Ruben D. Martinez

Wave propagation effects on amplitude variation with offset measurements; a modeling study

Wave propagation effects can significantly affect amplitude variation with offset (AVO) measurements. These effects include spreading losses, transmission losses, interbed multiples, surface multiple reflections, P‐SV mode converted waves and inelastic attenuation. Examination of prestack elastic synthetic seismograms suggests that spreading losses and the transmission losses plus compressional interbed multiples are manifest mainly as a time and offset effect on the primary reflections. The surface related multiples and the P‐SV mode‐converted waves interfere with prestack amplitudes inducing distortions in the AVO pattern. Such distortions cause large variances in AVO model fitting. Prestack viscoelastic synthetic seismograms also suggest that inelastic attenuation further complicates the AVO response because of the offset and time variant amplitude decay effects and the phase change due to dispersion. Together, all these effects severely alter AVO behavior and result in serious errors in AVO parameter ...

Formation Pressure Prediction With Seismic Data From the Gulf of Mexico

In this paper, the authors derive seismic formation-pressure logs using seismic data from offshore Louisiana to delineate the distribution of overpressured zones in the subsurface. The seismic-data processing consists of velocity modeling, wavelet processing, and seismic inversion. From the acoustic impedances produced by seismic inversion, the authors derive seismic velocity and density logs at every seismic tracer location using a relationship between sonic velocities and acoustic impedances. The authors use these logs to compute the seismic formation-pressure logs vs. depth. Formation-pressure logs are calculated with the assumption that compressional velocity, means density, and depth are proportional to formation pressure. These logs are constrained at every depth by estimated matrix and fluid compressional velocities (v{sub max} and v{sub min}). v{sup max} and v{sub min} are derived from porosity and sonic well-log information. Results include profiles of seismic-velocity, seismic-density, and formation-pressure logs for two intersecting seismic lines from offshore Louisiana. Log from one well are used to constrain the data processing. The seismic formation-pressure sections delineate a large region of overpressured shales in the subsurface.

ANALYSIS OF ABSORPTION AND DISPERSION EFFECTS IN SYNTHETIC tau -p SEISMOGRAMS.

Analysis of absorption and dispersion effects may be done in intercept time‐ray parameter (τ-p) synthetic seismograms calculated using the slowness formulation of the reflectivity method. Seismograms initially computed in the frequency‐ray parameter (ω-p) domain to incorporate absorption and dispersion effects are then Fourier transformed to the (τ-p) domain. Absorption and dispersion are functions of p. Modeling both simple and more realistic stratigraphic sequences shows the interaction of only velocity and density for infinite Q and the complicated effects added when Q is finite. The observed null reflection at p = 0 for infinite Q is no longer null when Q is finite. For p ≠ 0, the inclusion of absorption and dispersion effects complicates the amplitude and phase of the seismic response. Reflectivity due to Q alone (i.e., at an interface with no impedance contrast), as a function of Q contrast and p, contains interesting variations of amplitude and phase. The responses of three geologically realistic m...

Amplitude Preserving 3D Pre-stack Kirchhoff Time Migration For V(z) And VTI Media

Prestack time Kirchhoff migration has been known to be a flexible method to image 3D seismic data. It has traditionally used the straight ray assumption to compute the travel-times. With our new method, we can analytically estimate the travel-times for V(z) and VTI (transverse isotropy with vertical symmetry axis) media. In addition, we also calculate the appropriate amplitude weighting factors to preserve the relative amplitudes after migration. To include ray bending, the earth is assumed to consist of horizontal layers, i.e. V(z) media, so that the velocity profile used to calculate the travel-times is simply a function of depth or time. Because ray-bending and VTI are considered, the takeoff and emergence angles for shots and receivers could be calculated accurately compared to those obtained assuming straight rays. Thus, the amplitude correction terms of the operator can be determined using these takeoff and emergence angles to preserve the relative amplitudes. The algorithm is robust in the presence of irregular recording geometries and therefore lends itself well to its application on most modern seismic marine, OBS and land surveys. The migration tests results for model and real data demonstrate that our proposed traveltime equation and the amplitude weighting scheme produce better imaging results than those obtained with the straight ray migration.

Practical approaches for subsalt velocity model building

Imaging sediments below salt bodies is challenging because of the inherent difficulty of estimating accurate velocity models. These models can be estimated in a variety of ways with varying degrees of expense and effectiveness. Two methods are commercially viable trade-offs. In the first method, residual-moveout analysis is performed in a layer-stripping mode. The models produced with this method can be used as a first approximation of the subsalt velocity field. A wave-equation migration scanning technique is more suitable for fine-tuning the velocity model below the salt. Both methods can be run as part of a sophisticated interactive velocity interpretation software package that makes velocity interpretation efficient. Performance of these methods has been tested on synthetic and field data examples.

A strategy for anisotropic P-wave prestack imaging

Summary The prestack depth imaging process has been and is continuously evolving with the goal of accurately position the seismic events in space. To achieve this goal, the prestack imaging processes should account for velocity anisotropy. If the presence of velocity anisotropy is important, then ignoring it will have a significant impact in the final image accuracy. In this paper, we restrict our velocity anisotropy discussion to transverse isotropy with a vertical symmetry axis (VTI) or polar anisotropy. Since velocity and anisotropic parameters are connected, the estimation of reliable anisotropic parameters for prestack imaging is not trivial nor stable, therefore a strategy is required. We propose a strategy that combines anisotropic prestack time and depth imaging. The strategy consists of three parts. The first part consists of a loop where a prestack time migration designed to handle V(z) (vertical velocity heterogeneity) and VTI (vertical transverse isotropy) media is used to obtain a preliminary subsurface image, effective velocities (Vnmo) and effective anelliptical parameters (ηeff ). The second part of the strategy continues with the conversion of the effective anisotropic parameters to interval parameters as a function of depth. The third step in the strategy is to perform the depth imaging loop. In this step, the interval anisotropic parameters are iteratively refined until an optimized subsurface image is obtained in depth. The proposed strategy provides stability to the complete subsurface imaging process. The gain in stability becomes clear during the anisotropic parameter estimation stage since the effective parameters are first estimated using the proposed time migration and then converted to the interval parameters which are further refined in the depth imaging loops.

Anisotropic prestack depth migration improves the well‐ties at the Ewing Bank Oil Field, Gulf of Mexico

Summary We successfully applied anisotropic Kirchhoff prestack depth migration (AKPreDM) to a 3D data set from the Ewing Bank Oil Field, Gulf of Mexico to accurately map the target sands in depth. Initially, we used isotropic Kirchhoff prestack depth migration (IKPreDM) to perform the mapping of the reservoir sands. However, the depths estimated using the seismic data and those detected at the wells for the target sands showed excessive mis-ties (approximately 1100 feet). The results obtained after the application of AKPreDM showed that the misties were greatly reduced within a few tens of feet, therefore providing a better tie with the well tops. In this paper, we present the methodology employed in this case study, which includes the anisotropic parameter estimation. We also discuss the well tie results obtained after the application of AKPreDM and IKPreDM. We conclude that the effect of anisotropy (vertical transverse isotropy, VTI) should be taken into account to obtain seismic depth estimates that better tie the well depths accurately.

3D Kirchhoff PS-wave Prestack Time Migration For V(z) And VTI Media

P107 3D KIRCHHOFF PS-WAVE PRESTACK TIME MIGRATION FOR V(Z) AND VTI MEDIA Summary 1 The conventional 3D Kirchhoff P-S-wave pre-stack time migration (KPSTM) assumes straight raypaths therefore it assumes constant velocity media for the traveltime calculations. To improve upon this limitation we propose a new amplitude preserving KPSTM algorithm suitable for V(z) (velocity varying with depth) media. To include ray bending in the traveltime calculations the velocity is assumed to vary with depth and a new high order traveltime equation is used to calculate the traveltime instead of ray tracing. On the other hand transverse isotropy with a vertical symmetry

Limits on excited tau lepton from W→τντ decay

We evaluate the compositeness effects of leptons on the vertex Wτντ in the context of an effective Lagrangian approach and get the corrections to the non universal coupling gτ where we consider that only the third family is composed. We find the allowed region from the experimental gτ/ge quotient for (Λ versus m*) plane when the masses of the excited states of the third generation are considered equal, i.e., mτ*=mϑτ*=m*.

Constrained Seismic Data Processing Sequence For AVO Analysis Including a Case History

An approach to processing seismic data for amplitude versus offset (AVO) analysis is presented and illustrated with a case history. The seismic data was calibrated at key stages of the processing sequence using pre-stack synthetic seismograms derived from known lithologic and fluid conditions at one well location where two reservoirs (shallow and deep) were drilled. Petrophysical modeling to compute the shear wave velocity needed for the synthetic seismogram calculations was