Azimuthal Inversion Research Articles

A nonlinear and anisotropic data-driven litho-petroelastic inversion for single-loop subsurface characterization: Theory, uncertainties, and a case study

A new data assimilation algorithm for joint litho-petroelastic (LPE) inversion using nonlinear anisotropic Zoeppritz reflectivity operators, together with iterative sequential filtering, is used to provide joint elastic, lithology, and petrophysical estimates. The sequential filtering approach is an attractive choice because integration of petroelastic rock models with seismic data for multiparameter estimation can become quickly ill posed. Data assimilation techniques integrate the data and model in a manner that tracks uncertainties and manages the flow of data, which helps control this difficult, ill-posed estimation problem. For anisotropic formations, joint LPE inversion makes it possible to use anisotropy information associated with the lithology units or petrophysical parameters, either as fixed lithology-dependent trends by means of prior averages or as a direct function of the petrophysical parameters. This proves beneficial for amplitude variation with angle/amplitude variation with azimuth inversion where the azimuthal invariant anisotropic parameter space, containing the vertical transverse isotropy (VTI) components of the reflectivity operators, is not resolvable independently from shear and density information. In many cases, neglecting to account for anisotropy will lead to inferior characterization of anisotropic plays. Anisotropic LPE inversion enables anisotropic characterization by identifying the anisotropic formation as part of the inversion process. LPE inversion also provides estimates of the petrophysical parameter space and, therefore, honors the relation between the anisotropic elasticity, lithology, and petrophysical parameters. This study reviews the LPE inversion workflow and shows how anisotropic LPE inversion in VTI media is used to derive jointly elastic properties, lithology, and petrophysical parameters of the Wolfcamp Permian Basin shale play in Texas. We also demonstrate the importance of including anisotropy in the inversion and show that isotropic inversion poorly delineated the lithology of the play.

Matrix-fluid-fracture decoupled-based elastic impedance variation with angle and azimuth inversion for fluid modulus and fracture weaknesses

The ratio of normal-to-shear fracture compliances, approximate to the product of two ratios of shear-to-compressional (S-to-P) wave velocity and normal-to-tangential fracture weakness, has been treated as an indicator of fluid content for an oil-bearing reservoir with aligned fractures. However, this indicator depends on both fluid saturation and fracturing strength of rocks, while the effective fluid bulk modulus as a sensitive indicator decouples the double effects of rock porosity and pore fluid. Moreover, an incorrect value of S- and P-wave velocity ratio may have a significant effect on the estimation of normal-to-shear fracture compliances. Based on the anisotropic poroelasticity amplitude variation with offset and azimuth (AVOAz) theory, we use the Born formalism and a first-order perturbation assumption to derive a matrix-fluid-fracture decoupled-based linearized PP-wave reflection coefficient in an oil-bearing fractured porous medium. Our derived formula reveals that the combined effects of background matrix, pore fluids and fracture strength on seismic amplitudes are separated, more applicable to implement the fluid identification and fracture detection in a liquid-filled porous reservoir with aligned fractures. Following a Bayesian framework, we develop a Bayesian inversion method to reasonably obtain the fluid modulus and saturated fracture weaknesses. The implementation methodology includes two steps: a model-based least-squares inversion for azimuthal elastic impedances and an iterative Bayesian seismic inversion for model parameters. Tests on synthetic data corrupted with moderate random noise indicate that these model parameters can be estimated reasonably and accurately when the oil-saturated rock is permeated with a single fracture system. Test on a real data set validates that the reliable estimates of fluid and fracture parameters can be used to realize the fluid identification and fracture detection in an oil-bearing fractured porous reservoir in a more direct manner than previous approach.

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.

Amplitude variation with offset and azimuth inversion for fluid indicator and fracture weaknesses in an oil-bearing fractured reservoir

Fluid identification and fracture discrimination play an important role in the exploration and development of an oil-bearing fractured reservoir. The most common fluid indicator in fractured reservoirs, the normal-to-shear fracture compliance ratio, is influenced by the fluid content and the fracture intensity. To reduce the ambiguities in the discrimination of the fluid and fracture parameters, we have aimed to extend the scattering theory to implement the fluid identification and fracture detection by incorporating the azimuthal data in an oil-bearing fractured reservoir via the proposed Bayesian amplitude variation with offset and azimuth (AVOAz) inversion approach. The background medium is, as far as the scattering theory is concerned, an isotropic medium without fractures, and the fractured medium is corresponding to a perturbed medium. The elastic parameters of a saturated anisotropic medium can be parameterized as a perturbation over a homogeneous isotropic background medium. We used the scattering theory to derive a generalized AVOAz approximation that provided the iterative estimates of hydrocarbon fluid indicator, shear modulus, density, and fracture weaknesses in a Bayesian scheme. The inversion algorithm is based on a convolutional model and a weak-contrast and small-weakness PP-wave reflection coefficient. The approach is applied to an oil-bearing field data set from a fractured marlstone reservoir. We observe that reasonable estimates of fluid indicator and fracture weaknesses are inverted, which can be used to perform the discrimination of fluid and fracture parameters. We conclude that the proposed approach provides us a potentially powerful tool to estimate the reservoir fluid and fracture properties in a more straightforward and efficient manner than those previous methods.

Amplitude variation with incident angle and azimuth inversion for Young's impedance, Poisson's ratio and fracture weaknesses in shale gas reservoirs

ABSTRACTBy analogy with P‐ and S‐wave impedances, the product of Young's modulus and density can be termed as Young's impedance, which indicates the rock lithology and brittleness of unconventional hydrocarbon reservoirs. Poisson's ratio is also an effective indicator of rock brittleness and fluid property of unconventional reservoirs, and fracture weaknesses indicate the fracture properties (fracturing intensity and fracture fillings) in fracture‐induced unconventional reservoirs. We aim to simultaneously estimate the Young's impedance, Poisson's ratio and fracture weaknesses from wide‐azimuth surface seismic data in a fracture‐induced shale gas reservoir, and use the horizontal transversely isotropic model to characterize the fractures. First, the linearized PP‐wave reflection coefficient in terms of Young's impedance, Poisson's ratio, density and fracture weaknesses is derived for the case of a weak‐contrast interface separating two weakly horizontal transversely isotropic media. In addition, an orthorhombic anisotropic case is also discussed in this paper. Then a Bayesian amplitude variation with incident angle and azimuth scheme with a model constraint is used to stably estimate Young's impedance, Poisson's ratio and fracture weaknesses with only PP‐wave azimuthal seismic data. The proposed approach is finally demonstrated on both synthetic and real data sets with reasonable results.

Fracture detection and fluid identification based on anisotropic Gassmann equation and linear-slip model

Detection of fracture and fluid properties from subsurface azimuthal seismic data improves our abilities to characterize the saturated porous reservoirs with aligned fractures. Motivated by the fracture detection and fluid identification in a fractured porous medium, we have developed a feasible approach to perform a rock physics model-based amplitude variation with offset and azimuth (AVOAz) inversion for the fracture and fluid parameters in a horizontal transversely isotropic (HTI) medium using the PP-wave angle gathers along different azimuths. Based on the linear-slip model, we first use anisotropic Gassmann’s equation to derive the expressions of saturated stiffness components and their perturbations of first-order approximation in terms of elastic properties of an isotropic porous background and fracture compliances induced by a single set of rotationally invariant fractures. We then derive a linearized PP-wave reflection coefficient in terms of fluid modulus, dry-rock matrix term, porosity, density, and fracture compliances or quasi-compliances for an interface separating two weakly HTI media based on the Born scattering theory. Finally, we solve the AVOAz inverse problems iteratively constrained by the Cauchy-sparse regularization and the low-frequency regularization in a Bayesian framework. The results demonstrate that the fluid modulus and fracture quasi-compliances are reasonably estimated in the case of synthetic and real seismic data containing moderate noise in a gas-filled fractured porous reservoir.

Elastic Impedance Variation with Angle and Azimuth Inversion for Brittleness and Fracture Parameters in Anisotropic Elastic Media

Young’s modulus, Poisson’s ratio, and fracture excess compliances, which are related to rock brittleness and natural fractures, can be used to evaluate the hydraulic fracturing and infer the optimized sweet spots in unconventional reservoirs. We aim to characterize the elastic properties of rock brittleness and compliance from the observable wide-azimuth seismic data via the inversion of Young’s modulus, Poisson’s ratio, and excess compliances. Using the linear slip model, we first derive the perturbations in stiffness components in terms of Young’s modulus, Poisson’s ratio, and excess compliances for the case of weak anisotropy and small contrasts in elastic properties across the interface. Based on the relationship between scattering function and reflection coefficient in weakly anisotropic media, we then derive a linearized PP-wave reflection coefficient and an azimuthal elastic impedance (EI) equation as a function of Young’s modulus, Poisson’s ratio, density, and excess compliances. Finally, we develop an EI variation with incident angle and azimuth inversion method to estimate the Young’s modulus, Poisson’s ratio, and excess compliances in a Bayesian framework. The approach is implemented in a two-step inversion: azimuthal EI inversion and estimation of model parameters. A synthetic test demonstrates that the model parameter can be reasonably estimated even containing moderate noise. A field data set test reveals that the inversion results agree well with the well log interpretation.

Estimation of fluid indicator and dry fracture compliances using azimuthal seismic reflection data in a gas-saturated fractured reservoir

Amplitude variation with offset and azimuth (AVOA) inversion is a powerful tool used to predict the fluid and fracture information by utilizing the observable seismic reflection amplitudes. Understanding the effect of in situ fluid and fracture characteristics on seismic response is significant in a fractured reservoir. Our goal is to demonstrate an AVOA inversion approach to utilize the observable azimuthal seismic reflection data to predict the fluid and fracture properties in a gas-saturated fractured reservoir. Starting from Gassmann’s anisotropic poroelasticity theory and the linear-slip model, we first derive a linearized PP-wave reflection coefficient in terms of fluid, rigidity, density, and dry fracture compliance parameters based on the scattering function and perturbations in dry stiffness matrix of a horizontal transversely isotropic (HTI) rock containing a system of aligned vertical fractures. The derived equation builds a linearized relationship between the characteristics of fluid and fracture and the seismic response of azimuthal seismic reflection amplitudes. Incorporating the convolution model and Bayesian inversion, we propose a feasible Bayesian AVOA inversion method to estimate the fluid and fracture parameters directly. Cauchy and Gaussian probability distribution are used for the a priori information of model parameters and the likelihood function, respectively, and the nonlinear iteratively reweighted least squares (IRLS) strategy is finally utilized to solve the maximum a posteriori solutions of model parameters. The synthetic examples containing a moderate noise demonstrate the feasibility of inversion method, and the real data illustrates the inversion stabilities of fluid and fracture parameters in a gas-saturated fractured reservoir.

Bringing multidisciplinary geosciences into quantitative inversion: A Midland Basin case study

Over the last two decades, the driver behind the boom in unconventional reservoirs has been the development of horizontal drilling and hydraulic fracturing. More recently, the fall in oil prices has resulted in the industry refocusing on the shale market and its most profitable plays, a notable example being the Permian Basin. We argue that this refocusing should also take place in the technology domain and that seismic and its derivatives should provide reservoir and completion engineers with the means to optimize well planning. This is illustrated with a case study of an advanced quantitative interpretation workflow tailored for a seismic multiclient program in the Wolfberry Play of the Midland Basin. Seismic imaging begins by providing a structural interpretation basis, then quantitative interpretation provides 3D elastic and geomechanical attributes through prestack inversion and azimuthal inversion, respectively. This 3D canvas of elastic attributes is combined with petrophysical, mineralogical, geomechanical, and geochemical properties measured at the wells. The challenge of reconciling such data sets with different scales and spatial sampling is overcome using physical, empirical, or statistical relationships within the data. The adjunction of rock data to the 3D elastic attributes provides calibration and validation of the inversion results. More interestingly, it allows for quantitative prediction of lithology, facies, porosity, and geochemical properties away from the wells. The purpose of the resulting calibrated reservoir model is to assist in optimizing drilling plans and executing completion designs.

Azimuthally pre-stack seismic inversion for orthorhombic anisotropy driven by rock physics

Based on the long-wavelength approximation, a set of parallel vertical fractures embedded in periodic thin interbeds can be regarded as an equivalent orthorhombic medium. Rock physics is the basis for constructing the relationship between fracture parameters and seismic response. Seismic scattering is an effective way to inverse anisotropic parameters. In this study, we propose a reliable method for predicting the Thomsen’s weak anisotropic parameters and fracture weaknesses in an orthorhombic fractured reservoir using azimuthal pre-stack seismic data. First, considering the influence of fluid substitution in mineral matrix, porosity, fractures and anisotropic rocks, we estimate the orthorhombic anisotropic stiffness coefficients by constructing an equivalent rock physics model for fractured rocks. Further, we predict the logging elastic parameters, Thomsen’s weak parameters, and fracture weaknesses to provide the initial model constraints for the seismic inversion. Then, we derive the P -wave reflection coefficient equation for the inversion of Thomsen’s weak anisotropic parameters and fracture weaknesses. Cauchy-sparse and smoothing-model constraint regularization taken into account in a Bayesian framework, we finally develop a method of amplitude variation with angles of incidence and azimuth (AVAZ) inversion for Thomsen’s weak anisotropic parameters and fracture weaknesses, and the model parameters are estimated by using the nonlinear iteratively reweighted least squares (IRLS) strategy. Both synthetic and real examples show that the method can directly estimate the orthorhombic characteristic parameters from the azimuthally pre-stack seismic data, which provides a reliable seismic inversion method for predicting Thomsen’s weak anisotropic parameters and fracture weaknesses.

Elastic impedance parameterization and inversion for fluid modulus and dry fracture quasi-weaknesses in a gas-saturated reservoir

A single set of aligned vertical fractures embedded in a purely isotropic background can be considered as an effective long-wavelength transversely isotropic (HTI) medium with a horizontal axis of symmetry. Understanding the separated effect of fluid and fracture properties on seismic characteristics is important for the characterization of a gas-saturated fractured reservoir. Our goal is to demonstrate a direct approach to separate the effects of fluid and fracture properties on PP-wave reflection coefficient, and utilize the azimuthal seismic reflection data to estimate the fluid modulus and dry fracture quasi-weaknesses simultaneously in a gas-saturated fractured reservoir. Starting from Gassmann's poroelasticity theory and linear-slip model, we first derive expressions for the effective elastic stiffness matrix of a gas-saturated fracture-induced porous HTI medium. Using the assumption of small perturbations in rock moduli and small weaknesses, we then derive an expression for linearized PP-wave reflection coefficient for the case of a weak-contrast interface separating two weakly HTI media in terms of fluid modulus and dry (gas-filled) fracture weaknesses based on the perturbation matrix and scattering function, separating the effects of fluid and fracture properties on PP-wave seismic response. With a novel parameterization for dry fracture weaknesses, we propose a method of elastic impedance variation with offset and azimuth (EIVOA) inversion for fluid modulus and dry fracture quasi-weaknesses to reduce the uncertainty of the characterization of fluid and dry fracture properties. Combing Bayesian seismic inversion and regularization constraints, the fluid modulus and dry fracture quasi-weakness parameters are reasonably estimated in the case of synthetic and real seismic data containing a moderate noise in a gas-saturated fractured reservoir.

Azimuthal Seismic Amplitude Variation with Offset and Azimuth Inversion in Weakly Anisotropic Media with Orthorhombic Symmetry

Seismic amplitude variation with offset and azimuth (AVOaz) inversion is well known as a popular and pragmatic tool utilized to estimate fracture parameters. A single set of vertical fractures aligned along a preferred horizontal direction embedded in a horizontally layered medium can be considered as an effective long-wavelength orthorhombic medium. Estimation of Thomsen’s weak-anisotropy (WA) parameters and fracture weaknesses plays an important role in characterizing the orthorhombic anisotropy in a weakly anisotropic medium. Our goal is to demonstrate an orthorhombic anisotropic AVOaz inversion approach to describe the orthorhombic anisotropy utilizing the observable wide-azimuth seismic reflection data in a fractured reservoir with the assumption of orthorhombic symmetry. Combining Thomsen’s WA theory and linear-slip model, we first derive a perturbation in stiffness matrix of a weakly anisotropic medium with orthorhombic symmetry under the assumption of small WA parameters and fracture weaknesses. Using the perturbation matrix and scattering function, we then derive an expression for linearized PP-wave reflection coefficient in terms of P- and S-wave moduli, density, Thomsen’s WA parameters, and fracture weaknesses in such an orthorhombic medium, which avoids the complicated nonlinear relationship between the orthorhombic anisotropy and azimuthal seismic reflection data. Incorporating azimuthal seismic data and Bayesian inversion theory, the maximum a posteriori solutions of Thomsen’s WA parameters and fracture weaknesses in a weakly anisotropic medium with orthorhombic symmetry are reasonably estimated with the constraints of Cauchy a priori probability distribution and smooth initial models of model parameters to enhance the inversion resolution and the nonlinear iteratively reweighted least squares strategy. The synthetic examples containing a moderate noise demonstrate the feasibility of the derived orthorhombic anisotropic AVOaz inversion method, and the real data illustrate the inversion stabilities of orthorhombic anisotropy in a fractured reservoir.

Azimuthal AVO inversion of an elliptic orthorhombic medium

Anisotropic information regarding the subsurface is important for various geophysical applications, including fracture characterization and estimation of the in situ stress field. Conventional techniques used to invert seismic amplitudes for anisotropic parameters estimate quantities such as the anisotropic gradient, which is not easily interpretable due to the amalgamation of various elastic stiffness coefficients. To gain an improved understanding of the anisotropic parameters estimated from azimuthal amplitude variation with offset (AVO) inversion, we simplify the PP reflection coefficient for a medium with arbitrary anisotropy by imposing an elliptic orthorhombic constraint. This results in a reduced form of the reflection coefficient in which the azimuthally dependent components are only a function of the horizontal P- and vertical S-wave velocities in a rotated coordinate frame. Furthermore, the anisotropic components are parameterized as direct perturbations from the isotropic solution, which requires no a priori information regarding the anisotropy and stabilizes the inversion. We demonstrate the utility of the elliptic orthorhombic approximation through an example in the Montney tight-gas play in northeast British Columbia, Canada, where we perform an azimuthal AVO inversion and estimate the crack density and differential stress ratio.

Post-stack attribute-based fracture characterization: A case study from the Niobrara shale

The ability to determine the relative density and orientations of fractures in potential reservoirs has become increasingly important as resource plays are now a major exploration and development focus for energy companies worldwide. Techniques have been developed using pre-stack data and velocity anisotropy to identify and map fractures. Azimuthal AVO has been employed to estimate fracture density and quantitatively assess how well this approach predicts reservoir quality (Hunt, 2010). Additionally, a new approach to quantitative azimuthal inversion for stress and fracture detection has been developed (Mesdag, 2016). This paper focuses on extracting a relative fracture density attribute and fracture orientations from migrated post-stack 3D seismic volumes. The detection and mapping of fractures in migrated poststack 3D seismic data depends on the resolution and signal-tonoise ratio of the data in the seismic volume. A discussion of resolution problems and the limits of resolution in post-stack 3D seismic data, and structurally-oriented post-stack coherent and random noise filtering is followed by descriptions of a Fracture Density attribute and of the extraction of fracture orientations. An example of the results of applying these processes and workflow is included from the Niobrara shale play in the United States.

Model-based amplitude versus offset and azimuth inversion for estimating fracture parameters and fluid content

The normal-to-shear fracture compliance ratio is commonly used as a fluid indicator. In the seismic frequency range, the fluid indicator lies between the values for isolated fluid-filled fractures and dry fractures, and it is not easy to discriminate the fluid content. Assuming that the fracture surfaces are smooth, we use [Formula: see text], with [Formula: see text] and [Formula: see text] representing the normal fracture weakness of the saturated and dry rock, to indicate fluid types, and to define a fluid influencing factor. The fluid influencing factor is sensitive to the fluid properties, the aspect ratio of the fractures, and the frequency. Conventionally, the amplitude versus offset and azimuth (AVOA) inversion is formulated in terms of the contrasts of the fracture weaknesses across the interface, assuming that the fractures are vertical with the same symmetry axis. We consider fractures with arbitrary azimuths, and develop a method to estimate fracture parameters from wide-azimuth seismic data. The proposed AVOA inversion algorithm is tested on real 3D prestack seismic data from the Tarim Basin, China, and the inverted fracture density show good agreement with well log data, except that there are some discrepancies for one of the fractured reservoir sections. The discrepancies can be ascribed to neglect of the dip angle for the tilted fractures and the conjugate fracture sets, and to the validity of the linear-slip model. The fractured reservoirs are expected to be liquid saturated, under the assumption of smooth fractures. Overall, the inverted fracture density and fluid influencing factor can be potentially used for better well planning in fractured reservoirs and quantitatively estimating the fluid effects.

Evaluation of CBM reservoir fracture characteristics by azimuthal AVA inversion

Exploitation of coalbed methane (CBM) is directly affected by the strike and density of fractures, particularly because fractures can act as conduits for water and gas (after desorption). To realize the azimuthal amplitude versus angle (AVA) inversion for a CBM reservoir, we treated reservoirs whose fractures are aligned vertically as being equivalent to a horizontal transverse isotropic medium and simplified the P-P wave reflection coefficient formula to an approximately linear equation. Then, we adopted a modified damping least squares algorithm to solve the azimuthal AVA inversion problem. With edited macro-bins, corrected residual moveout, and normalized amplitude, the azimuthal gathers exhibited unambiguous azimuthal AVA characteristics. The #3 CBM reservoir in the Qinshui Basin was selected for a case study. The density and strike of the reservoir fractures were obtained and analyzed, and the reservoir was divided into three classes according to fracture density. Finally, in comparison with the gas production data, we confirmed that the inversion results and reservoir classification were both reasonable and credible.

Polynomial amplitude versus azimuth inversion in horizontally transverse isotropic media, as tested on fractured coal seams in the Surat Basin

A new technique of amplitude versus azimuth (AVAZ) seismic inversion in horizontally transverse isotropic (HTI) media is presented. AVAZ is an effective method of characterising anisotropic variation within individual reflectors as well as characterising fractures. The compressional wave reflectivity equation in HTI media has been reformulated into a parabolic form that allows for fast and efficient inversion. The isotropic component of the azimuthal reflectivity has been separated precisely from the anisotropic component and the anisotropic component has been decoupled exactly into its constituent elliptic and anelliptic components. The exact isotropic, elliptic and anelliptic amplitude versus offset (AVO) gradient equations in HTI media are presented herein and the amount of error associated with previous approximations is also defined under the assumption of weak anisotropy. A method of calculating Thomsen’s weak anisotropy parameters using these AVO gradient terms is then outlined. Compared with the elliptic method, there is reduced error incorporated in the new AVAZ method and the error relationships of this method are compared with the Fourier method. Data from an open file 3D wide azimuth seismic survey in the Surat Basin were inverted to demonstrate the effectiveness of the techniques which are presented herein. Seismic amplitudes from six azimuthal stacks were extracted over two horizons and inverted around a well where full-wave sonic and density logs were acquired. For both horizons, the error between the inverted anisotropy parameters from seismic and the inverted anisotropy parameters from wire line logs were found to be less than 5% for both horizons.

What’s new and exciting in seismic inversion?

Consider an oil and gas exploration team that has been successfully using seismic attributes such as gradient & intercept or fluid & lithology indicators. Why might this team want to switch from those tried-and-true seismic attributes to seismic inversion? And which type of seismic inversion should they use? We now have access to azimuthal inversion, facies inversion, Bayesian probabilistic inversion and full waveform acoustic and (emerging) full waveform elastic inversion. The evolution and pace of seismic inversion technologies is exciting but present some difficult choices to the uninitiated interpreter. This talk aims to give seismic interpreters an overview of these ‘new’ technologies and how they compare. Topics covered will include: the advantages and challenges of azimuthal AVO inversion in Australia’s high stress environment, Bayesian (probabilistic) inversion and how inverting for facies improves it, synergies and challenges of combining new broad-band / long cable seismic acquisition with AVO inversion, and full waveform seismic inversion — can it replace AVO inversion? A minimum of equations will be shown — and only then to as a guide to illustrate what the different inversion techniques are doing.

Uncertainty and nonuniqueness in linearized AVAZ for orthorhombic media

Orthorhombic symmetry is one of the simplest models capable of representing fractured media such as naturally fractured shale reservoirs. However, low elastic symmetry translates to a large number of unknown elastic parameters, which affects the ability to obtain unique solutions. Therefore, the uncertainty associated with seismic-amplitude inversion must be considered for better understanding of the limitations and potential benefit of the inversion. An analysis of linearized amplitude variation with azimuth (AVAZ) inversion resulted in the development of workflows for practical AVAZ parameter estimation with uncertainty analysis. The inverted orthorhombic parameters are ranked by their uncertainty. Inversion attributes have clear meaning and can be used quantitatively when performing anisotropic orthorhombic subsurface characterization. The technique was applied in a field case for estimation of reservoir properties in orthorhombic media.

Azimuthal amplitude variation with offset analysis of physical modeling data acquired over an azimuthally anisotropic medium

We evaluated a quantitative amplitude analysis of 3D physical model reflection data acquired over an experimental phenolic layer that modeled a fractured medium with one set of vertical fractures. The phenolic layer was overlain by two isotropic layers, the uppermost being water, and the data acquisition was designed to avoid the interference of the primary and ghost events. The elastic stiffness coefficients and hence the anisotropy of the phenolic layer were known in advance from a previous traveltime analysis. The reflection amplitudes from the top of the phenolic layer required corrections to make them suitable for an amplitude study. In addition to the usual amplitude corrections applied to seismic field data, a directivity correction specific to the physical model transducers was applied. The corrected amplitudes along different azimuths showed a clear azimuthal variation caused by the phenolic layer and agreed with amplitudes predicted theoretically. An amplitude variation with angle and azimuth inversion was performed for horizontal transverse isotropy (HTI) parameters of the phenolic layer. We determined from the inversion results that from the azimuthally varying P-wave reflectivity response, it was possible to estimate HTI parameters that compared favorably to those obtained previously by a traveltime analysis. This result made it possible to compute the S-wave splitting parameter [Formula: see text] (historically determined from S-wave data and directly related to fracture density) from a quantitative analysis of the PP data.