A new technique has been developed which makes it possible to process a seismic record‐section in such a way that all seismic events with dips in a given range are preserved with no alteration over a wide frequency band, while all seismic events with dips outside the specified range are uniformly and severely attenuated. By applying this process to a noisy record‐section, a record‐section may be obtained which has all events within a specified dip range perfectly preserved, and very high‐velocity noise essentially eliminated, a result which is impossible by simple wave‐number filtering or conventional array usage. In structurally complex areas where several steeply dipping events interfere, the technique may be applied to separate the events with different dips. In areas where a normal‐moveout contrast exists between primaries and multiples, the technique may be used for wide‐band multiple attenuation. By application of a “rotating Pie‐Slice” to micro‐spread noise data, seismic noise may be separated on the basis of propagation velocity, and a clearer picture of the seismic noise problem obtained. The “rotating Pie‐Slice” also provides a means of uncovering diffractions and other steeply‐curved events from a record section. The paper discusses the motivation and implementation of the process and its application to both synthetic and actual data.
In offshore shooting the validity of previously recorded seismic data has been severely limited by multiple reflections within the water layer. The magnitude of this problem is dependent on the thickness and the nature of the boundaries of the water layer. The effect of the water layer is treated as a linear filtering mechanism, and it is suggested that most apparent water reverberation records probably contain some approximate subsurface structural information, even in their present form. The use of inverse filtering techniques for the removal or attenuation of the water reverberation effect is discussed. Examples show the application of the technique to conventional magnetically recorded offshore data. It has been found that the effectiveness of the method is strongly dependent on the instrumental parameters used in the recording of the original data.
Two‐dimensional, fenced 2-D, and 3-D isosurface displays of some realistic 3-D seismic models built in the lower Miocene Powderhorn Field, Calhoun County, Texas, demonstrate that a seismic event does not necessarily follow an impedance boundary defined by a geological time surface. Instead, the position of a filtered impedance boundary relative to the geological time surface may vary with seismic frequency because of inadequate resolution of seismic data and to the en echelon or ramp arrangement of impedance anomalies of sandstone. Except for some relatively time‐parallel seismic events, the correlation error of event picking is large enough to distort or even miss the majority of the target zone on stratal slices. In some cases, reflections from sandstone bodies in different depositional units interfere to form a single event and, in one instance, an event tying as many as six depositional units (interbedded sandy and shaly layers) over 50 m was observed. Frequency independence is a necessary condition for selecting time‐parallel reference events. Instead of event picking, phantom mapping between such reference events is a better technique for picking stratal slices, making it possible to map detailed depositional facies within reservoir sequences routinely and reliably from 3-D seismic data.
The locally converted shear wave is often neglected in ray‐trace modeling when reproduction of the AVO response of potential hydrocarbon reservoirs is attempted. Primaries‐only ray‐trace modeling in which the Zoeppritz equations describe the reflection amplitudes is most common. The locally converted shear waves, however, often have a first‐order effect on the seismic response. This fact does not appear to be widely recognized, or else the implications are not well understood. Primaries‐only Zoeppritz modeling can be very misleading. Interference between the converted waves and the primary reflections from the base of the layers becomes increasingly important as layer thicknesses decrease. This interference often produces a seismogram that is very different from one produced under the primaries‐only Zoeppritz assumption. For primaries‐only modeling of thin layers, synthetic seismograms obtained by use of a linearized approximation to the Zoeppritz equations to describe the reflection coefficients are more accurate than those obtained by use of the exact Zoeppritz reflection coefficients. A real‐data example consisting of an assemblage of very thin layers has recently been discussed in the literature. Inferences as to the true earth properties based on the predicted amplitude variation with offset are in error because the primaries‐only assumption is invalid. For one of the models, primaries‐only modeling predicts an amplitude increase of approximately a factor of three from the near trace to the far trace. Reflectivity modeling predicts an amplitude decrease with offset. The O’Doherty‐Anstey effect suggests that transmission loss for primary reflections should not be included in normal‐incidence synthetic seismograms if the short‐period reverberations are not also included. The same principle holds for prestack modeling. Similarly, the Zoeppritz equations should not be used for synthetic seismograms without including the locally converted shear wave.
A practical approach to linear prestack seismic inversion in the context of a locally 1-D earth is employed to use amplitude variation with offset (AVO) information for the direct detection in hydrocarbons. The inversion is based on the three‐term linearized approximation to the Zoeppritz equations. The normal‐incidence compressional‐wave reflection coefficient [Formula: see text] models the background reflectivity in the absence of hydrocarbons and incorporates the mudrock curve and Gardner’s equation. Prediction‐error parameters, [Formula: see text] and [Formula: see text], represent perturbations in the normal‐incidence shear‐wave reflection coefficient and the density contribution to the normal incidence reflectivity, respectively, from that predicted by the mudrock curve and Gardner’s equation. This prediction‐error approach can detect hydrocarbons in the absence of an overall increase in AVO, and in the absence of bright spots, as expected in theory. Linear inversion is applied to a portion of a young, Tertiary, shallow‐marine data set that contains known hydrocarbon accumulations. Prestack data are in the form of angle stack, or constant offset‐to‐depth ratio, gathers. Prestack synthetic seismograms are obtained by primaries‐only ray tracing using the linearized approximation to the Zoeppritz equations to model the reflection amplitudes. Where the a priori assumptions hold, the data are reproduced with a single parameter [Formula: see text]. Hydrocarbons are detected as low impedance relative to the surrounding shales and the downdip brine‐filled reservoir on [Formula: see text], also as positive perturbations (opposite polarity relative to [Formula: see text]) on [Formula: see text] and [Formula: see text]. The maximum perturbation in [Formula: see text] from the normal‐incidence shear‐wave reflection coefficient predicted by the a priori assumptions is 0.08. Hydrocarbon detection is achieved, although the overall seismic response of a gas‐filled thin layer shows a decrease in amplitude with offset (angle). The angle‐stack data (70 prestack ensembles, 0.504–1.936 s time range) are reproduced with a data residual that is 7 dB down. Reflectivity‐based prestack seismograms properly model a gas/water contact as a strong increase in AVO and a gas‐filled thin layer as a decrease in AVO.
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