvature measures, but neither they nor the AVO or VVAz attributes yielded statistically significant correlations to the production data.

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

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.

PP-wave reflection coefficients in weakly anisotropic elastic media

Approximate PP-wave reflection coefficients for weak contrast interfaces separating elastic, weakly transversely isotropic media have been derived recently by several authors. Application of these coefficients is limited because the axis of symmetry of transversely isotropic media must be either perpendicular or parallel to the reflector. In this paper, we remove this limitation by deriving a formula for the PP-wave reflection coefficient for weak contrast interfaces separating two weakly but arbitrarily anisotropic media. The formula is obtained by applying the first‐order perturbation theory. The approximate coefficient consists of a sum of the PP-wave reflection coefficient for a weak contrast interface separating two background isotropic half‐spaces and a perturbation attributable to the deviation of anisotropic half‐spaces from their isotropic backgrounds. The coefficient depends linearly on differences of weak anisotropy parameters across the interface. This simplifies studies of sensitivity of such coefficients to the parameters of the surrounding structure, which represent a basic part of the amplitude‐versus‐offset (AVO) or amplitude‐versus‐azimuth (AVA) analysis. The reflection coefficient is reciprocal. In the same way, the formula for the PP-wave transmission coefficient can be derived. The generalization of the procedure presented for the derivation of coefficients of converted waves is also possible although slightly more complicated. Dependence of the reflection coefficient on the angle of incidence is expressed in terms of three factors, as in isotropic media. The first factor alone describes normal incidence reflection. The second yields the low‐order angular variations. All three factors describe the coefficient in the whole region, in which the approximate formula is valid. In symmetry planes of weakly anisotropic media of higher symmetry, the approximate formula reduces to the formulas presented by other authors. The accuracy of the approximate formula for the PP reflection coefficient is illustrated on the model with an interface separating an isotropic half‐space from a half‐space filled by a transversely isotropic material with a horizontal axis of symmetry. The results show a very good fit with results of the exact formula, even in cases of strong anisotropy and strong velocity contrast.