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**Concept Tag**

- Abakaliki (1)
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- acquisition (3)
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**anisotropy (41)**- Artificial Intelligence (3)
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- Reservoir Characterization (39)
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- seismic processing and interpretation (35)
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**File Type**

Reservoir seismic applications require offset domain seismic data to be converted into angles. While it is straightforward to convert offsets to angles under the isotropic assumptions, such a transformation is complex in the presence of anisotropy. Correct interpretation of angle dependent reflection amplitudes requires offset domain data to be corrected for the non-hyperbolic anisotropic moveout and distinction between the phase and the group angles. Some of these fundamental issues relating to the angle dependent P-wave seismic reflections for transversely isotropic elastic medium with a vertical symmetry axis (VTI medium) are reviewed here with illustrations.

amplitude, angle, angle gather, anisotropy, domain, equation, Green River shale, group, group angle, NMO, reflection, Reservoir Characterization, reservoir description and dynamics, seg las vegas, seismic processing and interpretation, slowness, Thomsen, transversely isotropic, Upstream Oil & Gas, vector, VTI

Oilfield Places:

- North America > United States > Wyoming > Green River Basin (0.98)
- North America > United States > Utah > Green River Basin (0.98)

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)

2D parabolic Radon filtering is a widely used method for multiple attenuation. However, for dense and wideazimuth gathers that have azimuthal anisotropy effects this approach can have problems. Because of the variation of the curvature of the events with azimuth, the bin gathers can not be processed in one go but must rather be split into sub-collections where the azimuth either has little variation or varies smoothly. We instead propose herein to take into account the azimuthal anisotropy by incorporating an elliptical model for the variations of the curvature with azimuth, to define a 3D parabolic Radon filtering. This is a more natural way of processing dense wide-azimuth gathers by honoring their actual 3D geometry.

algorithm, anisotropy, azimuth, azimuth sector, azimuthal, azimuthal anisotropy, curvature, elliptical model, gather, geometry, high resolution, las vegas, model space, parabolic radon, Radon domain, Reservoir Characterization, reservoir description and dynamics, sector, seismic processing and interpretation, trace, Upstream Oil & Gas, variation

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.31)

Elastic anisotropy of shale is mainly controlled by the intrinsic anisotropy of individual clay minerals as well as by the textural alignment of grains, pores, and fractures. One of the major challenges in predicting the elastic anisotropy of shales, while using rock physics models, is that the elastic properties of rock-forming clay minerals are poorly known. Since it is impossible to find single and large enough clay crystals for acoustic measurements and ab initio calculations are still incomplete, few data exist on the elastic moduli of clay minerals.

In an attempt to derive the intrinsic anisotropy of pure clay minerals, we present laboratory measurements of compressional and shear wave anisotropy in compacted clay powders at different porosities. In the present work, we focus on the anisotropy of montmorillonitic clays. We used a cold-press method by applying uniaxial compaction in order to obtain compacted mineral aggregates. Different degrees of compaction enable us to obtain samples with variable porosities and crystallite alignments. We measure ultrasonic P- and S- wave velocities along the beddingnormal and the parallel directions. The textural orientation of compacted clay aggregates is found to be controlled by compaction. We obtain the orientation distribution of the clay minerals using synchrotron X-ray diffraction.

Increasing anisotropy of the clay assemblages corresponds to an increase in the preferred orientation of the clay minerals. The combined usage of P- and S- anisotropy measurements with orientation distributions allows us to better constrain the inversion of clay mineral moduli. Our work provides laboratory data on elastic anisotropy of pure clay minerals while linking them to the variation of clay orientation distribution with porosity.

anisotropy, clay, clay mineral, compaction, distribution, elastic anisotropy, elastic property, Epsilon, exponential, formation evaluation, geophysics, intrinsic anisotropy, log analysis, mineral, model, montmorillonite, orientation, porosity, Reservoir Characterization, reservoir description and dynamics, sample, seismic processing and interpretation, shale, stiffness, Thomsen, Upstream Oil & Gas, well logging

Utom, A.U. (Ebonyi State University, Abakaliki, Nigeria.) | Odoh, Ben I. (Ebonyi State University, Abakaliki, Nigeria.) | Ogala, F. (Ebonyi State University, Abakaliki, Nigeria.)

Exploration for groundwater at the College of Agricultural Sciences (CAS) campus of Ebonyi State University in Abakaliki Capital Territory, Nigeria becomes critical where secondary features such as fractures and faults control groundwater movement and occurrence. Intermittent water shortages have developed since the boreholes (resulting from the commonly used Schlumberger array) at the campus have been put to use after well completion. To study the groundwater conditions in details, we used Azimuthal Resistivity Survey to characterize the shale fractures at the campus as part of the research project of merit award to Ebonyi State University Geophysical Society by the SEG Foundation on "potable groundwater exploration in Abakaliki shale Formation". Measured apparent resistivities changed with the orientation of the fractures. Graphical interpretation of the survey data indicates that the fractures trend generally in the northwestsoutheast direction at the depths of 28.3, 40.0 and 50.0 m with the coefficient of anisotropy ranging from 1.36 to 1.55 with the higher anisotropy factor indicating area of higher permeability. The applied square array is more sensitive to a given rock anisotropy than the more commonly used Schlumberger and Wenner arrays.Generally, an additional advantage of the array technique used is that it requires about 65 percent less surface area than an equivalent survey using a Schlumberger or Wenner array.

Abakaliki, anisotropy, apparent resistivity, array, azimuthal resistivity survey, campus, complex reservoir, drilling data acquisition, drilling measurement, Ebonyi State University, fracture, fracture system, hydraulic fracturing, knowledge management, logging while drilling, LWD, management and information, Nigeria, Reservoir Characterization, reservoir description and dynamics, resistivity, shale, structural geology, Upstream Oil & Gas, well completion

The past couple of years have seen a tremendous increase in the acquisition of wide azimuth (WAZ) surveys that provide improved subsalt imaging. We have seen a step change improvement in image quality compared to conventional narrow azimuth (NAZ) surveys, even when using minimal processing and existing, conventional-survey velocity models. The improvement in image quality is taken to the next level when the wide and rich azimuth data are combined with other seismic and non-seismic measurements to build ever more highly constrained models, and then more accurately migrated with two-way wave-equation methods.

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)

Over the past decade, the majority of deep water blocks in the Gulf of Mexico have been covered multiple times with seismic data from narrow-azimuth, towed-streamer acquisition (NAZ). In complex subsalt areas, each NAZ dataset provides unique subsurface illumination benefits. Multiple-azimuth data are now frequently integrated to provide extended subsurface coverage and for better imaging of complex subsalt structures. Multiple-azimuth seismic data, with shot and receiver locations covering a large portion of the two dimensional surface, presents a new challenge for deriving a single velocity model that satisfies both datasets.

Velocity variation with azimuth is observed in an orthogonal dual-azimuth streamer dataset in Deep Water Gulf of Mexico. This paper presents the benefit of tilted transversely isotropic (TTI) tomography to yield an anisotropy model that flattens gathers for all azimuths as well as improves focusing and spatial positioning of steeply-dipping salt flanks.

anisotropy, azimuth, basin, cig gather, dataset, dual azimuth, ew survey, gather, Imaging, las vegas, migration, model, Reservoir Characterization, reservoir description and dynamics, salt flank, seismic processing and interpretation, semblance, survey, tomography, TTI tomography, Upstream Oil & Gas

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)

**Summary**

Shear-wave seismic acquired at Rulison Field, Piceance basin, Colorado in 2003 exhibits evidence of faults and natural fractures from reflection discontinuity and shearwave splitting analysis. Rulison Field is a thick unconventional natural gas reservoir producing from the fluvial tight gas sandstones of the Late Cretaceous Williams Fork Formation.

Fault interpretations made from multicomponent seismic data clearly show near vertical faults in the lower reservoir Cameo Coal interval that strike in a north-northwest direction. The shear-wave (s-wave) seismic shows better evidence of faults propagating upward through the main reservoir interval than the p-wave. Borehole image logs confirmed these faults. These faults splay upward into the reservoir as flower structures that create fault zones and control natural fracturing within the reservoir. Natural fractures were observed from s-wave splitting. Since the reservoir is more than a wavelength thick, s-wave splitting calculations were done on seismic volumes as opposed to the traditional horizon-based approach. This process resulted in s-wave splitting volumes that correlate with image log fracture interpretations and anisotropy logs from cross-dipole sonic logs. These volumes show spatial and vertical variations in the degree of s-wave splitting that are geologically and can ultimately be used to optimize well locations and drilling efficiency.

anisotropy, anisotropy log, Colorado, difference, fault, high eur well, high impedance anisotropy, impedance, impedance anisotropy, multicomponent seismic, natural fracture, natural fracture identification, research, Reservoir Characterization, reservoir description and dynamics, Rulison Field, s-wave splitting, seismic processing and interpretation, similarity, Upstream Oil & Gas, well

Oilfield Places:

An inversion procedure is described wherein microseismic data recorded by a network of three component geophones are assumed to be represented as the sum of a compressional (P) and one or two shear (S) arrivals. The inversion operates in the frequency-space domain and includes a linear inversion for source waveforms and a nonlinear inversion for model properties or source locations. The linear inversion effectively reverses time using a ray trace Green function to recover the source-time functions. For the nonlinear inversion two waveform fitting functionals are constructed; one captures moveout and polarization information through a reconstructed data misfit, another captures information from arrival time differences through a spectral coherence functional. The two may be scaled and summed to form a joint X2 misfit which may be combined with soft prior information in a Bayesian posterior. This is then maximized using global search techniques. Model calibration is accomplished by inverting waveform data from known locations (e.g. perforation shots) for anisotropy and optionally for model smoothness and Q. Micro-earthquake event locations are determined by inverting waveform data given the calibrated model.

Since the procedure involves fitting waveforms, time picking is not required. The beam-forming property of the receiver array and the complete polarization vector are used to enhance the signal to noise ratio of arrivals. The presence of a P arrival is not necessary to determine a location. The algorithm implementation uses layered VTI models, includes losses due to spreading, transmission and Q and handles an arbitrary distribution of receivers (e.g. from horizontal or multiple wells or surface locations). The inversion permits automated, objective data analysis with quantified uncertainties in estimated unknowns.

amplitude, anisotropy, approach, arrival, Artificial Intelligence, frequency, function, information, inversion, least-squares time reversal, location, model, objective function, posterior, receiver, Reservoir Characterization, reservoir description and dynamics, seismic processing and interpretation, source, source function, source location, Upstream Oil & Gas, waveform, waveform fitting

Technology: Information Technology > Artificial Intelligence > Representation & Reasoning > Search (0.34)

Elliptical anisotropy or lateral velocity variations can cause azimuthal variations in moveout velocity. In cases where apparent elliptically anisotropic moveout is present, a single picked velocity is inadequate to flatten an event on a 3-D CMP gather. We propose a velocity-independent imaging approach to perform an elliptically anisotropic moveout correction in 3- D. The velocity-independent approach relies on locally measured traveltime slopes rather than aggregate velocities to flatten each event and is very well suited to azimuthally variable corrections. We derive the velocity-independent elliptically anisotropic moveout equation for the 3-D case. We also derive expressions for extracting velocity and the angle between the symmetry and acquisition axes. Tests on synthetic and real data validate the proposed method.

Common physical occurrences such as dipping interfaces, lateral velocity variations, or HTI media can lead to apparent azimuthal anisotropy (Grechka and Tsvankin, 1998), in which case the P-wave moveout velocity is elliptically dependent on azimuth. The symmetry axes of apparent elliptic anisotropy often correspond to geologically meaningful parameters such as the strike and dip directions of the reflector (Levin, 1985), or in the HTI case, the preferred orientation of vertical fractures (Crampin, 1984). Failure to account for azimuthal velocity variations often leads to stack degradation, improper time-todepth conversion, inaccurate AVO/AVOA, and overall poorer image results (Williams and Jenner, 2002).

The concept of velocity-independent imaging (Ottolini, 1983) is attractive because it can significantly decrease the time and manual work required to process a seismic data set (Fomel, 2007). The underlying strategy of velocity-independent imaging relies on measuring traveltime slopes throughout the data set rather than velocities themselves (Wolf et al., 2004). Fomel (2002) demonstrates that plane-wave destruction filters provide an automated and effective way to measure local slopes in a seismic volume, which can then be used to automate any common time-domain imaging step (Fomel, 2007). Previous work concerning automatic moveout corrections does not extend to the 3-D case. In doing so here, we demonstrate that the azimuthal flexibility of automatic moveout correction in 3- D is especially useful in the presence of apparent azimuthal anisotropy.

Rather than using a single picked velocity to apply the NMO correction, using the local slopes of a given 3-D reflection event allows the event to be flattened regardless of azimuthal variations inNMOvelocity. The velocity-independent approach can still be used to extract moveout or interval velocities throughout the data set as data attributes (Fomel, 2007). The proposed method here also suggests that by measuring local curvatures throughout the seismic data volume, the orientation of the symmetry axes can automatically be estimated with respect to the acquisition coordinates.

Equation (1) describes NMO with elliptical velocity, where the third parameter with units of slownesssquared, Wxy, arises from observing the ellipse from rotated coordinates. In practice, one can still perform elliptically anisotropic NMO using conventional velocity picking in the in-line and cross-line directions, butWxy must also be estimated. Rewriting equation (1) as a matrix-vector multiplication allows one to solve for the angle between the acquisition coordinates and the medium symmetry axes, denoted as a here.

In this complex structure land imaging case history, we observed lateral positioning differences beneath the dipping anisotropic overburden of about 120 m between the isotropic prestack time migration (PSTM) imaging and the anisotropic prestack depth migration (PSDM) imaging. After migrating the anisotropic PSDM with different velocity and anisotropy models, we estimated the lateral positioning uncertainty in the anisotropic depth image. In the area where we observed the largest positioning differences with the PSTM, we estimated the uncertainty due to anisotropy to be of the order of 30 m, and the uncertainty due to velocity to be of the order of 15 m. As the dip of the overburden decreased, the lateral positioning differences between the isotropic PSTM and the anisotropic PSDM decreased, as did the lateral positioning uncertainty of the anisotropic PSDM imaging.

anisotropic depth migration, anisotropy, anisotropy model, Case History, Comparison, field, gather, Imaging, lateral positioning, lateral positioning difference, migration, model, overburden, positioning, Reservoir Characterization, reservoir description and dynamics, seismic processing and interpretation, thrust belt case history, Upstream Oil & Gas, well

Thank you!