Amplitude Variation With Offset And Azimuth Research Articles

Multiscale frequency-domain seismic inversion for fracture weakness

Amplitude variation with offset and azimuth (AVOAz) inversion is an effective tool to invert the azimuthal seismic reflection data for fracture weaknesses, which play an important role in seismic characterization of fractures. Conventional AVOAz inversion is implemented in the time domain, which simultaneously uses full-frequency components of the seismic data causing an unstable and inaccurate inversion result in the case of noisy seismic data. Here we propose a novel multiscale frequency-domain seismic inversion approach to improve resolution and accuracy of fracture weakness estimates. Based on new derived frequency-domain expression of azimuthal seismic amplitude difference for a horizontal transversely isotropic (HTI) medium, we build the kernel function incorporated with the Fourier operator, which avoids the Fourier inverse transform in the frequency-domain inversion. Low frequency information in seismic data is often missing or contaminated with noises, thus we establish an inversion objective function combining low frequency regularization term and Cauchy sparse regularization term in the Bayesian framework. We adopt the multiscale strategy and perform inversion successively from low to high frequency group utilizing a limited number of frequency components with a high signal-to-noise (S/N) ratio. In addition, we compare the multiscale frequency-domain inversion approach, the frequency-domain simultaneous inversion approach, and the time-domain inversion approach using synthetic data and field data. Synthetic example demonstrates that the cross-correlation coefficients (CCs) between the true fracture weaknesses and the inversion results obtained by multiscale frequency-domain inversion approach are above 0.83 even with a S/N of 2. Compared to the time-domain inversion approach and the frequency-domain simultaneous inversion approach, the inversion results with multiscale frequency-domain inversion approach have higher resolution and accuracy. Field data example further validates the feasibility and superiority of the proposed multiscale frequency-domain inversion approach.

Impact of poroelastic effects on the inversion of fracture properties from amplitude variation with offset and azimuth data in horizontal transversely isotropic media

The identification and characterization of fractures is an important objective in many areas of earth and environmental sciences. Amplitude variation with offset and azimuth (AVOAz) analysis of seismic reflection data is a key method for achieving these tasks. Theoretical and experimental studies have shown that the presence of pore fluids together with the strong mechanical contrast between the fractures and their embedding background give rise to wave-induced fluid flow (WIFF) effects. This implies that the effective stiffness tensor of a fluid-saturated fractured rock defining its seismic response becomes viscoelastic and frequency-dependent. In spite of this, AVOAz analysis typically relies on end-member-type elastic stiffness models that either assume a relaxed (i.e., equilibrated) or unrelaxed (i.e., unequilibrated) state of the wave-induced fluid pressure in the rock. In general, however, neither the appropriateness of the chosen model nor the associated errors in the inversion process are known. To investigate this topic, we have considered a poroelastic medium containing parallel vertical fractures and generate synthetic seismic AVOAz data using the classic Rüger approximations for PP-wave reflection coefficients in horizontally transversely isotropic media. A Markov chain Monte Carlo method is used to perform a Bayesian inversion of the synthetic seismic AVOAz data. We quantify the influence of WIFF effects on the AVOAz inversion results when elastic relaxed and unrelaxed models are used as forward solvers of inversion schemes to estimate the fracture volume fraction, the elastic moduli, and the porosity of the background rock, as well as the overall weakness of the medium due to the presence of fractures. Our results indicate that, when dealing with single-frequency data, relaxed elastic models provide biased but overall better inversion results than unrelaxed ones, for which some fracture parameters cannot be resolved. Improved inversion performance is achieved when using frequency-dependent data, which illustrates the importance of accounting for poroelastic effects.

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.

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.

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.

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.

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.

Fracture detection via correlating P-wave amplitude variation with offset and azimuth analysis and well data in eastern central Saudi Arabia

The late Carboniferous clastic Unayzah-C in eastern central Saudi Arabia is a low-porosity, possibly fractured reservoir. Mapping the Unayzah-C is a challenge due to the low signal-to-noise ratio (S/N) and limited bandwidth in the conventional 3D seismic data. A related challenge is delineating and characterizing fracture zones within the Unayzah-C. Full-azimuth 3D broadband seismic data were acquired using point receivers, low-frequency sweeps down to 2 Hz, and 6 km patch geometry. The data indicate significant enhancement in continuity and resolution of the reflection data, leading to improved mapping of the Unayzah-C. Because the data set has a rectangular patch geometry with full inline offsets to 6000 m, using amplitude variation with offset and azimuth (AVOA) may be effective to delineate and characterize fracture zones within Unayzah-A and Unayzah-C. The study was undertaken to determine the improvement of wide-azimuth seismic data in fracture detection in clastic reservoirs. The results were validated with available well data including borehole images, well tests, and production data in the Unayzah-A. There are no production data or borehole images within the Unayzah-C. For validation, we had to refer to a comparison of alternative seismic fracture detection methods, mainly curvature and coherence. Anisotropy was found to be weak, which may be due to noise, clastic lithology, and heterogeneity of the reservoirs, in both reservoirs except for along the western steep flank of the study area. These may correspond to some north–south-trending faults suggested by circulation loss and borehole image data in a few wells. The orientation of the long axis of the anisotropy ellipses is northwest–southeast, and it is not in agreement with the north–south structural trend. No correlation was found among the curvature, coherence, and AVOA in Unayzah-A or Unayzah-C. Some possible explanations for the low correlation between the AVOA ellipticity and the natural fractures are a noisy data set, overburden anisotropy, heterogeneity, granulation seams, and deformation.

Geophysics Bright Spots

In the March-April 2017 issue of Geophysics, we see an improved structure-tensor-based coherence technique to detect and map seismic faults and channels. We learn about a new viscoelastic reverse time migration algorithm with attenuation compensation. We also learn about a new sparse dictionary method for full-waveform inversion (FWI). In rock physics, we see a new approach to amplitude variation with offset and azimuth (AVOA) analysis that helps determine fracture fluid properties, as well as a new study of acoustic measurements in well-mated fracture environments.

Fracture clustering effect on amplitude variation with offset and azimuth analyses

Traditional amplitude variation with offset and azimuth (AVOAz) analysis for fracture characterization extracts fracture properties through analysis of reflection AVOAz to determine anisotropic parameters (e.g., Thomsen’s parameters) that are then related to fracture properties. The validity of this method relies on the basic assumption that a fractured unit can be viewed as an equivalent anisotropic medium. As a rule of thumb, this assumption is taken to be valid when the fracture spacing is less than [Formula: see text]. Under the effective medium assumption, diffractions from individual fractures destructively interfere and only specular reflections from boundaries of a fractured layer can be observed in seismic data. The effective medium theory has been widely used in fracture characterization, and its applicability has been validated through many field applications. However, through numerical simulations, we find that diffractions from fracture clusters can significantly distort the AVOAz signatures when a fracture system has irregular spacing even though the average fracture spacing is much smaller than a wavelength (e.g., [Formula: see text]). Contamination by diffractions from irregularly spaced fractures on reflections can substantially bias the fracture properties estimated from AVOAz analysis and may possibly lead to incorrect estimates of fracture properties. Additionally, through Monte Carlo simulations, we find that fracture spacing uncertainty inverted from amplitude variation with offset (AVO) analysis can be up to 10%–20% when fractures are not uniformly distributed, which should be the realistic state of fractures present in the earth. Also, AVOAz and AVO analysis gives more reliable estimates of fracture properties when reflections at the top of the fractured layer are used compared with those from the bottom of the layer.

Feasibility of time-lapse AVO and AVOA analysis to monitor compaction-induced seismic anisotropy

Hydrocarbon reservoir production generally results in observable time-lapse physical property changes, such as velocity increases within a compacting reservoir. However, the physical property changes that lead to velocity changes can be difficult to isolate uniquely. Thus, integrated hydro-mechanical simulation, stress-sensitive rock physics models and time-lapse seismic modelling workflows can be employed to study the influence of velocity changes and induced seismic anisotropy due to reservoir compaction. We study the influence of reservoir compaction and compartmentalization on time-lapse seismic signatures for reflection amplitude variation with offset (AVO) and azimuth (AVOA). Specifically, the time-lapse AVO and AVOA responses are predicted for two models: a laterally homogeneous four-layer dipping model and a laterally heterogeneous graben structure reservoir model. Seismic reflection coefficients for different offsets and azimuths are calculated for compressional (P–P) and converted shear (P–S) waves using an anisotropic ray tracer as well as using approximate equations for AVO and AVOA. The simulations help assess the feasibility of using time-lapse AVO and AVOA signatures to monitor reservoir compartmentalization as well as evaluate induced stress anisotropy due to changes in the effective stress field. The results of this study indicate that time-lapse AVO and AVOA analysis can be applied as a potential means for qualitatively and semi-quantitatively linking azimuthal anisotropy changes caused by reservoir production to pressure/stress changes.

Interpreting azimuthal Fourier coefficients for anisotropic and fracture parameters

Amplitude variation with offset and azimuth (AVOAz) analysis can be separated into two separate parts: amplitude variation with offset (AVO) analysis and amplitude variation with azimuth (AVAz) analysis. Useful information about fractures and anisotropy can be obtained just by examining the AVAz. The AVAz can be described as a sum of sinusoids of different periodicities, each characterized by its magnitude and phase. This sum is mathematically equivalent to a Fourier series, and hence the coefficients describing the AVAz response are azimuthal Fourier coefficients (FCs). This FC parameterization is purely descriptive. The aim of this paper is to help the interpreter understand what these coefficients mean in terms of anisotropic and fracture parameters for the case of P-wave reflectivity using a linearized approximation. The FC representation is valid for general anisotropy. However, to gain insight into the significance of FCs, more restrictive assumptions about the anisotropy or facture system must be assumed. In the case of transverse isotropic media with a horizontal axis of symmetry, the P-wave reflectivity linearized approximation may be rewritten in terms of azimuthal FCs with the magnitude and phase of the different FCs corresponding to traditional AVAz attributes. Linear slip theory is used to show that the FCs can be interpreted similarly for the cases of a single set of parallel vertical fractures in isotropic media and in transverse isotropic media with a vertical axis of symmetry (VTI). The magnitude of the FCs depends on the fracture weakness parameters and the background media. For the case of vertical fractures in a VTI background, the AVOAz inverse problem is underdetermined, so extra information must be incorporated to determine how the weights are modified due to this background anisotropy. We evaluated this on a 3D data set from northwest Louisiana for which the main target was the Haynesville shale.

Fracture parameter inversion for Marcellus Shale

We inverted P-wave amplitude variation with offset and azimuth (AVOAz) data from the Marcellus Shale to obtain fracture parameters that can fully describe the elastic behavior of fractured rocks with overall symmetry of orthorhombic or monoclinic. AVOAz data from two interfaces, (1) the upper interface between top Marcellus and Stafford limestone and (2) the lower interface between base Marcellus and Onondaga limestone, were used for inversion. To check the validity of our inversion results, fracture parameters for the Marcellus Shale were inverted for each interface using Monte Carlo simulation to include uncertainty in our a priori information, i.e., elastic properties of unfractured rocks that are assumed to be known from well logs. Inversion results appeared robust with respect to uncertainties and converge to the same values for the two inversions. Our results were also consistent with singular value decomposition analysis (resolution matrix).

Nonstretching NMO correction of prestack time-migrated gathers using a matching-pursuit algorithm

Wide-azimuth, long-offset surveys are becoming increasingly common in unconventional exploration plays where one of the key routine processes is maintaining data fidelity at far offsets. The conventional NMO correction that processes the data sample-by-sample results in the well-known decrease of frequency content and amplitude distortion through stretch, which lowers the seismic resolution and hinders [Formula: see text] and amplitude variation with offset and azimuth (AVAz) analysis of the long-offset signal. To mitigate the stretch typically associated with large offsets, we use a matching-pursuit-based normal moveout correction (MPNMO) to reduce NMO-stretch effects in long-offset data. MPNMO corrects the data wavelet-by-wavelet rather than sample-by-sample, thereby avoiding stretch. We apply our technique (1) to a set of synthetic gathers and (2) as part of a residual velocity analysis workflow to a prestack time-migrated data volume acquired over the Northern Chicontepec Basin, Mexico. Test results show that MPNMO can produce relatively nonstretched events and generate higher temporal resolution prestack gathers.

Fracture mapping using seismic amplitude variation with offset and azimuth analysis at the Weyburn CO2 storage site

Cap rock integrity is an essential characteristic of any reservoir to be used for long-term [Formula: see text] storage. Seismic AVOA (amplitude variation with offset and azimuth) techniques have been applied to map HTI anisotropy near the cap rock of the Weyburn field in southeast Saskatchewan, Canada, with the purpose of identifying potential fracture zones that may compromise seal integrity. This analysis, supported by modeling, observes the top of the regional seal (Watrous Formation) to have low levels of HTI anisotropy, whereas the reservoir cap rock (composite Midale Evaporite and Ratcliffe Beds) contains isolated areas of high intensity anisotropy, which may be fracture-related. Properties of the fracture fill and hydraulic conductivity within the inferred fracture zones are not constrained using this technique. The predominant orientations of the observed anisotropy are parallel and normal to the direction of maximum horizontal stress (northeast–southwest) and agree closely with previous fracture studies on core samples from the reservoir. Anisotropy anomalies are observed to correlate spatially with salt dissolution structures in the cap rock and overlying horizons as interpreted from 3D seismic cross sections.

Seismic modelling of a fractured carbonate reservoir in Abu Dhabi, United Arab Emirates

ABSTRACT The problem of identifying and quantifying the brittle deformation of carbonate reservoirs both in the United Arab Emirates (UAE) and elsewhere is addressed. Naturally occurring fractures may substantially increase or decrease the permeability and porosity of reservoirs, and therefore knowledge of location, orientation, density and connectivity of fractures is required to optimise hydrocarbon production. A rock containing parallel fractures can be seismically anisotropic, provided the vertical and horizontal extent and spacing of the fractures is small compared to the seismic wavelength. Seismic anisotropy may be detectable from attributes of pre-stack 3-D seismic data including reflection amplitude variation with offset and azimuth (AVOA). However, in carbonates seismic-velocity anisotropy can result from many different factors, including present-day horizontal stress anisotropy, sedimentological features such as clinoforms, and geological structure. We present a methodology for determining whether a proposed reservoir-fracture model is consistent with the observed seismic data. The approach includes modelling the seismic anisotropy where an essential input parameter is the compliance of the fractures. Since so little is known about this key parameter, we determine an upper bound to fracture compliance from well data and existing laboratory and field data and consequently obtain an upper bound to the seismic anisotropy that might be detected. We apply our method to data from an onshore carbonate oilfield in Abu Dhabi, United Arab Emirates, where analysis of core, log and 3-D post-stack seismic data indicates that open or partially open fractures may be pervasive and could have a dominant influence on reservoir production. Due to poor AVOA data quality our results are inconclusive. However, this case study is a demonstration of the methodology that could be applied elsewhere.

Fracture-porosity inversion from P-wave AVOA data along 2D seismic lines: An example from the Austin Chalk of southeast Texas

Vertical aligned fractures can significantly enhance the horizontal permeability of a tight reservoir. Therefore, it is important to know the fracture porosity and direction in order to develop the reservoir efficiently. P-wave AVOA (amplitude variation with offset and azimuth) can be used to determine these fracture parameters. In this study, I present a method for inverting the fracture porosity from 2D P-wave seismic data. The method is based on a modeling result that shows that the anisotropic AVO (amplitude variation with offset) gradient is negative and linearly dependent on the fracture porosity in a gas-saturated reservoir, whereas the gradient is positive and linearly dependent on the fracture porosity in a liquid-saturated reservoir. This assumption is accurate as long as the crack aspect ratio is less than 0.1 and the ratio of the P-wave velocity to the S-wave velocity is greater than 1.8 — two conditions that are satisfied in most naturally fractured reservoirs. The inversion then uses the fracture strike, the crack aspect ratio, and the ratio of the P-wave velocity to the S-wave velocity to invert the fracture porosity from the anisotropic AVO gradient after inferring the fluid type from the sign of the anisotropic AVO gradient. When I applied this method to a seismic line from the oil-saturated zone of the fractured Austin Chalk of southeast Texas, I found that the inversion gave a median fracture porosity of 0.21%, which is within the fracture-porosity range commonly measured in cores from the Austin Chalk.

Seismic anisotropy as an indicator of reservoir quality in siliciclastic rocks

AbstractImproving the accuracy of subsurface imaging is commonly the main incentive for including the effects of anisotropy in seismic processing. However, the anisotropy itself holds valuable information about rock properties and, as such, can be viewed as a seismic attribute. Here we summarize results from an integrated project that explored the potential to use observations of seismic anisotropy to interpret lithological and fluid properties (the SAIL project). Our approach links detailed petrofabric analyses of reservoir rocks, laboratory based measurements of ultrasonic velocities in core samples, and reservoir-scale seismic observations. We present results for the Clair field, a Carboniferous–Devonian reservoir offshore Scotland, west of the Shetland Islands. The reservoir rocks are sandstones that are variable in composition and exhibit anisotropy on three length-scales: the crystal, grain and fracture scale.We have developed a methodology for assessing crystal-preferred-orientation (CPO) using a combination of electron back-scattered diffraction (EBSD), X-ray texture goniometry (XRTG) and image analysis. Modal proportions of individual minerals are measured using quantitative X-ray diffraction (QXRD). These measurements are used to calculate the intrinsic anisotropy due to CPO via Voigt-Reuss-Hill averaging of individual crystal elasticities and their orientations. The intrinsic anisotropy of the rock is controlled by the phyllosilicate content and to a lesser degree the orientation of quartz and feldspar; the latter can serve as a palaeoflow indicator. Our results show remarkable consistency in CPO throughout the reservoir and allow us to construct a mathematical model of reservoir anisotropy. A comparison of CPO-predicted velocities and those derived from laboratory measurements of ultrasonic signals allows the estimation of additional elastic compliance terms due to grain-boundary interactions. The results show that the CPO estimates are good proxies for the intrinsic anisotropy of the clean sandstones. The more micaceous rocks exhibit enhanced anisotropy due to interactions between the phyllosilicate grains. We then compare the lab-scale predictions with reservoir-scale measurements of seismic anisotropy, based on amplitude variation with offset and azimuth (AVOA) analysis and non-hyperbolic moveout. Our mathematical model provides a foundation for interpreting the reservoir-scale seismic data and improving the geological modelling of complex reservoirs. The observed increases in AVOA signal with depth can only be explained with an increase in fracturing beneath the major unit boundaries, rather than a change in intrinsic CPO properties. In general, the style and magnitude of anisotropy in the Clair field appears to be indicative of reservoir quality.

Fracture characterization at Valhall: Application of P‐wave amplitude variation with offset and azimuth (AVOA) analysis to a 3D ocean‐bottom data set

The delineation and characterization of fracturing is important in the successful exploitation of many hydrocarbon reservoirs. Such fracturing often occurs in preferentially aligned sets; if the fractures are of subseismic scale, this may result in seismic anisotropy. Thus, measurements of anisotropy from seismic data may be used to delineate fracture patterns and investigate their properties. Here fracture‐induced anisotropy is investigated in the Valhall field, which lies in the Norwegian sector of the North Sea. This field is a chalk reservoir with good porosity but variable permeability, where fractures may significantly impact production, e.g., during waterflooding. To investigate the nature of fracturing in this reservoir, P‐wave amplitude variation with offset and azimuth (AVOA) is analyzed in a 3D ocean‐bottom cable (OBC) data set. In general, 3D ocean‐bottom seismic (OBS) acquisition leads to patchy coverage in offset and azimuth, and this must be addressed when considering such data. To overcome this challenge and others associated with 3D OBS acquisition, a new method for processing and analysis is presented. For example, a surface fitting approach, which involves analyzing azimuthal variations in AVO gradients, is used to estimate the orientation and magnitude of the fracture‐induced anisotropy. This approach is also more widely applicable to offset‐azimuth analysis of other attributes (e.g., traveltimes) and any data set where there has been true 3D data acquisition, land or marine. Using this new methodology, we derive high‐resolution maps of P‐wave anisotropy from the AVOA analysis for the top‐chalk reflection at Valhall. These anisotropy maps show coherent but laterally varying trends. Synthetic AVOA modeling, using effective medium models, indicates that if this anisotropy is from aligned fracturing, the fractures are likely liquid filled with small aspect ratios and the fracture density must be high. Furthermore, we show that the fracture‐normal direction is parallel to the direction of most positive AVO gradient. In other situations the reverse can be true, i.e., the fracture‐normal direction can be parallel to the direction of the most negative AVO gradient. Effective medium modeling or comparisons with anisotropy estimates from other approaches (e.g., azimuthal variations in velocity) must therefore be used to resolve this ambiguity. The inferred fracture orientations and anisotropy magnitudes show a degree of correlation with the positions and alignments of larger scale faults, which are estimated from 3D coherency analysis. Overall, this work demonstrates that significant insight may be gained into the alignment and character of fracturing and the stress field variations throughout a field using this high‐resolution AVOA method.

Predicting the seismic implications of salt anisotropy using numerical simulations of halite deformation

In the past, the potential for seismic anisotropy in salt structures and its effect on their seismic imaging has received little attention. We consider the plausibility of salt anisotropy through linked numerical studies of salt deformation and its seismic consequences. Numerical models are used to predict lattice preferred orientations (LPOs) in halite polycrystalline aggregates subjected to axial extension and simple shear. The elastic constants for the deformed polycrystalline aggregate are then calculated. Simple models representing a salt sill and the stem of a diapir are created using these elastic constants. Ray tracing is used to investigate the effects of halite LPO on the propagation of seismic waves. The results suggest that salt anisotropy can cause significant traveltime effects and could lead to significant errors in seismic interpretation in salt environments if this anisotropy is ignored. We also investigate potential amplitude variation with offset and azimuth (AVOA) for the reflection from the top and bottom of an anisotropic salt sill. Ray paths with a shear‐wave leg within the salt display strong AVOA effects with a clear four‐fold symmetry.