Deep sonic imaging is a method to analyze geologic structures around a borehole using waveforms acquired by sonic logging tools. In the past few years, processing methods for deep sonic imaging have been greatly improved in both accuracy and performance. The matched filter approach effectively attenuates flexural waves and deconvolves the chirp source signal. Beamform processing enhances event signals using the azimuthal receivers of the tool and removes the effects of tool rotations. The trial-reflector migration, which is a Kirchhoff migration with coherence weighting for virtual reflectors, provides high-resolution images. A new structural analysis method continuously picks curved reflectors using crosscorrelation and resolves 180° ambiguities of reflector azimuths. The total workflow of deep sonic imaging is reviewed, and a field example is presented using sonic data for structural imaging around a geothermal well.

Sonic datasets acquired in differently oriented wells are combined via clustering on the basis of independent measurements. The clusters are then inverted to yield many sets of independent transversely isotropic (TI) constants along with the associated bulk density, neutron porosity, and resistivity parallel to bedding. Together, these results comprise a database of prior information that can be used for Bayesian-type inversions on future wells and datasets in the case study area.

Analysis of single-well sonic measurements to determine formation TI elastic parameters has traditionally been done using deterministic models with multiple, simplistic assumptions using only vertical or horizontal wells with flat structural dip. Here a probabilistic Bayesian-type inversion method is shown, which provides a flexible solution for any wellbore orientation solving for all five TI (transversely isotropic) parameters. This inversion is guided by prior information, which may be; core tests, borehole seismic survey results, offset well data or a public database. The approach demonstrated here uses prior information of TI elastic properties to determine a consistent model at each depth. The inversion uses all sonic slownesses, compressional, fast and slow shear, as well as Stoneley shear and density to provide a continuous output of Thomsen's parameters and anisotropic mechanical properties at each depth. The results are consistent with offset well data as well as walk-above VSP velocities obtained in the same well. This technique was applied on a prominent and thick shale formation, which is present throughout UAE. Most of the wells drilled in UAE penetrate through this shale formation which is locally unstable for drilling, and is a prominent seismic reflector which directly overlies the reservoir. Accurate geomechanical characterization of this shale formation is critical as more wells are drilled at high angles with the application of full 3D finite-element modeling. Similarily the velocity models used for pre-stack depth migration (PSDM) and seismic well tie require accurate anisotropic TI parameters. This workflow is new and applicable to any well orientation or structural dip and yields results that are consistent with offset sonic and borehole seismic measurements. Application of this method will have a profound impact on geophysical velocity and geomechanical model building methods and results.

The effect of anisotropy on sonic measurements within layered formations has an impact in geomechanics and geophysics workflows. A new single-well workflow is presented that uses a probabilistic approach using prior information to provide a complete continuous characterization of the transverse isotropic (TI) parameters. The workflow applies to any well orientation or structural dip and yields results that are consistent with prior information from offset wells, core measurements or walk-away vertical seismic profile (VSP) results. Analysis of single-well sonic measurements is predominately done using deterministic models for which the orientation of the measurements must be aligned with the layering; in other words, vertical or horizontal (not deviated) wellbores must be used for flat structural dip. In addition, such models depend on strict assumptions for using the measurements to predict the missing parameters because there are not enough measured slownesses in a single well to determine the five independent moduli. Multiwell models depend on variable well orientations, usually where a combination of a vertical with multiple deviated wells are needed to characterize the relative change in slowness with dip for each associated slowness. Often, the acoustic anisotropy must be determined before these deviated wells are drilled and evaluated to impact well placement, drilling design, or stimulation plans. The approach demonstrated herein uses prior information of TI elastic properties to determine a consistent model at each depth. The inversion uses all sonic slownesses, compressional, fast and slow shear, as well as Stoneley shear along with the fast shear azimuth and density to provide a continuous output of either stiffness moduli or velocities at each depth. The prior information can be from multiple sources such as core tests (dynamic or static), borehole seismic survey results, offset well data, or a public core database. A case study from an offshore field in Abu Dhabi, UAE, is presented to demonstrate this new workflow using sonic and walk-away VSP data for input to velocity model calibration for prestack depth migration. Understanding the impact of anisotropy on wellbore stability calculation for adjacent fields is also of interest. Presentation Date: Thursday, October 18, 2018 Start Time: 8:30:00 AM Location: 205A (Anaheim Convention Center) Presentation Type: Oral

Sonic slowness measurements from a vertical well are augmented with auxiliary data to provide plausible logs of fractured VTI (FVTI) moduli. The auxiliary data come from published core measurements, described by a data base mean vector containing five VTI parameters and an associated covariance matrix. A Bayesian formalism is used to bring in the auxiliary data. The inversion seeks an FVTI medium that fits the sonic measurements while honoring the data base, exploiting correlations between the in situ and auxiliary measurements. The data base is used to constrain VTI tensor components for the background medium and in both symmetry planes. A seven-parameter model vector (VP, VS, E, A, G, δV, δN) is found through nonlinear optimization; posterior uncertainties are determined using MCMC. Together with the shear sonic fast azimuth, a depth-dependent monoclinic medium can be constructed and upscaled to seismic frequencies. Applications include models for seismic and geomechanical simulation, and background priors for orthorhombic tomography and AVA vs. azimuth inversion. Presentation Date: Monday, October 15, 2018 Start Time: 1:50:00 PM Location: 212A (Anaheim Convention Center) Presentation Type: Oral

Summary The Hejre oil and gas field is located in the Danish Central Graben, a shallow water part of the central North Sea. The reservoir lies at depths below 5 km in a high-temperature (172°C) and high-pressure (1 kbar) environment. Seismic resolution is relatively poor due to absorption in the overburden, multiples and distortion from a complex structure. Anisotropic depth processing improved the seismic quality but the anisotropy uncertainty remained high. In order to measure elastic anisotropy in-situ, reduce the velocity model uncertainties and allow improvements in anisotropic surface seismic processing, comprehensive Walkaway VSP and modern wireline sonic logging surveys were planned in a new deviated production well drilled in 2016. This project represents a first step in the velocity model calibration workflow and highlights the importance of integrating measurements taken at different scales: cores, sonic, borehole and surface seismic, in order to understand the elastic anisotropy of the rocks drilled and allow reducing the uncertainties in the seismic velocity models used for depth imaging.

We study the mechanical deformation of fractures under normal stress, via tangent and specific fracture stiffnesses, for different length scales using numerical simulations and analytical insights. First, we revisit an equivalent elastic layer model that leads to two expressions: the tangent stiffness is the sum of an intrinsic stiffness and the normal stress, and the specific stiffness is the tangent stiffness divided by the fracture aperture at current stress. Second, we simulate the deformation of rough fractures using a boundary element method where fracture surfaces represented by elastic asperities on an elastic half-space follow a self-affine distribution. A large number of statistically identical parent fractures are generated, from which sub-fractures of smaller dimensions are extracted. The self-affine distribution implies that the stress-free fracture aperture increases with fracture length with a power law in agreement with the chosen Hurst exponent. All simulated fractures exhibit an increase in the specific stiffness with stress and an average decrease with increase in length consistent with field observations. The simulated specific and tangent stiffnesses are well described by the equivalent layer model provided the intrinsic stiffness slightly decreases with fracture length following a power law. By combining numerical simulations and the analytical model, the effect of scale and stress on fracture stiffness measures can be easily separated using the concept of intrinsic stiffness. We learn that the primary reason for the variability in specific stiffness with length comes from the fact that the typical aperture of the self-affine fractures itself scales with the length of the fractures.

PreviousNext No AccessSEG Technical Program Expanded Abstracts 2015Sonic-derived TI anisotropy as a guide for seismic velocity model buildingAuthors: Maurizio FerlaFerdinanda PampuriMargherita CorciuloJeroen JockerErik WielemakerMaurizio FerlaEniSearch for more papers by this author, Ferdinanda PampuriEniSearch for more papers by this author, Margherita CorciuloEniSearch for more papers by this author, Jeroen JockerSchlumbergerSearch for more papers by this author, and Erik WielemakerSchlumbergerSearch for more papers by this authorhttps://doi.org/10.1190/segam2015-5898796.1 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract While accurate velocity models are critical for seismic images representative of the subsurface, the process of determining the correct velocity model is non-unique. Seismic images may therefore come with significant uncertainty, especially in fields with complex structure in combination with a complex velocity field. In turn, this uncertainty leads to wells missing their targets as well as increased drilling risks. Borehole sonic-derived anisotropy magnitudes may provide constraints to the seismic velocity model, but the applicability of sonic-derived anisotropy to surface seismic data is unclear. In this paper, the consistency between a sonic-derived anisotropic velocity model and surface seismic data is analyzed by comparing NMO corrections on basis of a seismic-only model versus a seismic model guided by sonic-derived anisotropy. For the complex seismic dataset presented in the examples it is observed how (unlike the sonic-guided model) the seismic-only model is not able to flatten the gathers at far offsets. The process of deriving TI parameters from borehole sonic data is relatively efficient (compared to the seismic equivalent), and their use as a guide during the construction of the seismic velocity model results in subsurface images that can be established with greater confidence. Keywords: TTI, depth migration, rock physics, borehole geophysics, anisotropyPermalink: https://doi.org/10.1190/segam2015-5898796.1FiguresReferencesRelatedDetails SEG Technical Program Expanded Abstracts 2015ISSN (print):1052-3812 ISSN (online):1949-4645Copyright: 2015 Pages: 5634 publication data© 2015 Published in electronic format with permission by the Society of Exploration GeophysicistsPublisher:Society of Exploration Geophysicists HistoryPublished Online: 19 Aug 2015 CITATION INFORMATION Maurizio Ferla, Ferdinanda Pampuri, Margherita Corciulo, Jeroen Jocker, and Erik Wielemaker, (2015), "Sonic-derived TI anisotropy as a guide for seismic velocity model building," SEG Technical Program Expanded Abstracts : 351-355. https://doi.org/10.1190/segam2015-5898796.1 Plain-Language Summary KeywordsTTIdepth migrationrock physicsborehole geophysicsanisotropyPDF DownloadLoading ...

Heterogeneity is a common phenomenon that needs to be taken into account when characterizing the elastic anisotropic properties of formations. This can be done successfully through a methodology involving careful binning of the velocity data on the basis of independent, petrophysical information, followed by an inversion process that is carried out on each bin individually. The resulting table of anisotropic parameters per bin can then be used to derive, among other results, correlations between formation petrophysical and anisotropic properties. A workflow was successfully applied to determine the elastic, transversely isotropic properties of heterogeneous sand-shale sequences. The results of the methodology have significant practical implications. One of these is that synthetics based on the anisotropy-corrected deviated well logs yield stronger and more apparent reflections, as well as a significantly different time-depth relation. Additional applications include the use of the inversion workflow results as inputs into anisotropic seismic velocity models and AVOs.

Inverting borehole sonic data for anisotropic elastic parameters requires data acquired in, at least, two different orientations. In practice this often means combining acquisitions from two offset wells, which is only straightforward if the encountered formations are laterally continuous. If wells do not tie laterally, or if data acquired at different depths in vertically heterogeneous strata need to be combined, then an inversion strategy is required that explicitly takes heterogeneity into account. This short note outlines such a strategy on the basis of borehole sonic and conventional petrophysical data, structural information, and well surveys. A new and sophisticated workflow was developed to estimate TI anisotropic parameters from borehole sonic logs, adopting a smart data clustering approach. Among other things, the output consists of elastic properties as a function of independently acquired data such as shale volume and density. In turn, these expressions constitute a model that is driven by measurements instead of assumptions, that can be established also in the presence of lateral and vertical heterogeneity, and that can be applied in neighboring wells where the amount of sonic data are insufficient for a complete inversion. Introduction An accurate characterization of the anisotropic elastic properties of subsurface formations is highly relevant to both geomechanical (e.g., hydraulic fracture design and simulation) and geophysical workflows (e.g., seismic migration and wellto-seismic tie). Borehole sonic measurements represent a rich source of information regarding the (dynamic) elastic behavior of formations, and several outstanding papers have been devoted to discussing the inversion of sonic data in order to extract a multitude of elastic parameters. In most published cases, the characterized formations are assumed to be well-described by a transversely isotropic (TI) model consisting of up to five independent parameters, and inversion results are commonly reported following Thomsen’s (1986) notation (i.e., in terms of VP0, VS0, , , and ). Likewise, this note will also follow Thomsen’s convention, as well as the use of the TI model to characterize subsurface strata. Depending on the relative dip, i.e., the angle between the well and the TI symmetry axis, at a single depth up to four independent measurements can be acquired by advanced sonic logging tools (e.g. Walsh et al., 2007). Four measurements are not enough to fully constrain five independent TI parameters, and so, invariably, single-well/single-depth measurements need to be complemented by core measurements, or by TI models such as ANNIE (Schoenberg et al., 1996) or Sayers’ aligned clay platelet model (Sayers, 2005). However, core data points are discontinuous, expensive and take long to acquire, while the application of a model in a particular environment may be hard to justify. Hence, the industry has looked for ways to combine sonic data coming from multiple wells at different orientations, and to invert those data without the use of TI models to arrive at estimates for the five independent TI constants. Hornby et al. (2003) invert compressional data acquired in twelve differently oriented wells to arrive at estimates for  and . More recently, Horne et al. (2012) and Miller et al. (2012) obtain all five independent TI parameters by inverting compressional and dipole shear data acquired in a typical shale gas layout (vertical pilot well and a rapidly deviating sidetrack), assuming homogeneity over the interval (~150 vertical meters) of interest. From the logs illustrated in all three referenced cases, the characterized formations are clearly significantly heterogeneous, but (presumably) because the primary interest is in obtaining large scale anisotropy estimates for geophysical applications, no attempt is made to take heterogeneity into account in the inversion process. However, spatial variations in properties such as shale volume and density can have a

Summary Inverting borehole sonic data for anisotropic elastic parameters requires data acquired in, at least, two different orientations. In practice this often means combining acquisitions from two offset wells, which is only straightforward if the encountered formations are laterally continuous. If wells do not tie laterally, or if data acquired at different depths in vertically heterogeneous strata need to be combined, then an inversion strategy is required that explicitly takes heterogeneity into account. This short note outlines such a strategy on the basis of borehole sonic and conventional petrophysical data, structural information, and well surveys. A new and sophisticated workflow was developed to estimate TI anisotropic parameters from borehole sonic logs, adopting a smart data clustering approach. Among other things, the output consists of elastic properties as a function of independently acquired data such as gamma ray and density. In turn, these expressions constitute a model that is driven by measurements instead of assumptions, that can be established also in the presence of lateral and vertical heterogeneity, and that can be applied in neighboring wells where the amount of sonic data are insufficient for a complete inversion.

Abstract Inverting borehole sonic data for anisotropic elastic parameters requires data acquired in, at least, two different orientations. In practice this often means combining acquisitions from two offset wells, which is only straightforward if the encountered formations are laterally continuous. If wells do not tie laterally, or if data acquired at different depths in vertically heterogeneous strata need to be combined, then an inversion strategy is required that explicitly takes heterogeneity into account. This short note outlines such a strategy on the basis of borehole sonic and conventional petrophysical data, structural information, and well surveys. A new and sophisticated workflow was developed to estimate TI anisotropic parameters from borehole sonic logs, adopting a smart data clustering approach. Among other things, the output consists of elastic properties as a function of independently acquired data such as shale volume and density. In turn, these expressions constitute a model that is driven by measurements instead of assumptions, that can be established also in the presence of lateral and vertical heterogeneity, and that can be applied in neighboring wells where the amount of sonic data are insufficient for a complete inversion.

We revisit an exact, quasi-static, semianalytical solution for the effective tube-wave modulus for any borehole orientation relative to an anisotropic medium of arbitrary symmetry and strength. This exact solution agrees very well with the one computed from a finite-element model (FEM). We compare the exact solution with several analytical approximations for well deviations from vertical to horizontal and for different transversely isotropic media. For elliptic media, we show that the Rice and Chi-Tang approximations are in accordance with the exact solution because they depend only on the horizontal and vertical shear-wave velocity. For anelliptic media, we show that the maximum difference between the exact solution and the Norris-Sinha or Chi-Tang perturbation approximation becomes increasingly significant with increasing degree of anellipticity and shear-wave anisotropy with a maximum error of 5%, 10%, and 18% for Thomsen parameters less than 0.25, 0.4, and 0.6, respectively.

We present a rigorous validation of the analytical Amadei solution for the stress concentration around an arbitrarily orientated borehole in general anisotropic elastic media. First, we revisit the theoretical framework of the Amadei solution and present analytical insights that show that the solution does indeed contain all special cases of symmetry, contrary to previous understanding, provided that the reduced strain coefficients β11 and β55 are not equal. It is shown from theoretical considerations and published experimental data that the β11 and β55 are not equal for realistic rocks. Second, we develop a 3D finite element elastic model within a hybrid analytical–numerical workflow that circumvents the need to rebuild and remesh the model for every borehole and material orientation. Third, we show that the borehole stresses computed from the numerical model and the analytical solution match almost perfectly for different borehole orientations (vertical, deviated and horizontal) and for several cases involving isotropic, transverse isotropic and orthorhombic symmetries. It is concluded that the analytical Amadei solution is valid with no restriction on the borehole orientation or the symmetry of the elastic anisotropy.

The presence of elastic anisotropy has implications for a wide range of practical applications in both the geophysical as well as geomechanical domain. For instance, stress magnitudes and orientations can be very different in anisotropic media as compared to isotropic media. Hooke’s law can be used to calculate stresses along the wellbore, but in order to do so the elastic properties of the formation are required. In the case of Transverse Isotropic (TI) formations such as shales, the number of independent elastic coefficients is five. A commonly used source for information on these five parameters is comprised of borehole sonic data. Nevertheless, even in a deviated well the number of borehole sonic measurements is at most four, thus necessitating the integration of single-well borehole sonic data with relevant data coming from an alternative source. A case study is presented where sonic data from a single well were combined with offset well data in order to fully characterize the overburden shale in the North Sea Eldfisk field. The results were subsequently used to determine the minimum horizontal stress profile along the well. This stress profile was compared with fracture gradients derived using more conventional models such as Eaton’s and M&K. It was concluded that stress profiles on the basis of a full anisotropic model provide a natural fit with wellbore stability observations without requiring boost factors or the

We present a rigorous validation of the analyticalAmadei solution for the stress concentration around arbitrarily orientated borehole in general anisotropic elastic media. First, we revisit the theoretical framework of the Amadei solution and present analytical insights that show that the solution does indeed contain all special cases of symmetry, contrary to previous understanding, provided that the reduced strain coefficients β11 and β55 are not equal. It is shown from theoretical considerations and published experimental data that the β11 and β55 are not equal for realistic rocks. Second, we develop a 3D finite-element elastic model within a hybrid analyticalnumerical workflow that circumvents the need to rebuild and remesh the model for every borehole and material orientation. Third, we show that the borehole stresses computed from the numerical model and the analytical solution match almost perfectly for different borehole orientations (vertical, deviated and horizontal) and for several cases involving isotropic and transverse isotropic symmetries. It is concluded that the analytical Amadei solution is valid with no restrictions on the borehole orientation or elastic anisotropy symmetry.