Amplitude Inversion Research Articles

Modelling analysis of the limitation of P-wave AVAZ inversion

The limitation of P-wave amplitude versus azimuth (AVAZ) inversion for fracture attribute parameters was studied by numerical modeling. First, seismic reflection data from multiple azimuths and incident angles were synthetized using anisotropic elastic wave equation modeling performed on a geological model, with a homogeneous isotropic medium overlying an anisotropic medium comprising vertical fractures. Then AVAZ inversion for fracture attribute parameters was performed on the synthetic data, from noise free to a signal-to-noise ratio (SNR) level of 2. The results were analyzed by comparison with the actual attribute parameters of the model. We demonstrate that the fracture azimuth attributes from the AVAZ inversion of noise free data agree well with the actual models, with difference <1°, over incident angle range from 9.8° to 44.2°. Inversion results from noisy data, on the other hand, vary widely and failed to characterize the actual azimuth, though an average of many inversions may still be able to approximate azimuth. In contrast, fracture intensity attributes from AVAZ inversion generally carry large inherent errors. The AVAZ attributes from noise free data underestimate the intensity, using incident angle range of 15° to ~26°, with errors ranging from 8% to ~92%. Using a lager incident angle, within ~26° to 35°, overestimates the intensity, with errors up to ~461%. The inherent errors are so large and variable that the fracture intensity attributes from AVAZ inversion are not suitable for use as direct quantitative interpretation of fracture intensity. However, the relative differences of fracture intensity attributes from AVAZ inversion qualitatively agree with the actual intensity differences and may be exploited as a qualitative measure of fracture intensity variation applied to a very limited range of incident angles. For noisy data, it is difficult to characterize fracture azimuth, not only by a single inversion but also by a statistical mean of multiple inversion results and an effective de-noising processing strategy is a critical step for fracture azimuth inversion.

Seismic amplitude inversion for the transversely isotropic media with vertical axis of symmetry

ABSTRACTTransverse isotropy with a vertical axis of symmetry is a common form of anisotropy in sedimentary basins, and it has a significant influence on the seismic amplitude variation with offset. Although exact solutions and approximations of the PP‐wave reflection coefficient for the transversely isotropic media with vertical axis of symmetry have been explicitly studied, it is difficult to apply these equations to amplitude inversion, because more than three parameters need to be estimated, and such an inverse problem is highly ill‐posed. In this paper, we propose a seismic amplitude inversion method for the transversely isotropic media with a vertical axis of symmetry based on a modified approximation of the reflection coefficient. This new approximation consists of only three model parameters: attribute A, the impedance (vertical phase velocity multiplied by bulk density); attribute B, shear modulus proportional to an anellipticity parameter (Thomsen's parameter ε−δ); and attribute C, the approximate horizontal P‐wave phase velocity, which can be well estimated by using a Bayesian‐framework‐based inversion method. Using numerical tests we show that the derived approximation has similar accuracy to the existing linear approximation and much higher accuracy than isotropic approximations, especially at large angles of incidence and for strong anisotropy. The new inversion method is validated by using both synthetic data and field seismic data. We show that the inverted attributes are robust for shale‐gas reservoir characterization: the shale formation can be discriminated from surrounding formations by using the crossplot of the attributes A and C, and then the gas‐bearing shale can be identified through the combination of the attributes A and B. We then propose a rock‐physics‐based method and a stepwise‐inversion‐based method to estimate the P‐wave anisotropy parameter (Thomsen's parameter ε). The latter is more suitable when subsurface media are strongly heterogeneous. The stepwise inversion produces a stable and accurate Thomsen's parameter ε, which is proved by using both synthetic and field data.

Joint Multiscale Direct Envelope Inversion of Phase and Amplitude in the Time–Frequency Domain

Time–frequency analysis can reveal local variations and allow for separation of phase and amplitude information of nonstationary seismic waveforms. Seismic signals are used since long as a robust tool for inversion of underground structures, as has been the practice in geophysical exploration. However, the mixing of phase and amplitude in seismic data increases the nonlinearity of seismic inversion. The authors first use Gabor transform to separate the phase and amplitude information of envelope data, and then introduce an adaptive factor into the misfit function to redistribute the weight of phase and amplitude information for direct envelope inversion (DEI) in the time–frequency domain. By adopting this procedure, greater flexibility can be achieved in operating the local phase of envelope and waveform spectra to enhance stability of multiscale phase inversion. For DEI, the direct envelope Frechet derivative is used, and thus, no weak scattering assumption is imposed on the joint multiscale DEI of phase and amplitude (PADEI). Compared with the DEI method, the PADEI can better recover the deeper parts of salt-bottom and subsalt structures by boosting the signal energy and weakening the nonlinearity of the waveform inversion.

Including edge preserving smoothing filter within blocky- constrained, target-oriented AVA inversions

Resolving thin layers and achieve focused layer boundaries is one of the major challenges in seismic inversion. This translates into recovering a blocky solution with sparse spatial derivatives of model parameters. Here, we present two iterative focusing regularization techniques for target-oriented Amplitude Versus Angle (AVA) inversion. Target-oriented means that only the AVA responses of the reflections of interest are inverted for the simultaneous estimation of P-wave, S-wave and density reflectivities. The first approach imposes Cauchy constraints on the spatial model derivatives whereas, the second is inspired by the minimum gradient support regularization. Both the implemented algorithms enhance their focusing and edge-preserving abilities by exploiting an Edge Preserving Smoothing (EPS) filter that is used to compute both the model constraints and the model update. We include a-priori model information into the inversion kernel to guide the convergence of the algorithms toward physically plausible solutions. The two approaches are compared against the standard Bayesian inversion that simply considers Gaussian distributed model parameters, and with the well-known edge-preserving method that assumes Cauchy-distributed derivative of model parameters. For the lack of available field seismic data, we limit the attention to synthetic inversion experiments in which we simulate different signal-to noise (S/N) ratios. The inversion tests prove the suitability of the two proposed approaches for target-oriented AVA inversion and demonstrate their focusing and anti-noise abilities. In particular, the two implemented algorithms outperform the standard Bayesian inversion and the Cauchy approach in cases of low S/N ratios. The two implemented methods are also extremely flexible and can be applied to other linear or non-linear geophysical inverse problems.

Full-waveform inversion for imaging and geologic interpretation: A deepwater Gulf of Mexico case study

Full-waveform inversion (FWI) is commonly used in model-building workflows to improve the resolution of the shallow velocity model and thus has a potentially positive impact on the imaging of deeper targets. This type of inversion commonly makes use of first arrivals from the longest offsets. However, signal from smaller offsets and later times can extend the depth range of the FWI-derived velocity model. Waveform inversion methods that use reflections have been shown to provide greater details and accuracy when deriving velocity models for deepwater exploration and production. The derived velocity sometimes provides an improved migrated image useful for interpretation in complex geology and enhances geologic features such as subsalt sediments, faults, and channels. We have used combination of FWI and a wavefield inversion approach known as reconstructed wavefield inversion (RWI) that makes use of diving waves and reflections to derive a velocity model for a deepwater survey off the coast of Veracruz in the Gulf of Mexico. The velocity model we derived from this approach produces an improved image of the target reservoir, and furthermore contains enough geologic details for direct interpretation. We enhanced the resolution of the velocity model further by performing a poststack amplitude inversion with the FWI + RWI derived velocity used as the input low-frequency model. The resulting high-resolution velocity provides an excellent product for detecting shallow gas anomalies, delineating a gas reservoir in an anticline structure as well as a system of deep, sand-filled channels. The inverted velocity also indicates a better correlation with sonic velocity measured from two blind wells than the initial tomography velocity, indicating the benefits of FWI approaches for quantitative reservoir characterization in deepwater environments.

A SPECTRAL METHOD OF LITHOFACIES DIFFERENTIATION WITHIN A HYDROCARBON RESERVIOR UNIT USING SEISMIC AND WELL DATA FROM TOMBOY FIELD NIGER DELTA

Seismic facies analysis is a key component of Seismic interpretation workflow, as much information on depositional process, environment, reservoir architecture and potential can be determined from the seismic data. This enhances the seismic visibility of subtle stratigraphic features, and prediction of new prospects for drilling due to lateral continuity of sand bodies (the hydrocarbon reservoir) deposited within the sedimentary column. This study presents the results of the application of seismic amplitude inversion and spectral decomposition to differentiate lithofacies within a thin-sand reservoir and show their lateral and vertical continuity using amplitude-derived attributes (rock properties) in the interpretation of 3D seismic and well log data from “TOMBOY” field Niger Delta. A thin-sand reservoir was delineated from lithologic log signatures within the interval 11,135.61-11,210.35ft which corresponds to the time window 2.752 - 2.768secs on the seismic data along an arbitrary line drawn to connect the six wells (01-06) in the field. Crossplot of acoustic impedance against density across the reservoir bed showed three compartments interpreted as gas filled sand, oil filled sand and shale. The interpretation was enhanced via spectral analysis by computing frequency maps of acoustic impedance, density and velocity using discrete Fourier transform (DFT) technique at top (2.752sec) of the reservoir in terms of magnitude, phase and frequency. Phase response for the three attributes (acoustic impedance, density and velocity) showed lateral continuity and discontinuity of sand lithofacies at the various well locations which were not evident on their original amplitude time slice, while frequency response showed bed thickness, with low frequency indicating presence of hydrocarbon or sand rich beddings, while high frequency indicates thin shale beddings. It was observed that the top (2.752sec) of the reservoir for wells 02, 05, 01 and 04 showed low frequency values for the three attributes (acoustic impedance, density and velocity) which indicates potential zones for hydrocarbon production and development in the field, while wells 03 and 06 within the same time slice (2.752sec) showed a higher value in acoustic impedance frequency, density frequency and velocity frequency and suggests the presence of thin shale facies at the top (2.752sec) of the thin-sand reservoir. By defining the lateral and vertical continuity of sand facies within the reservoir bed, hydrocarbon fairways were better defined and knowledge of this can be incorporated into drilling decisions for field development. The results gave enhanced structural disposition of the reservoir bed and more insights into the variation of sand lithofacies with depth. Keywords: Lithofacies, Amplitude inversion, Geologic transform, Seismic attributes, Cross plots and Spectral decomposition. DOI : 10.7176/JEES/9-3-14 Publication date :March 31 st 2019

D-dimensional SYK, AdS loops, and 6j symbols

We study the 6j symbol for the conformal group, and its appearance in three seemingly unrelated contexts: the SYK model, conformal representation theory, and perturbative amplitudes in AdS. The contribution of the planar Feynman diagrams to the three-point function of the bilinear singlets in SYK is shown to be a 6j symbol. We generalize the computation of these and other Feynman diagrams to d dimensions. The 6j symbol can be viewed as the crossing kernel for conformal partial waves, which may be computed using the Lorentzian inversion formula. We provide closed-form expressions for 6j symbols in d = 1, 2, 4. In AdS, we show that the 6j symbol is the Lorentzian inversion of a crossing-symmetric tree-level exchange amplitude, thus efficiently packaging the doubletrace OPE data. Finally, we consider one-loop diagrams in AdS with internal scalars and external spinning operators, and show that the triangle diagram is a 6j symbol, while one-loop n-gon diagrams are built out of 6j symbols.

Nonlinear joint PP-PS AVO inversion based on improved Bayesian inference and LSSVM

Multiwave seismic technology promotes the application of joint PP-PS amplitude versus offset (AVO) inversion; however conventional joint PP-PS AVO inversioan is linear based on approximations of the Zoeppritz equations for multiple iterations. Therefore the inversion results of P-wave, S-wave velocity and density exhibit low precision in the faroffset; thus, the joint PP-PS AVO inversion is nonlinear. Herein, we propose a nonlinear joint inversion method based on exact Zoeppritz equations that combines improved Bayesian inference and a least squares support vector machine (LSSVM) to solve the nonlinear inversion problem. The initial parameters of Bayesian inference are optimized via particle swarm optimization (PSO). In improved Bayesian inference, the optimal parameter of the LSSVM is obtained by maximizing the posterior probability of the hyperparameters, thus improving the learning and generalization abilities of LSSVM. Then, an optimal nonlinear LSSVM model that defines the relationship between seismic reflection amplitude and elastic parameters is established to improve the precision of the joint PP-PS AVO inversion. Further, the nonlinear problem of joint inversion can be solved through a single training of the nonlinear inversion model. The results of the synthetic data suggest that the precision of the estimated parameters is higher than that obtained via Bayesian linear inversion with PP-wave data and via approximations of the Zoeppritz equations. In addition, results using synthetic data with added noise show that the proposed method has superior anti-noising properties. Real-world application shows the feasibility and superiority of the proposed method, as compared with Bayesian linear inversion.

Colored and linear inversions to relative acoustic impedance

Acoustic impedance (AI) is a widely used seismic attribute in stratigraphic interpretation. Because of the frequency-band-limited nature of seismic data, seismic amplitude inversion cannot determine AI itself, but it can only provide an estimate of its variations, the relative AI (RAI). We have revisited and compared two alternative methods to transform stacked seismic data into RAI. One is colored inversion (CI), which requires well-log information, and the other is linear inversion (LI), which requires knowledge of the seismic source wavelet. We start by formulating the two approaches in a theoretically comparable manner. This allows us to conclude that both procedures are theoretically equivalent. We proceed to check whether the use of the CI results as the initial solution for LI can improve the RAI estimation. In our experiments, combining CI and LI cannot provide superior RAI results to those produced by each approach applied individually. Then, we analyze the LI performance with two distinct solvers for the associated linear system. Moreover, we investigate the sensitivity of both methods regarding the frequency content present in synthetic data. The numerical tests using the Marmousi2 model demonstrate that the CI and LI techniques can provide an RAI estimate of similar accuracy. A field-data example confirms the analysis using synthetic-data experiments. Our investigations confirm the theoretical and practical similarities of CI and LI regardless of the numerical strategy used in LI. An important result of our tests is that an increase in the low-frequency gap in the data leads to slightly deteriorated CI quality. In this case, LI required more iterations for the conjugate-gradient least-squares solver, but the final results were not much affected. Both methodologies provided interesting RAI profiles compared with well-log data, at low computational cost and with a simple parameterization.

Constrained 3D inversion of magnetic data with structural orientation and borehole lithology: A case study in the Macheng iron deposit, Hebei, China

We have developed a case study on the use of constrained inversion of magnetic data for recovering ore bodies quantitatively in the Macheng iron deposit, China. The inversion is constrained by the structural orientation and the borehole lithology in the presence of high magnetic susceptibility and strong remanent magnetization. Either the self-demagnetization effect caused by high susceptibility or strong remanent magnetization would lead to an unknown total magnetization direction. Here, we chose inversion of amplitude data that indicate low sensitivity to the direction of magnetization of the sources when constructing the underground model of effective susceptibility. To reduce the errors that arise when treating the total-field anomaly as the projection of an anomalous field vector in the direction of the geomagnetic reference field, we develop an equivalent source technique to calculate the amplitude data from the total-field anomaly. This equivalent source technique is based on the acquisition of the total-field anomaly, which uses the total-field intensity minus the magnitude of the reference field. We first design a synthetic model from a simplified real case to test the new approach, involving the amplitude data calculation and the constrained amplitude inversion. Then, we apply this approach to the real data. The results indicate that the structural orientation and borehole susceptibility bounds are compatible with each other and are able to improve the quality of the recovered model to obtain the distribution of ore bodies quantitatively and effectively.

A Contribution of the CDP Gathers and Pre-Stack Seismic Inversion in the Prospect Evaluation: A Case Study of El Mansoura Field, Nile Delta, Egypt

This case study showing the usefulness of the Common Depth Point (CDP’s) analysis to assess the amplitude response which is similar at two cases (gas-bearing and dry sands) after stack, using the Amplitude Versus Offset (AVO) analysis and the pre-stack inversion to understand the reservoir configuration and its relationship to the different amplitude response. The results led to a high success of exploration ratio as the positives vastly outweigh the negatives. Several lessons have been learned, which how to differentiate between the similar amplitude responses for two dry and gas discovery wells-by understanding the relationship between the near traces (near offset) and the far traces (far offset) from the CDP gathers in order to reduce the amplitude anomalies to their right justification. Consequently, a variation in the reflectivity strength is observed, which is controlled by the mechanical properties of the rocks: compression wave (VP), shear wave (Vs) and density. These properties are affected by litho logy and fluid contents. The analysis of the CDP’s gathers and the inversion results help in validating the prospects before drilling and in determining the response of the seismic amplitude deviation with the offset, so it is possible to confirm the amplitude anomaly if it is related to hydrocarbon or not.

The Relationship Between Social Power and Sexual Objectification: Behavioral and ERP Data.

Sexual objectification is very common in modern Western societies, especially toward women. Previous research has suggested that in Western cultures, social power could lead to objectification. Specifically, power activates an approaching tendency toward useful targets, in turn leading to instrumental objectification and sexual objectification of targets. However, previous research has mostly focused on Western cultures, and the neural correlates underlying this phenomenon remain unclear. To examine whether the effects of power can be generalized to Chinese cultural contexts and how power promotes the objectification of sexualized bodies, we conducted two studies using Chinese samples. In Study 1, we replicated the behavioral effects of social power on sexual objectification. Specifically, we found that power increased sexual objectification toward sexualized female rather than male bodies. In Study 2, we examined the absence of an N170 amplitude inversion effect as a possible neural correlate of sexual objectification and replicated the effects of power on sexual objectification through event-related potentials (ERPs). For participants in a high-power group, the N170 amplitude inversion effect emerged when processing sexualized male bodies (less sexual objectification) but not female bodies (more sexual objectification); this effect was not seen for those participants in a low-power group. Our findings provide behavioral and neural data that power leads to increased sexual objectification toward sexualized women in Chinese participants.

A reliable regression-based approach for seismic reservoir characterization

ABSTRACTSeismic reservoir characterisation includes seismic inversion and property prediction which provides valuable information from seismic data. A good reservoir characterisation workflow requires a reliable seismic inversion method. The most common and reliable approach for reservoir property prediction from surface seismic data is rock physics in which a physical or empirical model is used to describe the properties. However, these models require a huge number of predefined constant parameters, which makes their use complicated in practice. To overcome this, we propose a simple regression-based methodology to estimate reservoir properties (including porosity, water saturation and shale volume) from the elastic properties. The proposed methodology is a modified version of Lambda-Mu-Rho analysis for regression of water saturation and shale volume estimations. To find the elastic properties, we use Bayesian linearised amplitude versus offset inversion. Both the inversion method and the proposed methodology for seismic reservoir characterisation provide reliable information that correlates very well with the well data. Compared with the rock physics method, which is complicated and requires a number of parameters, the proposed methodology is straightforward and easy to apply.

Reservoir Prediction Restricted by Sequence Stratigraphy&lt;br/&gt;—A Case Study of Bioclastic Shoal Reservoir in Changxing Formation of Jiannan Area

Bioclastic shoal reservoir in Changxing Formation of Jiannan area is characterized by small thickness and strong heterogeneity. The uncertainty of the reservoir distribution pattern has confined the effective development of this area, so the accurate bioclastic shoal reservoir prediction would be the key to achieve development breakthroughs. Based on drilling, well-log, seismic and core analysis data, this article conducted exquisite sequence stratigraphic classification and established isochronal regional stratigraphic framework of Changxing Formation in Jiannan area. The reservoir seismic corresponding features were determined by exquisite calibrating bioclastic shoal reservoir in Changxing Formation. Therefore, seismic processing methods, such as multiple attribute analysis and amplitude inversion, were applied to attain more reliable reservoir prediction results, which indicated the distribution of vertical reservoir in SSQ2, the IV sequence order and the distribution of horizontal reservoir around Well J43 and JZ1 in the platform margin of the study area.

基于光学遥感图像的南海北部内孤立波振幅反演模型与应用

基于光学遥感图像的南海北部内孤立波振幅反演模型与应用

Study on Flow Unit of Heavy Oil Bottom Water Reservoir with Over-Limited Thickness in Offshore Oilfield

The upper Ming section of L oilfield is a typical offshore heavy oil bottom-water reservoir with thick fluvial layers. All horizontal wells are developed by natural energy. Due to the few drilling holes and influence by the resolution of seismic data, it is difficult to describe reservoirs with thickness over 20 meters. In this paper, seismic resonance amplitude inversion technology is introduced to restore the real response of thick reservoirs and interbeds by drilling and drilling verification, and the geological bodies with different thickness are displayed by frequency division RGB three primary colors. Flow units of heavy oil reservoirs with bottom water are divided according to the three major factors of interlayer, lithologic internal boundary and water-oil thickness ratio which have the greatest influence on horizontal well development, thick sand bodies are divided into 10 different flow units in three levels, each unit is separated from each other, and the reservoir structure, water-cut characteristics and water-flooding characteristics are different. The reliability of the research is improved by using the dynamic data of horizontal wells and newly drilled passing wells, which provides a basis for tapping the potential of heavy oil reservoirs with bottom water.

The influence of pore system change during CO2storage on 4D seismic interpretation

A 4D seismic forward model constitutes the foundation of 4D seismic inversion. Here, in combination with the Gassmann equation, the Digby model is improved to calculate the S-wave velocity, and the resulting equation is verified using rock testing results. Then, considering the influences of changes in the pore pressure, CO2saturation and porosity on the P- and S- wave velocities, rock testing results from a CO2injection area in the Weyburn field are used to calculate the P- and S-wave velocities of the reservoir. These P- and S-wave velocities are found to overlap under different pressure conditions with or without considering porosity variations. Therefore, two-layer models and well models are developed to simulate synthetic seismograms; the models considering porosity variations may provide greater seismic responses and different Amplitude Versus Offset (AVO) trends in the synthetic seismogram profiles than those without considering porosity variations. Thus, porosity variations must be considered when establishing 4D seismic forward models.

Behaviors of Converted Wave in an Azimuthally Isotropic Medium - A Physical Model Study

The existence of subsurface fractures provides not only space for the residence of petroleum but also paths of migration. Therefore, subsurface fractures are of great interest to exploration geophysicists. In reflection seismology, a reservoir of vertically aligned fractures is often considered to possess azimuthal anisotropy, or Horizontal Transverse Isotropy (HTI), in terms of seismic anisotropy. The characteristics and information of this specific type of reservoir are widely obtained using seismic attributes, including the azimuthal variation in the P -wave amplitude and velocity, and the fractional difference of split S-waves. Essentially, a converted (C-) wave is initiated by a downward traveling P-wave, which is converted on reflection to upcoming S-waves. Hence, it combines the behaviors of P- and S-waves in theory. Using a forward model study, this study demonstrates the behaviors of a C-waves in a HTI medium, instead of the behaviors of P- or S-waves. Reflections are facilitated on the horizontal symmetry-axis plane of a scaled HTI model along seven different azimuths using end-on shooting arrangement. Using a P-type transducer as a source and an S-type transducer as a receiver, the behaviors of C-waves in a HTI medium are observed. In the acquired profiles, reflections of P-, PS1- (C1 -), and a mixture of PS2- ( C2-) and S1-waves were detected. The phenomenon of C-wave splitting is also observed because of the behavior of an S-wave in a Transversely Isotropic Medium (TIM), and it could be easily identified in the azimuths near the fracture plane. The reflectivity strengths obtained using a Hilbert transform show that the azimuthal variation in the Amplitude Versus Offset (AVO) for both P- and C1-waves are consistent, but the C1-wave amplitude variation depends more significantly on the azimuth than that of the P-wave. Furthermore, the percentage anisotropy of the C-wave computed from acquired data falls right between those of P- and S-waves. By incorporating C-wave splitting and azimuthal AVO variation into traditional signature analyses, our results show that the fracture orientation is more pronounced when the potential reservoir has vertically aligned fractures.

3-D prestack data preconditioning for seismic amplitude inversion and the estimation of geomechanical properties: A case study from the structurally complex Moncton sub-basin, Eastern Canada

3-D land seismic data collected in the Moncton sub-basin (Eastern Canada) are plagued by random and coherent nose attributed to difficult acquisition conditions and complexities in the subsurface. Prior to amplitude inversion or the estimation of geomechanical properties, data must be preconditioned to provide reliable results. The preconditioning approach includes AVO-friendly rank reduction filtering followed by frequency-wavenumber (f-k) trace regularization. First, a synthetic model is used to asses the ability of the rank reduction approach to preserve the AVO behavior under various noise conditions before it is applied to the field data. The rank reduction scheme more than doubles the signal-to-noise ratio (s/n) of near-offset and mid-offset traces, increases the s/n of far-offset traces by 1.5 times and reduced amplitude distortions by removing the coherent noise from the data. F-k trace regularization helped to fill gaps in the angle coverage induced by irregular and wide-spaced offsets. However, the modeling experiment showed that the performance of rank reduction decreases as the s/n deteriorates. For low s/n, the model suggests that noise significantly alters the AVO behavior. This makes it very challenging for the filtering method, as it not only has to preserve the AVO trend but somehow restore it. Although rank reduction is able to retrieve the general AVO character, it fails to fully restore the trend on the far offset. This is not only observed on the experimental results but also on the field data for which the far offset is frequently the nosiest receiver. This questions the validity of the AVO response on far offsets when land data are collected in noisy terrains. In such settings, the inversion of the density term from large angles reflections can be biased, adding uncertainty to the estimation of Young's Modulus and the brittleness index that involves the density term in their calculation.

AVO inversion on unconventional reservoirs: systematic estimation of uncertainty in the Vaca Muerta shale

Abstract Amplitude versus offset inversion is widely used in reservoir characterization, but its implementation on unconventional reservoirs represents a challenge owing to the subtle changes of elastic parameters that demarcate profitable areas. For this reason, it is important to have an estimation of the uncertainty expected from seismic inversion to improve the interpretation of inverted results. We have implemented a systematic estimation of uncertainty of relative elastic properties obtained by damped least squares inversion of Aki and Richards and Fatti et al. approximations of Zoeppritz’s equation. Well log data of the Vaca Muerta unconventional shale in Argentina was used to generate synthetic angle gathers, varying in terms of asignal-to-noise ratio, range of angle coverage and number of partial angle stacks. The inversion results provide a systematic estimation of the uncertainty of the inverted coefficients. Results show that signal-to-noise ratio and range of angle coverage of the seismic data are key parameters to assess the feasibility of the inversion. In case of characterization based on acoustic impedance, the inverted parameters show good correlation with the model, with these correlation values being predicted by the parameter resolution matrix values.