Measurements of attenuation from vertical seismic profiles by iterative modeling

Geophysics ◽  
1985 ◽  
Vol 50 (6) ◽  
pp. 931-949 ◽  
Author(s):  
Michel Dietrich ◽  
Michel Bouchon
Keyword(s):  
Velocity Dispersion ◽  
Synthetic Data ◽  
Layered Media ◽  
Spectral Ratio ◽  
Ratio Method ◽  
Seismic Profiles ◽  
Vertical Seismic Profiles ◽  
Anelastic Attenuation ◽  
Vsp Data ◽  
Intrinsic Dissipation

We present a numerical simulation of vertical seismic profiles (VSP) using the discrete horizontal wavenumber representation of seismic wave fields. The theoretical seismograms are computed in the acoustic case for flat layered media, and they include the effects of absorption and velocity dispersion. A study using the synthetic seismograms was conducted to investigate the accuracy and resolution of attenuation measurements from VSP data. It is shown that in finely layered media estimates of the anelastic attenuation obtained by use of the reduced spectral ratio method are usually inaccurate when the attenuation is measured over a small vertical extent. An iterative method is presented which improves the resolution of the measurements of intrinsic dissipation. This method allows determination for synthetic data of the quality factor over depth intervals of about one wavelength of the dominant seismic frequency.

Traveltime inversion of offset vertical seismic profiles—A feasibility study

Geophysics ◽  
1984 ◽  
Vol 49 (3) ◽  
pp. 250-264 ◽  
Author(s):  
L. R. Lines ◽  
A. Bourgeois ◽  
J. D. Covey
Keyword(s):  
Inverse Method ◽  
Synthetic Data ◽  
Real Data ◽  
Seismic Profile ◽  
Inversion Method ◽  
Earth Model ◽  
Seismic Profiles ◽  
Traveltime Inversion ◽  
Vertical Seismic Profiles ◽  
Inversion Techniques

Traveltimes from an offset vertical seismic profile (VSP) are used to estimate subsurface two‐dimensional dip by applying an iterative least‐squares inverse method. Tests on synthetic data demonstrate that inversion techniques are capable of estimating dips in the vicinity of a wellbore by using the traveltimes of the direct arrivals and the primary reflections. The inversion method involves a “layer stripping” approach in which the dips of the shallow layers are estimated before proceeding to estimate deeper dips. Examples demonstrate that the primary reflections become essential whenever the ratio of source offset to layer depth becomes small. Traveltime inversion also requires careful estimation of layer velocities and proper statics corrections. Aside from these difficulties and the ubiquitous nonuniqueness problem, the VSP traveltime inversion was able to produce a valid earth model for tests on a real data case.

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.

Multichannel Wiener deconvolution of vertical seismic profiles

Geophysics ◽  
1994 ◽  
Vol 59 (10) ◽  
pp. 1500-1511 ◽  
Author(s):  
Jakob B. U. Haldorsen ◽  
Douglas E. Miller ◽  
John J. Walsh
Keyword(s):  
Least Squares ◽  
Amplitude Spectrum ◽  
Seismic Source ◽  
Seismic Profile ◽  
Signal Spectrum ◽  
Seismic Profiles ◽  
Vertical Seismic Profiles ◽  
Vsp Data ◽  
Zero Offset ◽  
Noise Signature

We describe a technique for performing optimal, least‐squares deconvolution of vertical seismic profile (VSP) data. The method is a two‐step process that involves (1) estimating the source signature and (2) applying a least‐squares optimum deconvolution operator that minimizes the noise not coherent with the source signature estimate. The optimum inverse problem, formulated in the frequency domain, gives as a solution an operator that can be interpreted as a simple inverse to the estimated aligned signature multiplied by semblance across the array. An application to a zero‐offset VSP acquired with a dynamite source shows the effectiveness of the operator in attaining the two conflicting goals of adaptively spiking the effective source signature and minimizing the noise. Signature design for seismic surveys could benefit from observing that the optimum deconvolution operator gives a flat signal spectrum if and only if the seismic source has the same amplitude spectrum as the noise.

Estimation of Q from surface seismic reflection data

Geophysics ◽  
1998 ◽  
Vol 63 (6) ◽  
pp. 2120-2128 ◽  
Author(s):  
Rahul Dasgupta ◽  
Roger A. Clark
Keyword(s):  
Attenuation Factor ◽  
Spectral Ratio ◽  
Ratio Method ◽  
Amplitude Analysis ◽  
Gas Reservoir ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
Anelastic Attenuation ◽  
Zero Offset ◽  
Nmo Stretch

Reliable estimates of the anelastic attenuation factor, Q, are desirable for improved resolution through inverse Q deconvolution and to facilitate amplitude analysis. Q is a useful petrophysical parameter itself, yet Q is rarely measured. Estimates must currently be made from borehole seismology. This paper presents a simple technique for determining Q from conventional surface seismic common midpoint (CMP) gathers. It is essentially the classic spectral ratio method applied on a trace‐by‐trace basis to a designatured and NMO stretch‐corrected CMP gather. The variation of apparent Q versus offset (QVO) is extrapolated to give a zero‐offset Q estimate. Studies on synthetics suggest that, for reasonable data quality (S/N ratios better than 3:1, shallow (<5°) dips, and stacking velocity accuracy <5%), source‐to‐reflector average Q is recoverable to within some 3% and Q for a specific interval (depending on its two‐way time thickness and depth) is recoverable to 15–20%. Three case studies are reported. First, Q versus offset and vertical seismic profiling (VSP) Q estimates for a southern North Sea line were in close agreement, validating the method. For Chalk, Mushelkalk‐Keuper, and Bunter‐Zechstein, Q was estimated as 130 ± 15, 47 ± 8, and 156 ± 18, respectively. Next, two alternative lithological interpretations of a structure seen in a frontier area were discriminated between when Q estimates of 680 to 820 were obtained (compared to some 130–170 in the overlying units), favoring a metamorphic/crystalline lithology rather than (prospective) sediments. This was later confirmed by drilling. Third, a profile of Q estimates along a 200-ms-thick interval, known to include a gas reservoir, showed a clear and systematic reduction in Q to a low of 50 ± 11, coincident with the maximum reservoir thickness, from some 90–105 outside the reservoir. Q for the reservoir interval itself was estimated at 17 ± 7.

Tomographic determination of three‐dimensional seismic velocity structure using well logs, vertical seismic profiles, and surface seismic data

Geophysics ◽  
1987 ◽  
Vol 52 (8) ◽  
pp. 1085-1098 ◽  
Author(s):  
Stephen K. L. Chiu ◽  
Robert R. Stewart
Keyword(s):  
Velocity Structure ◽  
Seismic Velocity ◽  
Random Noise ◽  
Three Dimensional ◽  
Real Data ◽  
Well Logs ◽  
Seismic Profiles ◽  
Vertical Seismic Profiles ◽  
The Earth ◽  
Vsp Data

A tomographic technique (traveltime inversion) has been developed to obtain a two‐ or three‐dimensional velocity structure of the subsurface from well logs, vertical seismic profiles (VSP), and surface seismic measurements. The earth was modeled by continuous curved interfaces (polynomial or sinusoidal series), separating regions of constant velocity or transversely isotropic velocity. Ray tracing for each seismic source‐receiver pair was performed by solving a system of nonlinear equations which satisfy the generalized Snell’s law. Surface‐to‐borehole and surface‐to‐surface rays were included. A damped least‐squares formulation provided the updating of the earth model by minimizing the difference between the traveltimes picked from the real data and calculated traveltimes. Synthetic results indicated the following conclusions. For noise‐free cases, the inversion converged closely from the initial guess to the true model for either surface or VSP data. Adding random noise to the observations and performing the inversion indicated that (1) using surface data alone allows reconstruction of the broad velocity structure but with some inaccuracy; (2) using VSP data alone gives a very accurate but laterally limited velocity structure; and (3) the integration of both data sets produces a more laterally extensive, accurate image of the subsurface. Finally, a field example illustrates the viability of the method to construct a velocity structure from real data.

Accurate interval Q-factor estimation from VSP data

Geophysics ◽  
2012 ◽  
Vol 77 (3) ◽  
pp. WA149-WA156 ◽  
Author(s):  
E. Blias
Keyword(s):  
Real Data ◽  
Spectral Ratio ◽  
Ratio Method ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
Seismic Quality Factor ◽  
Vsp Data ◽  
Considerable Impact ◽  
The Difference ◽  
Factor Estimation

Inelastic attenuation, quantified by [Formula: see text], the seismic quality factor, has considerable impact on surface seismic reflection data. A new method for interval [Formula: see text]-factor estimation using near-offset VSP data was based on an objective function minimization measuring the difference between cumulative [Formula: see text] estimates and those calculated through interval [Formula: see text]. To calculate interval [Formula: see text], we used all receiver pairs that provided reasonable [Formula: see text] values. To estimate [Formula: see text] between two receiver levels, we used the equation that links amplitudes at different levels and could provide more accurate [Formula: see text] values than the spectral-ratio method. To improve interval [Formula: see text] estimates, which rely on traveltimes, we used a high-accuracy approach in the frequency domain to determine time shifts. Application of this method to real data demonstrated reasonable correspondence between [Formula: see text] estimates and log data.

Vertical seismic profiling depth migration of a salt dome flank

Geophysics ◽  
1986 ◽  
Vol 51 (5) ◽  
pp. 1087-1109 ◽  
Author(s):  
N. D. Whitmore ◽  
Larry R. Lines
Keyword(s):  
Data Processing ◽  
Survey Design ◽  
Velocity Model ◽  
Salt Dome ◽  
Velocity Estimation ◽  
Seismic Profiles ◽  
Depth Migration ◽  
Vertical Seismic Profiles ◽  
Interval Velocity ◽  
Vsp Data

Vertical seismic profiles (VSPs) can supply information about both velocity and subsurface interface locations. Properly designed VSPs can be used to map steeply dipping interfaces such as salt dome flanks. Mapping subsurface interfaces with VSP data requires careful survey design, appropriate data processing, interval velocity estimation, and reflector mapping. The first of these four ingredients is satisfied, in most cases, by preacquisition modeling. The second is accomplished by careful data processing. Initial velocity estimates are provided by seismic tomography. Velocity‐model refinement is accomplished by a combination of iterative modeling and iterative least‐squares inversion. Finally, the resultant interval velocities are used in depth migration of the processed VSP. These four ingredients have been combined to map a salt dome flank.

Waveform-based estimation of Q and scattering properties for zero-offset vertical seismic profile data

Geophysics ◽  
2020 ◽  
Vol 85 (4) ◽  
pp. R365-R379
Author(s):  
Rie Nakata ◽  
David Lumley ◽  
Gary Hampson ◽  
Kurt Nihei ◽  
Nori Nakata
Keyword(s):  
Field Data ◽  
Estimation Method ◽  
Spectral Ratio ◽  
Seismic Profile ◽  
Ratio Method ◽  
Vsp Data ◽  
Spectral Ratio Method ◽  
Band Limited ◽  
Zero Offset ◽  
Negative Formula

Estimating [Formula: see text] using downgoing waves in zero-offset vertical seismic profiles (VSPs) can be challenging when scattered waves from near-borehole heterogeneities interfere with direct arrivals. In any [Formula: see text] estimation method that assumes a downgoing plane wave, constructive and destructive wave-mode interference can cause errors in the estimate. For example, in the spectral-ratio method, such interference modulates the amplitude spectra introducing significant variations and even nonphysical negative [Formula: see text] (amplification) estimates. We have investigated this phenomenon using synthetic and field data sets from offshore Australia and developed a two-step waveform-based method to characterize scattering anomalies and improve [Formula: see text] estimates. Waveform information is key to deal with closely spaced band-limited seismic events. First, we solve an inverse problem to locate and characterize scatterers by minimizing the traveltime and waveform misfits. Then, using the estimated parameters, we model the scatterers’ contribution to the VSP data and remove it from the observed waveforms. The resulting spectra resemble those that would have been acquired in the absence of the scatterers and are much more suitable for the spectral-ratio method. By assuming a 1D medium and a simple scatterer shape (i.e., circular), we parameterize a scattering heterogeneity using five parameters (depth, distance, size, velocity, and density) and seek a solution using a grid search to handle the nonuniqueness of the VSP inversion. Instead, adaptive subtraction is required to fine-tune the modeled interference to better fit the observation. We successfully use this method to characterize and mitigate the strongest wave interference in the field data. The final [Formula: see text] estimates contain milder variations and much less nonphysical negative [Formula: see text]. Our results demonstrate that the proposed method, readily extendible to multiple scatterer cases, can locate discrete scatterers, remove the effects of their interference, and thus significantly improve the [Formula: see text] estimates from VSP data.

Seismic anelastic attenuation estimation using prestack seismic gathers

Geophysics ◽  
2019 ◽  
Vol 84 (6) ◽  
pp. M37-M49
Author(s):  
Naihao Liu ◽  
Bo Zhang ◽  
Jinghuai Gao ◽  
Hao Wu ◽  
Shengjun Li
Keyword(s):  
Seismic Data ◽  
Seismic Waves ◽  
Synthetic Data ◽  
Spectral Ratio ◽  
Time Frequency ◽  
Anelastic Attenuation ◽  
Time Migration ◽  
Seismic Quality Factor ◽  
Zero Offset ◽  
Nmo Stretch

The seismic quality factor [Formula: see text] quantifies the anelastic attenuation of seismic waves in the subsurface and can be used in assisting reservoir characterization and as an indicator of hydrocarbons. Usually, the [Formula: see text]-factor is estimated by comparing the spectrum changes of vertical seismic profiles and poststack seismic data. However, seismic processing such as the normal moveout (NMO) stretch would distort the spectrum of the seismic data. Hence, we have estimated [Formula: see text] using prestack time migration gathers. To mitigate the NMO stretch effect, we compensate the NMO stretch of prestack seismic gathers in the time-frequency domain. Similar to the log spectral method, our method obtains the [Formula: see text] by measuring the log spectral ratio (LSR) of seismic events of the top and base of the reservoir at a zero-offset seismic trace. The LSR has a linear relationship with a new parameter [Formula: see text] by assuming that the source wavelet is a constant-phase wavelet. The parameters [Formula: see text] and LSR vary with the offset value (traveltime). We use the values of [Formula: see text] and LSR obtained from nonzero-offset seismic traces to simulate the values of [Formula: see text] and LSR at a zero-offset seismic trace. Finally, we obtain [Formula: see text] by applying the classic LSR method to the simulated [Formula: see text] and LSR. To demonstrate the validity and effectiveness of our method, we first apply it to noise-free and noisy synthetic data examples and then to real seismic data acquired over the Sichuan Basin, China. The synthetic and real seismic applications demonstrate the effectiveness of our method in highlighting high anelastic-attenuation zones.

Nonlinear approach to spectral ratio method for estimation of seismic quality factor from VSP data

2019 ◽  
Vol 167 ◽  
pp. 33-41 ◽  
Author(s):  
Pardeep Sangwan ◽  
Dinesh Kumar ◽  
Subrata Chakraborty ◽  
Vidya Mundayat ◽  
M.K. Balasubramaniam
Keyword(s):  
Quality Factor ◽  
Spectral Ratio ◽  
Ratio Method ◽  
Nonlinear Approach ◽  
Seismic Quality Factor ◽  
Vsp Data ◽  
Spectral Ratio Method
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