Abstract We investigate the effects of changes in rock and fluid properties on amplitude-variation-with-offset (AVO) responses. In the slope-intercept domain, reflections from wet sands and shales fall on or near a trend that we call the fluid line. Reflections from the top of sands containing gas or light hydrocarbons fall on a trend approximately parallel to the fluid line; reflections from the base of gas sands fall on a parallel trend on the opposing side of the fluid line. The polarity standard of the seismic data dictates whether these reflections from the top of hydrocarbon-bearing sands are below or above the fluid line. Typically, rock properties of sands and shales differ, and therefore reflections from sand/shale interfaces are also displaced from the fluid line. The distance of these trends from the fluid line depends upon the contrast of the ratio of P-wave velocity V P and S-wave velocity V S . This ratio is a function of pore-fluid compressibility and implies that distance from the fluid line increases with increasing compressibility. Reflections from wet sands are closer to the fluid line than hydrocarbon-related reflections. Porosity changes affect acoustic impedance but do not significantly impact the V P / V S contrast. As aresult, porosity changes move the AVO response along trends approximately parallel to the fluid line. These observations are useful for interpreting AVO anomalies in terms of fluids, lithology, and porosity.

Abstract A data set containing marine seismic data and well-log measurements of key elastic parameters was compiled from data acquired in an area containing hydrocarbon reservoirs. This data set was created for the purpose of testing seismic inversion methods. The data set includes information that is often unavailable with field data and, therefore, may be used to cross check results of seismic processing or inversion algorithms. The data set has been released to the public domain to encourage the investigation of seismic inversion methods.

Abstract Attenuation and dispersion of the seismic pulse can strongly affect the outcome of amplitude versus offset (AVO) analysis. These anelastic aspects of wave propagation also influence the outcome of linear inversion for short scale fluctuations in elastic parameters, the model based analogue of AVO analysis. The viscoacoustic model provides a framework for illustration of these effects. An efficient time domain viscoacoustic finite difference scheme for synthesis of primaries only plane-wave (1-D model) and line source (2-D model) reflection records is the basis for linear inversion algorithms via iterative minimization of mean square error. This approach to inversion requires computation of the mean square error gradient. The gradient computation becomes feasible through the use of the adjoint state technique, together with a checkpointing scheme due to Griewank. Inversion of synthetic data in the plane-wave domain illustrates the sensitivity to attenuation of even qualitative aspects of inversion. Viscoacoustic 2-D inversion of a small part of the Mobil AVO data illustrates applicability to field data in the offset domain.

Abstract The objective of the present work is to obtain estimates of the P - and S -wave velocities and densities of the subsurface. The inversion is carried out on 952 τ – p transformed CMP gathers, each containing 61 p values ranging from 0.05 to 0.35 s/km. The forward modeling is performed by convolving the reflectivity with the wavelet, and it includes water bottom multiples, transmission effects, absorption and array filter effects. The basic assumption is that the subsurface is close to horizontally layered. A damped Gauss-Newton algorithm is used to minimize a least-squares misfit function. Comparison with the two well logs shows good agreement for the P -wave velocity estimates in the areas where the geology is close to horizontally stratified. In deeper and faulted areas the deviation between estimated and measured P -wave velocities is larger. The same trend holds for the S -wave velocity estimates, while the densities are the poorest resolved seismic parameter.

Abstract Results of an AVO methodology applied to the Mobil AVO data set are presented. The AVO methodology integrates seismic and petrophysical methods and consists of AVO feasibility, amplitude-preserved preprocessing, prestack amplitude-preserved depth migration, and stable AVO inversion, log seismic calibration and interpretation. A preliminary interpretation of P - and S -impedance depth images derived by our AVO methodology confirmed that the potential gas reservoir defined by log data could be identified on the seismic data.

Abstract We present our results on amplitude-preserved data processing and analysis of the Mobil AVO data set. First, we apply a source and receiver consistent amplitude balancing to the seismic data, which reduces source and receiver amplitude variance from about 8% and 15%, respectively, to within a few percent scatter. Next, we apply a time-domain conjugate-gradient multiple-suppression technique to remove multiple reflection energy and simultaneously preserve and enhance primary reflection AVO amplitudes. We perform unmigrated AVO analyses and find that the multiple-suppressed data correlate better with the well-log data than the unprocessed data. A prestack migration/inversion of the multiple-suppressed data show a clear improvement over unmigrated AVO analysis and reveal an undrilled graben block in the center of the line that exhibits a positive hydrocarbon indicator anomaly.

Abstract Three different methodologies for estimating compressional ( P ) and shear ( S ) wave reflectivities were examined using the Mobil North Sea data set. All three approaches involved estimating intercept and slope values from the seismic data and then converting these intercept and slope estimates into P - and S -wave reflectivity. The first approach used the traditional method of estimating intercept and slope from unmigrated NMO corrected CMP gathers. The second also estimated intercept and slope from NMO corrected CMP gathers, but the estimation was performed after common-offset time migration. The third technique inverts for intercept and slope as part of the imaging process using a linearized form of the wave equation. Comparisons with well-log data show that estimates of P - and S -wave reflectivity obtained from a least-squares fit of amplitude versus offset in CMP gathers failed to match trends seen in the log data. Reflectivities obtained from the prestack inversion did match the log data trends. None of the techniques, however, match the well-log data in detail.

Abstract A seismic profile of recent-vintage, good-quality data along with certain other subsurface information was provided for trace inversion processing. Time constraints for the study only allowed that the well logs could be used for straightforward correlative purposes. Evaluation of the inversion encompasses both the effectiveness of the data display as well as assessment of the information content which is enhanced and preserved. With limited ground-truth, only the credibility and consistency of interpretive conclusions can help establish validity. This is the procedure adapted here. Any interpretation must be presented as fully as possible against a more general background, and details of data treatment and the interpretive procedure also must be well described in order that the results can be fully appreciated. Such an approach was taken here. Our approach considers the North Sea Basin in general before focusing on the study area. Velocity, the data treatment, and the seismic expression of lithologies, all relevant to this work, are addressed. In this way, the interpretive results from this single line study can best be assessed. Also, the validity of indicated anomalies can be put into a more practical context. The limited local data diminish to a substantial degree the certainty of results obtained. Nevertheless, suggestions for additional studies are offered to corroborate those positive leads which were obtained. Also future directions are noted for the North Sea with the understanding that the present study has contributed to this overall view.

Abstract The data set provided for amplitude versus offset (AVO) inversion has been subjected to the three steps which are involved in the DELPHI consortium program: preprocessing, structural imaging, and lithologic characterization. In the preprocessing step, a major problem is the presence of strong surface-related multiples. With an integrated surface-related and Radon multiple elimination procedure, it was possible to remove the multiples in a satisfactory way without distorting the primary AVO characteristics. Once the multiples were removed, structural imaging could be done in a fairly straightforward way, in which prestack migration techniques were used to get a good macro velocity depth model for the poststack depth migration. In the lithologic inversion stage, anomalies in the compressional to shear wave velocity c p / c s ratio, which are related to hydrocarbons, were detected by inversion of prestack data. The inversion result shows that the shallower reservoirs have larger anomalies than the deeper (Jurassic) reservoirs. This is in agreement with the provided well data. Finally, using wave equation-based depth extrapolation, a shot record at the well was transformed into a pseudo vertical seismic profile (VSP). The pseudo VSP facilitates an accurate comparison between real VSP data and surface data. Integration of real and pseudo VSP data may provide a new way to predict lateral reservoir variations.

Abstract We developed a linearized inversion scheme in the τ – p domain based on a weighted stack technique , using a modification of an algorithm proposed by Smith and Gidlow (1987). The algorithm assumes that the background velocity model is known and obtains perturbations to the background from the weighted stack. The weights are computed from a linearized approximation of the reflection coefficients. We assume that the background shear-wave velocity follows the mud-rock line, and we use Gardner’s equation to relate density to compressional wave velocity. The inversion results in estimates of fractional changes in compressional wave velocity ( Δα/α ) and shear-wave velocity ( Δβ/β ). Two other factors, pseudo Poisson’s ratio ( ΔQ/Q ) and a fluid factor ( ΔF ), are also calculated by a linear combination of the two perturbation parameters. The fluid factor can be used as a diagnostic for direct detection of hydrocarbons. We first applied the weighted stack technique successfully to synthetic data and tested for the sensitivity of the results to the background velocity. Given the correct background velocity, the algorithm recovers the P -wave and S -wave reflectivities and the fluid factor very well. The results are, however, sensitive to the background velocity model. Then we applied the inversion technique to the Mobil AVO data set. We derived four sections from the data- Δα/α , Δβ/β , ΔQ/Q , and ΔF . The fluid factor profile indicates a hydrocarbon (gas) zone at around 1.97 s which correlates well with the well-log data. We performed the inversion using CMP gathers and assuming a 1-D earth model, and we derived the background velocity by interactively perturbing the velocity model until the reflection events were aligned. We believe that a more sophisticated velocity analysis may help in better resolving lateral continuity of parameters.

Abstract The seismic response of a hydrocarbon zone is determined by several factors, including pore fluid and rock properties, bed geometry, propagation effects, etc. In this study, hydrocarbon and brine densities and compressibilities have been computed based on fluid pressure, temperature and salinity distributions in the study area. For Well A, petrophysical trends derived for shale, wet-sand and gas-sand reveal distinct AVO behavior on the crossplot plane for different interfaced lithologies. For a target zone with averaged bedding thickness less than a seismic wavelength, the effect of "tuning" would tend to distort the modeling results with wider dispersion of points on the AVO crossplot. The preprocessing applied to seismic data prior to AVO analysis are critical to preserving information related to rock and fluid properties. It will be shown that careful application of surface-consistent amplitude corrections, channel balancing, and hyperbolic Radon filtering can significantly improve the quality of the seismic data.