Interpreter's Corner

Global empirical relationships of P-wave to S-wave and density for sandstones and shales are used to model two-term amplitude variation with angle at various depths of burial in a typically compacting siliciclastic basin. Data from the normally pressured Tertiary strata of Judd Basin, Atlantic Margin, West of Shetland, are used as a control. For a typical prospect depth of 1750 m below mudline, forward models of angle-dependent reflectivity reveal that discrimination of lithology (shale and brine sand) and fluid (oil sand) is optimally resolved at a 47° incidence angle (θ). This is equivalent to an angle of 28° on an intercept-gradient crossplot. Repeat experiments at other depths produce similar results but with the angle for optimal lithology and fluid determination shifting slightly with increasing depth. Background trends in seismic data crossplots of intercept versus gradient are typically overprinted by noise that has a disproportionate effect on the gradient. This study suggests that the difference between the noise and background rock-property trend is relatively small, such that in most modern seismic data sets, anomalies should be identifiable on time-windowed crossplots and equivalent weighted stacks. It is proposed that a seismic inversion for relative extended elastic impedance at a 45° incidence angle should capture most anomalies of interest in frontier basins with simple burial histories. An example is illustrated from a seismic line in Mozambique.

Least-squares inversion-based elastic reverse time migration with PP- and PS-angle-domain common-imaging gathers

Elastic angle-domain common-imaging gathers (ADCIGs) extracted from elastic reverse time migration (ERTM) play a pivotal part in elastic migration velocity analysis, elastic amplitude variation with angle, and attribute interpretation. In practice, however, elastic ADCIGs often suffer from unbalanced amplitude behavior, poor resolution, and low-wavenumber artifacts because of insufficient velocity information, limited recording aperture, uneven illumination, and other inaccuracies of the migration operator. We have developed a new method to improve the quality of elastic ADCIGs extracted from ERTM by posing ERTM imaging as an inverse problem whose misfit function measures the difference between simulated and observed data. The misfit function can be minimized by updating elastic offset-domain common-imaging gathers (ODCIGs) using an optimization method. Based on the transformation between ADCIGs and ODCIGs, the forward operator generates multicomponent seismic data from elastic ODCIGs by applying a scattering condition, and the adjoint operator generates elastic ODCIGs from ERTM using a subsurface space-shift imaging condition. Compared with elastic ODCIGs extracted from ERTM, our method effectively improves the focusing of elastic ODCIGs to produce elastic ADCIGs with higher resolution, fewer artifacts, and improved amplitude coherency across different reflection angles. Several synthetic examples were used to validate the effectiveness of the method.

Model parameterization and amplitude variation with angle and azimuthal inversion in orthotropic media

Horizontal layered formations with a suite of vertical or near-vertical fractures are usually assumed to be an approximate orthotropic medium and are more suitable for estimating fracture properties with wide-azimuth prestack seismic data in shale reservoirs. However, the small contribution of anisotropic parameters to the reflection coefficients highly reduces the stability of anisotropic parameter estimation by using seismic inversion approaches. Therefore, a novel model parameterization approach for the reflectivity and a pragmatic inversion method are proposed to enhance the stability of the inversion for orthotropic media. Previous attempts to characterize orthotropic media properties required using four or five independent parameters. However, we have derived a novel formulation that reduces the number of parameters to three. The inversion process is better conditioned with fewer degrees of freedom. An accuracy comparison of our formula with the previous ones indicates that our approach is sufficiently precise for reasonable parameter estimation. Furthermore, a Bayesian inversion method is developed that uses the amplitude variation with angle and azimuth (AVAZ) of the seismic data. Smooth background constraints reduce the similarity between the inversion result and the initial model, thereby reducing the sensitivity of the initial model to the inversion result. Cauchy and Gaussian probability distributions are used as prior constraints on the model parameters and the likelihood function, respectively. These ensure that the results are within the range of plausibility. Synthetic examples demonstrate that the adopted orthotropic AVAZ inversion method is feasible for estimating the anisotropic parameters even with moderate noise. The field data example illustrates the inversion robustness and stability of the adopted method in a fractured reservoir with a single well control.

Azimuthal P-P prestack amplitudes in the presence of oil-filled aligned porosity (fracture porosity)

A 3D P-P high-fold full-azimuth full-offset reflection survey was acquired and processed to characterize a naturally fractured carbonate reservoir. The reservoir is a thick carbonate, which will flow commercial oil with a sufficient fracture network. Extensive calibration data include (1) a horizontal borehole’s resistivity image log, (2) the first 24 months cumulative oil produced, by stage, as known from chemical frac tracer data, (3) pre- and postfrac job instantaneous shut-in pressures, (4) microseismic, and (5) wireline log data. We used the cumulative oil production to document the spatially varying amount of aligned vertical porosity (aligned compliance or fracture porosity) connected to the stage borehole location. The stages of high oil production exhibited, for the fracture-perpendicular azimuth, the more positive amplitude variation with angle (AVA) gradients, and dimmer near-angle (6°–15° angles of incidence) amplitudes, compared to the fracture-parallel azimuth. The azimuthal variation of the AVA gradient fit the cos 2θ curve well, indicating the presence of one set of vertical aligned fractures dominating the azimuthal amplitude signature. In a similar fashion, the azimuthal variation of the mathematical intercept, physically the near-angle amplitudes, also fit the cos 2θ curve well. We have constructed crossplots of the azimuthal near-angle amplitude versus the AVA gradient on a bin-by-bin basis: we observed a straight line at bins with elevated oil production (elevated fracture density). A straight line crossplot of the (AVA gradient, mathematical intercept) is the signature of change of the (sensed) porosity, as long as the lithology and pore fluid are held constant. In accord with industry knowledge, we found that porosity affects the P impedance and thus the near-angle amplitudes: the aligned porosity yields azimuthal P impedance (measured at the 6°–15° angles of incidence). Legacy high-fold 3D P-P surveys rich in the 6°–20° angles of incidence should be considered for reprocessing and reinterpretation using these techniques.

Case study: Phase-component amplitude variation with angle

In detectable and isolated thin layers below seismic resolution, phase decomposition can theoretically be used to discriminate relatively high-impedance thin-layer responses from low-impedance reservoir responses. Phase decomposition can be used to isolate seismic amplitudes with a particular phase response or to decompose the seismic trace into symmetrical and antisymmetrical phase components. These components sum to form the original trace. Assuming zero-phase seismic data and normal American polarity, seismically thin layers that are high impedance relative to overlying and underlying half-spaces are seen on the [Formula: see text] phase component, whereas a relatively low-impedance thin layer will appear on the [Formula: see text] phase component. When such phase decomposition is applied to prestack attributes on a 2D line across a thin, 8 m thick, gas-saturated reservoir in the Western Canadian Sedimentary Basin of Alberta, Canada, amplitude-variation-with-angle is magnified on the [Formula: see text] phase component. The [Formula: see text] far-offset component allows the lateral extent of the reservoir to be better delineated. This amplification is also seen on the [Formula: see text] phase component of the gradient attribute. These results are corroborated by seismic modeling that indicates the same phase-component relationships for near- and far-angle stacks as are observed on the real data. Fluid substitution and seismic modeling indicate that, relative to full-phase data, the mixed-phase response observed in this study exhibits variations in fluid effects that are magnified and better observed at far angles on the [Formula: see text] phase component.

Imperialist competitive algorithm optimization method for nonlinear amplitude variation with angle inversion

Amplitude variation with angle (AVA) inversion is one of the most effective techniques in hydrocarbon exploration and estimating subsurface petrophysical properties. The inversion problem as a nonlinear, multiparameter, and multimodal optimization problem is conventionally solved through linearized optimization methods, but with the cost of smoothing important geologic interfaces. In addition, the results obtained by these methods are more possible to be trapped in a local minimum, while global-optimization methods can produce more accurate results and preserve the interfaces of geologic structures. A Bayesian framework is used to formulate the AVA inversion problem, which incorporates a novel prior constraint included by two regularization functions, one for sparsity of the coefficients as well as recovering discontinuities and another one for enhancing the lateral continuity. The imperialist competitive algorithm as an efficient evolutionary algorithm is then used to optimize the resulted objective function, to invert the P-and S-wave velocities as well as the density. We compare our algorithm with a commonly used Bayesian linearized inversion method by applying both methods on synthetic data and real seismic data from Gulf of Mexico. Our results reveal the practicability and stability of the presented method for the AVA inversion problem.

Active seismic studies in valley glacier settings: strategies and limitations

ABSTRACTSubglacial tills play an important role in glacier dynamics but are difficult to characterize in situ. Amplitude Variation with Angle (AVA) analysis of seismic reflection data can distinguish between stiff tills and deformable tills. However, AVA analysis in mountain glacier environments can be problematic: reflections can be obscured by Rayleigh wave energy scattered from crevasses, and complex basal topography can impede the location of reflection points in 2-D acquisitions. We use a forward model to produce challenging synthetic seismic records in order to test the efficacy of AVA in crevassed and geometrically complex environments. We find that we can distinguish subglacial till types in moderately crevassed environments, where ‘moderate’ depends on crevasse spacing and orientation. The forward model serves as a planning tool, as it can predict AVA success or failure based on characteristics of the study glacier. Applying lessons from the forward model, we perform AVA on a seismic dataset collected from Taku Glacier in Southeast Alaska in March 2016. Taku Glacier is a valley glacier thought to overlay thick sediment deposits. A near-offset polarity reversal confirms that the tills are deformable.