A Generalized Biot-Gassmann Model for the Acoustic Properties of Shaley Sandstones

Carcione, M. J.; Gurevich, Boris; Callini, F.; Seriani, G.

doi:10.3997/2214-4609-pdb.28.d35

Cited by 14 publications

(36 citation statements)

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“…We consider the material properties shown in Table 1, where the moduli and density of the grain material correspond to a mixture of 90% quartz and 10% clay [the moduli are calculated as the upper and lower Hashin-Shtrikman bounds (Mavko et al, 1998, 106)]. The dry-rock moduli are obtained by a relation introduced by Krief et al (1990) (see Goldberg and Gurevich, 1998;and Carcione et al, 2000). Note that White's (1975) theory does not consider tortuosity [the value of tortuosity given in Table 1 is typical of a sandstone (e.g., Johnson et al, 1987)].…”

Section: Resultsmentioning

confidence: 99%

White's model for wave propagation in partially saturated rocks: Comparison with poroelastic numerical experiments

2003

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We use a poroelastic modeling algorithm to compute numerical experiments of wave propagation in White's partial saturation model. The results are then compared to the theoretical predictions. The model consists of a homogeneous sandstone saturated with brine and spherical gas pockets. White's theory predicts a relaxation mechanism, due to pressure equilibration, causing attenuation and velocity dispersion of the wavefield. We vary gas saturation either by increasing the radius of the gas pocket or by increasing the density of gas bubbles. Despite that the modeling is two dimensional and interaction between the gas pockets is neglected in White's model, the numerical results show the trends predicted by the theory. In particular, we observe a similar increase in velocity at high frequencies (and low permeabilities). Furthermore, the behavior of the attenuation peaks versus water saturation and frequency is similar to that of White's model. The modeling results show more dissipation and higher velocities than White's model due to multiple scattering and local fluid-flow effects. The conversion of fast P-wave energy into dissipating slow waves at the patches is the main mechanism of attenuation. Differential motion between the rock skeleton and the fluids is highly enhanced by the presence of fluid/fluid interfaces and pressure gradients generated through them.

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Section: Resultsmentioning

confidence: 99%

White's model for wave propagation in partially saturated rocks: Comparison with poroelastic numerical experiments

2003

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“…The dry-rock bulk and shear moduli are given by the Krief model, (Krief et al, 1990;Brajanovski et al, 2005). Porosity and permeability are related by an equation derived by Carcione et al (2000),…”

Section: Examplementioning

confidence: 99%

Angular and Frequency-Dependent Wave Velocity and Attenuation in Fractured Porous Media

Carcione

Gurevich

Santos

et al. 2013

Pure Appl. Geophys.

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Wave-induced fluid flow generates a dominant attenuation mechanism in porous media. It consists of energy loss due to P-wave conversion to Biot (diffusive) modes at mesoscopic-scale inhomogeneities. Fractured poroelastic media show significant attenuation and velocity dispersion due to this mechanism.The theory has first been developed for the symmetry axis of the equivalent transversely isotropic (TI) medium corresponding to a poroelastic medium containing planar fractures. In this work, we consider the theory for all propagation angles by obtaining the five complex and frequency-dependent stiffnesses of the equivalent TI medium as a function of frequency. We assume that the flow direction is perpendicular to the layering plane and is independent of the loading direction. As a consequence, the behaviour of the medium can be described by a single relaxation function.

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“…Clay content affects the permeability, which is not available for all the formations. Carcione et al [2000] derived a model of permeability as a function of clay content. They assumed that a shaly sandstone is composed of a sandy matrix and a shaly matrix with partial permeabilities:…”

Section: Formation Propertiesmentioning

confidence: 99%

Seismic modeling to monitor CO₂ geological storage: The Atzbach‐Schwanenstadt gas field

et al. 2012

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[1] We develop a petro-elastical numerical methodology to compute realistic synthetic seismograms and analyze the sensitivity of the seismic response when injecting carbon dioxide (CO 2 ) in a depleted gas reservoir. The petro-elastical model describes the seismic properties of the reservoir rock saturated with CO 2 , methane and brine, and allows us to estimate the distribution and saturation of CO 2 during the injection process. The gas properties, as a function of the in-situ pressure and temperature conditions, are computed with the Peng-Robinson equation of state, taking into account the absorption of gas by brine. Wave attenuation and velocity dispersion are based on the mesoscopic loss mechanism, which is simulated by an upscaling procedure to obtain an equivalent viscoelastic medium corresponding to partial saturation at the mesoscopic scale. Having the equivalent complex and frequency-dependent bulk (dilatational) modulus, we include shear attenuation and perform numerical simulations of wave propagation at the macroscale by solving the viscoelastic differential equations using the memory-variable approach. The pseudo-spectral modeling method allows general material variability and provides a complete and accurate characterization of the reservoir. The methodology is used to assess the sensitivity of the seismic method for monitoring the CO 2 geological storage at the Atzbach-Schwanestadt depleted gas-field in Austria. The objective of monitoring is the detection of the CO 2 plume in the reservoir and possible leakages of CO 2 . The leakages are located at different depths, where the CO 2 is present as gaseous, liquid and supercritical phases. Even though the differences can be very subtle, this work shows that seismic monitoring of CO 2 from the surface is possible. While the identification of shallow leakages is feasible, the detection of the plume and deep leakages, located in the caprock just above the injection formation, is more difficult, but possible by using repeatability metrics, such as the normalized RMS (NRMS) images. Considering real-data conditions, affected by random noise, a reference detection threshold for deep leakages and the CO 2 plume in the reservoir corresponds to a signal-to-noise ratio of about 10 dB.

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A Generalized Biot-Gassmann Model for the Acoustic Properties of Shaley Sandstones

Cited by 14 publications

References 10 publications

White's model for wave propagation in partially saturated rocks: Comparison with poroelastic numerical experiments

White's model for wave propagation in partially saturated rocks: Comparison with poroelastic numerical experiments

Angular and Frequency-Dependent Wave Velocity and Attenuation in Fractured Porous Media

Seismic modeling to monitor CO₂ geological storage: The Atzbach‐Schwanenstadt gas field

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A Generalized Biot-Gassmann Model for the Acoustic Properties of Shaley Sandstones

Cited by 14 publications

References 10 publications

White's model for wave propagation in partially saturated rocks: Comparison with poroelastic numerical experiments

White's model for wave propagation in partially saturated rocks: Comparison with poroelastic numerical experiments

Angular and Frequency-Dependent Wave Velocity and Attenuation in Fractured Porous Media

Seismic modeling to monitor CO2 geological storage: The Atzbach‐Schwanenstadt gas field

Contact Info

Product

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Seismic modeling to monitor CO₂ geological storage: The Atzbach‐Schwanenstadt gas field