Full-azimuth Seismic Data Research Articles

Horizontal Transverse Isotropy Studied Using Tools for Full-Azimuth Seismic Data Processing and an Advanced Well Logging Complex on the Example of Famennian Deposits of the Yugomashevskoye Field

Abstract —This paper presents a solution to the problem of searching for cavernous fractured zones and the zones that determine reservoir heterogeneity in Famennian deposits of one of the licensed sections of the Republic of Bashkortostan. The use of an integrated approach to the study of azimuthal horizontal-transverse isotropy of rocks using wellbore data and modern methods for processing areal seismic data for carbonate deposits associated with the development of organogenic structures is described. The results of using the full-azimuth angular migration technology are obtained. The introduction of high-tech approaches at the research site using full-azimuth seismic data processing, spectral decomposition, AVA/AVAZ inversion, and complex analysis of dynamic properties of the wave field in conjunction with well logging and core data makes it possible to identify the distorted zones of the carbonate reservoir associated with changes in the characteristics of the rock skeleton, the presence of a porous-cavernous-fracture void space and lithological replacement zones, as well as secondary processes, thereby reducing the risks associated with subsequent production drilling.

A multi-level parallel algorithm for seismic imaging based on one-way wave equation migration

This article presents a parallel algorithm for seismic imaging based on depth wavefield extrapolation (the solution of a one-way wave equation [OWE]) employing the pseudospectral method. The algorithm is essentially oriented on common-offset vector (COV) gathers seismic migration based on an OWE, includes several parallelism levels, and utilizes message passing interface (MPI), Nested OpenMP, and CUDA technologies. The uppermost level of parallelism involves data splitting to ensure that each dataset can be processed independently to construct parts of the COV images. The algorithm is embarrassingly parallel at this level. Next, each independent run processes several datasets to compute COV images. Each MPI process computes all COV images for a single dataset, then MPI processes exchange data to build up a single COV image for all datasets at a single node. Computation of the COV image at a node requires OpenMP parallelization so that one thread governs the GPU-based calculations and facilitates the construction of images within a thick slab. All other threads perform image interpolation within the slab. Finally, CUDA technology is used for the most computationally intense part of the algorithm—wavefield extrapolation. Such a complex algorithm structure makes it possible to process all COV images for full-azimuth seismic data employing OWE-based migration.

Azimuthal anisotropy analysis applied to naturally fractured unconventional reservoirs: A Barnett Shale example

Studying the seismic responses of velocity and amplitude on wide-/full-azimuth seismic data is now common for unconventional reservoir characterization. Velocity variation with azimuth (VVAz) and amplitude variation with azimuth (AVAz) are two of the most popular tools to map not only the relative intensity and orientation of natural fractures but also the strength and orientation of the maximum horizontal stress SH. We prestack time migrated a wide-azimuth Barnett Shale survey in North Texas into eight azimuths and reduced noise on the gathers using prestack structure-oriented filtering. We then computed the envelope, spectral peak frequency, and prestack P-wave impedance attributes for each azimuthally limited seismic volume. We compensated the VVAz effects by flattening each sector along the Barnett Shale key horizons, thereby registering the gathers for subsequent AVAz analysis. The results indicate the intensity, orientation, and confidence of azimuthal anisotropy effects on seismic velocity and amplitude, which can be referred to smaller scale vertical cracks or natural fractures. Our analysis reveals four zones of high anisotropy intensity that can be tied to either the regional structures or paleo stress field. Analysis of production data indicate from the anisotropy interpretation results that vertical, sealed fractures are the dominant cause of anisotropy and those specific fractures inhibit production. This observation and results indicate that horizon-based azimuthal anisotropy analysis avoids the VVAz effect and can be applied to fractures and regional stress field prediction.

Using Multiazimuth Seismic Data for Anisotropy Estimation in an Unconventional Reservoir

Productivity of a well in an unconventional reservoir is governed by various static and dynamic reservoir characteristics. Many of these characteristics have proxies among pre and post stack seismic attributes that can be derived from Multiazimuth 3D Seismic Data. The task of a geoscientist in this kind of reservoir is to understand these proxies to predict production behaviour. Natural fracture density and azimuth, as well as horizontal stress azimuth are the key attributes that seismic can help predict. Seismic Velocity and Amplitude variations with azimuth can be used to predict fracture strike, relative fracture density and define potential structural sweet spots. Azimuthal data from a Multiazimuth 3D seismic survey in the Nappamerri Trough of Cooper Basin has been interpreted to estimate fracture intensity and orientation. Co-rendered structural maps are used to create stress maps for different interval of interest. Stress maps help to identify areas of higher anisotropy and areas of lower minimum horizontal stress and so facilitate optimised well placement. To test the geological significance of these maps, correlation of stress vectors against well Image log and cross dipole sonic data was completed. This ground truth validates the prediction of direction and distribution of reservoir fractures based on full azimuth seismic data in this area.

Seismic data conditioning and orthotropic rock-physics-based inversion of wide-azimuth P-wave seismic data for fracture and total organic carbon characterization in a north Kuwait unconventional reservoir

Optimization of production from unconventional reservoirs requires estimates of reservoir properties such as porosity, total organic carbon (TOC) content, clay content, fluid saturation, and fracture intensity. The porosity and TOC content help to determine reservoir quality, and the natural fracture intensity provides information important for the completion strategy. Because shale reservoirs display intrinsic anisotropy due to layering and the partial alignment of clay minerals and kerogen with the bedding plane, the minimum acceptable representation of the anisotropy of naturally fractured shale-gas reservoirs is orthotropy, in which a set of vertical compliant fractures is embedded in a vertical transverse isotropic (VTI) background medium. Full-azimuth seismic data are required to characterize such reservoirs and to invert for the anisotropic elastic properties. Orthotropic inversion uses azimuthally sectored seismic data stacked according to the incident angle. Even for high-fold acquisition, this azimuth/angle grouping can result in low-fold angle stacks. Orthotropic amplitude-variation-with-offset-and-azimuth (AVOAz) inversion requires seismic preconditioning techniques that ensure proper primary amplitude preservation, noise attenuation, and data alignment, and a workflow implemented for the construction of an orthotropic rock-physics model. This model integrates well and core data to estimate reservoir properties using the results of the AVOAz inversion. The seismic inversion results include the P- and S-impedance and parameters quantifying the azimuthal anisotropy. The rock model assumes a VTI kerogen-rich layer, containing aligned vertical fractures, and it uses prestack orthotropic AVOAz inversion results to predict porosity, TOC, and fracture intensity.

Seismic attribute analysis for fracture detection and porosity prediction: A case study from tight volcanic reservoirs, Barmer Basin, India

The Raageshwari Deep Gas Field is situated in the southern part of the onshore Barmer Basin in Rajasthan, India. The field contains gas condensate with excellent gas quality reservoired dominantly within the tight volcanic rocks. Optimal development and production of the tight reservoirs requires characterization of faults and natural fractures that are important to fluid flow and production. Reservoir quality of the volcanic complex is governed by the distribution of matrix pore spaces and fractures. Use of seismic attributes for detecting effective reservoir pore spaces such as fractured zones and vesicles is challenging considering the limits of seismic resolution in the tight volcanic reservoirs. Poststack seismic attributes used in this study for fracture detection include geometric attributes such as coherency for detection of seismically resolved faults and reflection curvature attributes for discrimination of subseismic faults. Discrete frequency components extracted from seismic data are also used to analyze geologic discontinuities. Besides geometric attributes, seismic wave attenuation from the basic instantaneous seismic attributes — instantaneous amplitude, phase, and frequency — are also key indicators of fractured zones and vesicles that create effective pore spaces. In fractured intervals within the volcanic reservoirs, a decrease in density and slowdown in acoustic propagation velocity yields a relative drop in P-wave impedance, which are important characteristics to determine fractured zones. Detected fractured zones from seismic attributes were validated with wells, image logs, and production data. In addition to fracture detection, predicting subsurface properties, such as porosity distribution away from wells, has always been a fundamental requisite for appropriate infill well planning. Full-azimuth seismic data and selected seismic attributes were used in multiattribute analysis to predict porosity and were correlated with “blind” wells. This study captures the heterogeneous volcanic rock porosity distribution in the field, improving the understanding of varied production behavior observed within the volcanic rock complex.

Multiazimuth coherence

Since its introduction two decades ago, coherence has been widely used to map structural and stratigraphic discontinuities such as faults, cracks, karst collapse features, channels, stratigraphic edges, and unconformities. With the intent to map azimuthal variations of horizontal stress as well as to improve the signal-to-noise ratio of unconventional resource plays, wide-/full-azimuth seismic data acquisition has become common. Migrating seismic traces into different azimuthal bins costs no more than migrating them into one bin. If the velocity anisotropy is not taken into account by the migration algorithm, subtle discontinuities and some major faults may exhibit lateral shifts, resulting in a smeared image after stacking. Based on these two issues, we evaluate a new way to compute the coherence for azimuthally limited data volumes. Like multispectral coherence, we modify the covariance matrix to be the sum of the covariance matrices, each of which belongs to an azimuthally limited volume, and then we use the summed covariance matrix to compute the coherent energy. We validate the effectiveness of our multiazimuth coherence by applying it to two seismic surveys acquired over the Fort Worth Basin, Texas. Not surprisingly, multiazimuth coherence exhibits less incoherent noise than coherence computed from azimuthally limited amplitude volumes. If the data have been migrated using an azimuthally variable velocity, multiazimuth coherence exhibits higher lateral resolution than that computed from the stacked data. In contrast, if the data have not been migrated using an appropriate azimuthally variable velocity model, the misalignment of each image results in a blurring of the multiazimuth coherence and the coherence computed from the stacked data. This suggests that our method may serve as a future tool for azimuthal velocity analysis.

Large-scale complex physical modeling and precision analysis

Large-scale 3D physical models of complex structures can be used to simulate hydrocarbon exploration areas. The high-fidelity simulation of actual structures poses challenges to model building and quality control. Such models can be used to collect wideazimuth, multi-azimuth, and full-azimuth seismic data that can be used to verify various 3D processing and interpretation methods. Faced with nonideal imaging problems owing to the extensive complex surface conditions and subsurface structures in the oil-rich foreland basins of western China, we designed and built the KS physical model based on the complex subsurface structure. This is the largest and most complex 3D physical model built to date. The physical modeling technology advancements mainly involve 1) the model design method, 2) the model casting flow, and 3) data acquisition. A 3D velocity model of the physical model was obtained for the first time, and the model building precision was quantitatively analyzed. The absolute error was less than 3 mm, which satisfies the experimental requirements. The 3D velocity model obtained from 3D measurements of the model layers is the basis for testing various imaging methods. Furthermore, the model is considered a standard in seismic physical modeling technology.