The proposed MultiFocusing based multiple attenuation procedure is valid for surface-related as well as for interbed types of multiples. It is robust and simple. It is easy to implement and it can predict all kinds of multiples defined by the picked corridors in the MF domain. The multiple suppression approach with MF attributes is not dependent on the regularity of the data.
The new algorithm of 3D diffraction imaging is based on a MultiFocusing methodology and consists of optimal summation of seismic data in accordance with a diffraction-moveout formula. The diffraction-oriented stacked sections can be used for reliable interpretation of non-smoothed geological interfaces and for identification of local heterogeneities such as faults, karsts, fractures etc.
Common-offset MultiFocusing can be considered as a method for full prestack wavefield analysis and imaging.
The method is based on a local MultiFocusing approximation for locally coherent seismic events and allows, for each trace and each time sample, an accurate estimation of the wavefield parameters (such as local wavefront curvatures, geometrical spreading and emergence angles in shot and receiver domains).
The MultiFocusing method not only provides coherent stacking of seismic data with arbitrary source-receiver distribution to create high-quality time images, but it also has the potential to compute enhanced prestack seismic traces. This method uses a new MF move-out correction formula for approximation of the local moveout correction and is based on partial stacks along optimal travel-time trajectories.
Multifocusing, as a non-CMP based imaging method, opens a new perspective for optimal approximation of the zero-offset sections.Stacked sections obtained by the MultiFocusing method are superior to those obtained by the conventional DMO/NMO processing: they are characterized by higher signal-to-noise ratio and better approximate the actual zero-offset sections. Parameters (wavefield attributes) estimated by the MultiFocusing method have clear geophysical interpretation and can be used for several important applications such as velocity model building, migration, structural and stratigraphic interpretation.
The MultiFocusing method consists of stacking seismic data with arbitrary source-receiver distribution according to a new moveout correction formula. The MF travel-time curve provides a better approximation of actual reflection travel-time than the standard hyperbolic one. In particular, MF is very effective for processing and reprocessing low-fold CMP data due to MF’s noise suppression wavefield. Parameters obtained by the multifocusing method can be used for velocity model estimation and for time and depth migrations.
MultiFocusing diffraction imaging propose a new technique for detecting local subsurface heterogeneities using diffraction MultiFocusing stack. The imaging is based on a new type of local time correction for diffraction travel-time curve parametrization. The DMFS method consists of optimal stacking of seismic data along actual diffraction traveltime curves. The stacking procedure produces a section in which diffractions are emphasized and specular reflections are illuminated. The diffraction MultiFocusing stacks can be used for reliable interpretation of nonsmoothed geologic interfaces and for identification of local heterogeneities such as faults, karsts, and fractures.
The integrated interpretation of well log data and seismic data processed by the new MultiFocusing technology allowed the revision of the identification of unconformity markers and internal structural details in the northern part of the Russkoye field. Facies of marine origin (clays), slope deposits (shales), as well as shelf and deltaic sands were identified with more certainty using seismic reflections and based stratigraphic sequences, determined from the log data (together with core studies).
MultiFocusing method consists of stacking seismic data with arbitrary source-receiver distribution according to a new moveout correction formula. The method is not dependent on the geological section model and consists of stacking seismic data with arbitrary source-receiver distribution near the central points. A higher SNR, due to the summation of a greater number of traces and the absence of stretch effect, delivers a significant increase in the signal-to-noise ratio for both deep and shallow reflections.
This article explains a method of predicting the timing and moveout of a multiple so that its location in the t-r domain can be identified. If the t-r location of a given multiple is known, it can be attenuated. It is an interactive target-oriented “predict and subtract” attenuation method, whose objective is to remove multiples of any type (free surface, peg-leg, and interbed) .
This is a new 2-D method for attenuation of both surface-related and interbed multiples in the parabolic ø-p domain. It is a combination of the prediction method based on wavefront characteristics of multiple generating primary reflections and the Radon transform–based method for multiple subtraction. The multiple reject areas are determined automatically by zeroing the multiple ellipse in the ø-p domain, or by comparing the energy on the traces of the multiple model and the original input data in the ø-p domain.
The MultiFocusing method consists in stacking seismic data with arbitrary source–receiver distribution according to a new MultiFocusing moveout correction. This method can produce a zero offset section superior to the NMO/DMO stacked section in an automatic manner. The method is particularly useful in situations of low fold and/or low signal-to-noise ratio.
Unconventional reservoirs have a unique set of problems. Most production wells are drilled horizontally through the reservoir rock and hydraulic fracturing is applied to increase permeability in the reservoir. The pre-drilling knowledge of natural fracture corridors and small offset faults is very important in this case. Seismic resolution from conventional reflection imaging is generally not sufficient to resolve such small scale rock properties. Diffracted waves are events generated by small scale subsurface heterogeneities and discontinuities (including fractures). Detection and imaging the diffractive component of the total wavefield opens a new perspective to find and characterize fracture zones in carbonate environment.
The MultiFocusing imaging technology is able to describe not only reflection but also diffraction events from conventionally acquired seismic data and is performed in the pre-stack domain. By optimally summing diffracted events and attenuating specular reflections, an image that contains mostly diffraction energy is being generated. Synthetic and seismic studies are indicating a direct relationship between fracture density and intensity of the diffractivity. This phenomenon is being exploited to use seismic to directly map zones within unconventional/tight reservoirs that are naturally fractured. The MultiFocusing diffraction imaging methodology makes it possible to extract the weak diffractive element from the overall wave field and suppresses the strong specular events.
The generalized approach of the MF method of moveout correction allows processing of data acquired with irregular acquisition design and is very useful in cases where the subsurface is highly complicated.
The core of the Multi-Focusing stacking, based on paraxial approximation and dynamic ray tracing, is its Fresnel-zone basis for defining the large number of traces used in the stacking procedure. The resulting traces have a more densely sampled source-receiver distribution about each output location which allows the output dataset to be easily regularized.
The MF method not only provides coherent stacking of seismic data with arbitrary source-receiver distribution, creating high-quality time images, but also yields enhanced and regularized prestack gathers. In areas where acquiring aregular 3D dataset is impossible due to difficult terrain or high
population density, conventional gathering and stacking often results in shallow gaps in coverage. Stacking these regularized,enhanced gathers can often ‘heal’ these gaps in coverage.
The interpretation of faulted systems is an essential step in E&P business, from a proper understanding of
prospects to optimal development well placements. The identification of fractured zones within a reservoir,
usually characterized by sub-seismic faults, is often neglected, while it can add significant value to the
development of a project. The present case study is focused on the very prolific Algerian Ordovician tight
reservoir target. It highlights a structure at the end of an appraisal well campaign, where an integrated fracture
reservoir study had been performed in order to track efficiently subtle fault corridors.
The utilization of advanced seismic attributes using the MultiFocusing technique has proven valuable when
determining the detection and extension of fracture corridors within the reservoir. At the well locations, results
matched reasonably well with the fracture orientation and density interpreted from cores, borehole images and
DST interpretations. This approach has a great value when planning well trajectories, for production predictions,
and eventually for locating any future development wells in the area.
Kinematic wavefront characteristics of primary reflected waves can be used to predict and attenuate surface-, as well as interbed multiples. In order to estimate kinematic wavefront characteristics directly from unstacked data the common-shot-point homeomorphic-imaging CSP HI. method can be applied. This macro-model-independent method is based on a new local moveout correction that depends on two wavefront parameters: the emergence angle and the radius of wavefront curvature of a reflected primary wavefront. These parameters can be estimated by optimizing the semblance correlation measure, calculated in the common-shot-gather along the travel time curve defined by the new moveout correction. In the case of local maxima in the semblance functional, an automatic maximization procedure might lead to a wrong estimation of these parameters. In order to avoid such a situation, we propose an interactive, horizon-based implementation of the CSP HI method, which allows manual picking of the optimal wavefront parameters along the seismic line. Afterwards, we use the estimated emergence angles for the prediction and attenuation of multiples, based on the simple but powerful idea that any multiple event can be represented as a combination of primaries.