The aim of this paper is to understand the seismic anisotropy of the overburden shale in an oilfield in the North West Shelf of Western Australia. To this end, we first find the orientation of the symmetry axis of a spherical shale sample from measurements of ultrasonic P-wave velocities in 132 directions at the reservoir pressure. After transforming the data to the symmetry axis coordinates, we find Thomsen's anisotropy parameters d and ? using these measurements and measurements of the shear-wave velocity along the symmetry axis from a well log. To find these anisotropy parameters, we use a very fast simulated re-annealing algorithm with an objective function that contains only the measured ray velocities, their numerical derivatives and the unknown elasticity parameters. The results show strong elliptical anisotropy in the overburden shale. This approach produces smaller uncertainty of Thomsen parameter d than more direct approaches.

I present an algorithm that uses cross-dipole wireline data only in order to estimate the HTI stiffness tensor for sandstone formations under in-situ asymmetric lateral (azimuthal) stress conditions. The algorithm is based on the generalization of terms “excess compliance” and “fracture weakness” developed within the linear slip interface theory for fractured rocks and is applied here to describe the effect of grain contacts in loose sandstones. I introduce the term “plane of weakness” being oriented (aligned) orthogonal to the minimal horizontal principal stress direction in order to describe the overall effective weakness of sandstone caused by the different principal stresses. For the quantification of this phenomenon I use the anisotropic Gassmann model. As a result I am able to calculate a HTI stiffness tensor for the interval length of a saturated sandstone formation and the respective Thomsen’s parameters. The input data required for these calculations have to be provided by wireline logging and will consist of porosity, density, P-wave velocity, fast and slow shear wave velocities and oil-water saturation ratio. The algorithm in its current form is applicable to sandstone reservoirs only. Its limitation is based on two assumptions, which state that all the measured anisotropy is induced by the present stress in sandstone and that the unstressed sandstone would be nearly isotropic. From a technical viewpoint this algorithm can be implemented fairly easily in data acquisition and interpretation software relying on correct estimation of anisotropy parameters. It is also cheap because it does not require any additional measurements apart from the cross-dipole logging.

Our aim is to understand the stress-dependent seismic anisotropy of the overburden shale in an oil field in the North West Shelf of Western Australia. We analyze data from measurements of ultrasonic P-wave velocities in 132 directions for confining pressures of 0.1–400 MPa on a spherical shale sample. First, we find the orientation of the symmetry axis, assuming that the sample is transversely isotropic, and then transform the ray velocities to the symmetry axis coordinates. We use two parameterizations of the phase velocity; one, in terms of the Thomsen anisotropy parameters α, β, ɛ, δ as the main approach, and the other in terms of α, β, η, δ. We invert the ray velocities to estimate the anisotropy parameters α, ɛ, δ, and η using a very fast simulated reannealing algorithm. Both approaches result in the same estimation for the anisotropy parameters but with different uncertainties. The main approach is robust but produces higher uncertainties, in particular for η, whereas the alternative approach is unstable but gives lower uncertainties. These approaches are used to find the anisotropy parameters for the different confining pressures. The dependency of P-wave velocity, α, on pressure has exponential and linear components, which can be contributed to the compliant and stiff porosities. The exponential dependence at lower pressures up to 100 MPa corresponds to the closure of compliant pores and microcracks, whereas the linear dependence at higher pressures corresponds to contraction of the stiff pores. The anisotropy parameters ɛ and δ are quite large at lower pressures but decrease exponentially with pressure. For lower pressures up to 10 MPa, δ always is larger than ɛ; this trend is reversed for higher pressures. Despite the hydrostatic pressure, the symmetry axis orientation changes noticeably, in particular at lower pressures.

In this work we interpret the data showing unusually strong velocity dispersion of P-waves (up to 30%) and attenuation in a relatively narrow frequency range. The cross-hole and VSP data were measured in a reservoir, which is in the porous zone of the Silurian Kankakee Limestone Formation formed by vertical fractures within a porous matrix saturated by oil, and gas patches. Such a medium exhibits significant attenuation due to wave-induced fluid flow across the interfaces between different types of inclusions (fractures, fluid patches) and background. Other models of intrinsic attenuation (in particular squirt flow models) cannot explain the amount of observed dispersion when using realistic rock properties. In order to interpret data in a satisfactory way we develop a superposition model for fractured porous rocks accounting also for the patchy saturation effect.

PreviousNext No AccessBeijing 2009 International Geophysical Conference and Exposition, Beijing, China, 24–27 April 2009Stress induced anisotropy in sandstone reservoir and shale overburden ‐ AVO modelingAuthors: Miroslav BrajanovskiDariush NadriBoris GurevichAndrej BonaMiroslav BrajanovskiCurtin University of TechnologySearch for more papers by this author, Dariush NadriCSIRO PetroleumSearch for more papers by this author, Boris GurevichCurtin University of TechnologySearch for more papers by this author, and Andrej BonaCurtin University of TechnologySearch for more papers by this authorhttps://doi.org/10.1190/1.3603719 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract The influence of asymmetric horizontal stress on seismic signatures was investigated. We targeted the thin sandstone reservoir below the thick shale overburden. The presented data are based on the laboratory approach, as well as theoretical computations. Laboratory measurements were carried out on shale spherical samples from overburden under confining stress up to 400MPa, by means of ultrasonic soundings in 132 independent directions. Such an approach enables to determine 3D P‐wave elastic anisotropy. From the measured velocities, the stiffness tensor was inverted, assuming VTI symmetry approximation. Since the sandstones were partly unconsolidated, it was not possible to take ultrasonic measurements, so we invented a method (algorithm) for stress induced anisotropy estimation using only cross‐dipole logging data, which allows us to make HTI approximation in the presence of asymmetric horizontal stress. These two results give the possibility for anisotropic correction in AVO analysis.Permalink: https://doi.org/10.1190/1.3603719FiguresReferencesRelatedDetailsCited byEffects of sand-shale anisotropy on amplitude variation with angle (AVA) modelling: The Sawan gas field (Pakistan) as a key case-study for South Asia's sedimentary basinsJournal of Asian Earth Sciences, Vol. 147 Beijing 2009 International Geophysical Conference and Exposition, Beijing, China, 24–27 April 2009ISBN (print):978-1-56080-284-6ISSN (online):2159-6832Copyright: 2009 Pages: publication data© 2009 Copyright © 2009 Society of Exploration Geophysicists and China Petroleum SocietyPublisher:Society of Exploration Geophysicists HistoryPublished Online: 28 Jun 2011 CITATION INFORMATION Miroslav Brajanovski, Dariush Nadri, Boris Gurevich, and Andrej Bona, (2009), "Stress induced anisotropy in sandstone reservoir and shale overburden ‐ AVO modeling," SEG Global Meeting Abstracts : 194-194. https://doi.org/10.1190/1.3603719 Plain-Language Summary PDF DownloadLoading ...

The analysis of rock anisotropy in terms of seismic velocities and within the context of rock-physics (Biot-Gassmann theory of poroelasticity) provides important information for the evaluation of the stress state (tensors) of rocks, detection of the directions of formation weaknesses, helps in the estimation of overall permeability and failure prediction. Understanding the influence of stress and pore pressure on seismic velocities is important for 4-D reflection seismic interpretation, AVO analysis and reservoir modeling. Laboratory measurements were carried out on spherical shale samples from the overburden under confining stress up to 400 MPa, by means of ultrasonic soundings in 132 independent directions. Such an approach enables the estimation of 3-D elastic anisotropy. Assuming VTI symmetry approximation, from the measured velocities the stiffness tensor was inverted. Since the sandstones were partly unconsolidated, it was not possible to take ultrasonic measurements . To overcome this, we developed a method for stress induced azimuthal anisotropy estimation using only cross-dipole logging data. These results give the possibility for anisotropic correction in AVO analysis.

The analysis of rock anisotropy in terms of seismic velocities and within the context of rock physics (Biot-Gassmann theory of poroelasticity) provides important information for the evaluation of the stress state (tensors) of rocks, detection of the directions of formation weaknesses, helps in the estimation of overall permeability and failure prediction. Understanding the influence of stress and pore pressure on seismic velocities is important for 4-D reflection seismic interpretation, AVO analysis and reservoir modeling. Laboratory measurements were carried out on spherical shale samples from the overburden under confining stress up to 400 MPa, by means of ultrasonic soundings in 132 independent directions. Such an approach enables the estimation of 3-D elastic anisotropy. Since the sandstones were partly unconsolidated, it was not possible to take ultrasonic measurements. To overcome this, we developed a method for stress induced azimuthal anisotropy estimation using only cross-dipole logging data. These results give the possibility for anisotropic correction in AVO analysis.

From the P-wave traveltime measurements over a spherical shale sample at 40 MPa we find the symmetry axis. We transform the ray velocities from the measurement coordinate system to the symmetry axis coordinate system. Assuming transverse isotropy symmetry

ABSTRACTNatural fractures in hydrocarbon reservoirs can cause significant seismic attenuation and dispersion due to wave induced fluid flow between pores and fractures. We present two theoretical models explicitly based on the solution of Biot's equations of poroelasticity. The first model considers fractures as planes of weakness (or highly compliant and very thin layers) of infinite extent. In the second model fractures are modelled as thin penny‐shaped voids of finite radius. In both models attenuation is a result of conversion of the incident compressional wave energy into the diffusive Biot slow wave at the fracture surface and exhibits a typical relaxation peak around a normalized frequency of about 1. This corresponds to a frequency where the fluid diffusion length is of the order of crack spacing for the first model and the crack diameter for the second. This is consistent with an intuitive understanding of the nature of attenuation: when fractures are closely and regularly spaced, the Biot's slow waves produced by cracks interfere with each other, with the interference pattern controlled by the fracture spacing. Conversely, if fractures are of finite length, which is smaller than spacing, then fractures act as independent scatterers and the attenuation resembles the pattern of scattering by isolated cracks. An approximate mathematical approach based on the use of a branching function gives a unified analytical framework for both models.

PreviousNext No AccessBeijing 2009 International Geophysical Conference and Exposition, Beijing, China, 24–27 April 2009Estimation of elasticity tensor from the inversion of traveltimes in spherical shale samplesAuthors: Dariush NadriAndrej BónaMiroslav BrajanovskyDariush NadriCSIRO PetroleumSearch for more papers by this author, Andrej BónaCurtin University of TechnologySearch for more papers by this author, and Miroslav BrajanovskyCurtin University of TechnologySearch for more papers by this authorhttps://doi.org/10.1190/1.3603774 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InReddit Abstract From P‐wave traveltime measurements in a spherical shale sample at 40 MPa we find the symmetry axis. We transform the ray velocities from the measurement coordinate system to the symmetry axis coordinate system. Assuming transverse isotropy symmetry, we estimate the elasticity tensor using a very fast simulated annealing algorithm followed by a quasi Newton method.Permalink: https://doi.org/10.1190/1.3603774FiguresReferencesRelatedDetails Beijing 2009 International Geophysical Conference and Exposition, Beijing, China, 24–27 April 2009 ISBN (print):978-1-56080-284-6ISSN (online):2159-6832 Copyright: 2009 Pages: publication data© 2009 Copyright © 2009 Society of Exploration Geophysicists and China Petroleum SocietyPublisher:Society of Exploration Geophysicists HistoryPublished Online: 28 Jun 2011 CITATION INFORMATION Dariush Nadri, Andrej Bóna, and Miroslav Brajanovsky, (2009), "Estimation of elasticity tensor from the inversion of traveltimes in spherical shale samples," SEG Global Meeting Abstracts : 249-249. https://doi.org/10.1190/1.3603774 Plain-Language Summary PDF DownloadLoading ...

A conceptually simple superposition model is presented for dispersion and attenuation of compressional waves in fractured porous rocks that are saturated by a mixture of two pore fluids. These two different types of heterogeneities are described by four parameters: The fracture spacing (fracture density) and fracture weakness characterizing the fractured medium; the correlation length and degree of saturation characterizing the fluid patches that are embedded between the fractures. This model is employed to explain the relatively strong P-wave velocity dispersion found for a limestone reservoir. We conclude that the mechanism of wave-induced flow may well explain large P-wave dispersion and attenuation in heterogeneous porous media.

The importance of natural fractures for development and production of hydrocarbon reservoirs requires little justification. While in clastic reservoirs fractures can cause permeability anisotropy and thus affect field development, in carbonates and tight sands they are often critical for reservoir production. If open fractures have a preferential direction (which is almost always the case), they cause azimuthal seismic anisotropy, making seismic a powerful tool for the characterization of fractured reservoirs.

PreviousNext No AccessSEG Technical Program Expanded Abstracts 2007Strong dispersion and attenuation of P‐waves in a partially saturated fractured reservoirAuthors: Miroslav BrajanovskiTobias M. MüllerJorge O. ParraMiroslav BrajanovskiGeophysical Institute, University of Karlsruhe, GermanySearch for more papers by this author, Tobias M. MüllerGeophysical Institute, University of Karlsruhe, GermanySearch for more papers by this author, and Jorge O. ParraSouthwest Research Institute, San Antonio, USASearch for more papers by this authorhttps://doi.org/10.1190/1.2792762 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract In this work we interpret data showing strong velocity dispersion of P‐waves (up to 30%) and attenuation in a relatively narrow frequency range. The cross‐hole and VSP data were measured in a reservoir, which is in the porous zone of the Silurian Kankakee Limestone Formation formed by vertical fractures within a porous matrix saturated by oil, and gas patches. Such a medium exhibits significant attenuation due to wave‐induced fluid flow across the interfaces between different type of inclusions (fractures, fluid patches) and background. Other models of intrinsic attenuation (in particular squirt flow models) cannot explain amount of observed dispersion when using realistic rock properties. In order to interpret data in satisfactory way we develop a superposition model for fractured porous rocks accounting also for the patchy saturation effect.Permalink: https://doi.org/10.1190/1.2792762FiguresReferencesRelatedDetailsCited ByFrequency-Dependent Amplitude Versus Offset Variations in Porous Rocks with Aligned Fractures14 November 2016 | Pure and Applied Geophysics, Vol. 174, No. 3 SEG Technical Program Expanded Abstracts 2007ISSN (print):1052-3812 ISSN (online):1949-4645Copyright: 2007 Pages: 3124 publication data© 2007 Copyright © 2007 Society of Exploration GeophysicistsPublisher:Society of Exploration Geophysicists HistoryPublished: 14 Sep 2007 CITATION INFORMATION Miroslav Brajanovski, Tobias M. Müller, and Jorge O. Parra, (2007), "Strong dispersion and attenuation of P‐waves in a partially saturated fractured reservoir," SEG Technical Program Expanded Abstracts : 1407-1411. https://doi.org/10.1190/1.2792762 Plain-Language Summary PDF DownloadLoading ...

SummaryA conceptually simple superposition model is presented for dispersion and attenuation of compressional waves in fractured porous rocks that are saturated by a mixture of liquid and gas. These two different types of heterogeneities are described by four parameters: The fracture spacing (fracture density) and fracture weakness characterizing the fractured medium; the correlation length and degree of saturation characterizing the fluid patches that are embedded between the fractures. All four controlling parameters have a clear physical meaning and can be potentially constrained if there is additional information like well-log data. This model is employed to explain the relatively strong P-wave velocity dispersion found for a limestone reservoir. The mechanism of waveinduced flow may well explain large P-wave dispersion and attenuation in heterogeneous porous media.

A rock physics model is presented for dispersion and attenuation of compressional waves in fractured porous rocks that are saturated by a mixture of liquid and gas. These two different types of heterogeneities are described by four parameters: The fracture spacing and fracture weakness characterizing the fractured medium; the correlation length and degree of saturation characterizing the fluid patches that are embedded between the fractures. This model is employed to explain the extremely strong P-wave velocity dispersion in a narrow frequency range found for a limestone reservoir. The results indicate that seismic attenuation and dispersion may provide additional constraints on relevant reservoir parameters.