Results

SUMMARY

One of the most important mechanisms of P-wave attenuation at seismic frequencies is known as "mesoscopic loss", and is caused by the presence of heterogeneities larger than the pore size but smaller than the predominant wavelengths (mesoscopic-scale heterogeneities). These effects are caused by equilibration of wave-induced fluid pressure gradients via a slow-wave diffusion process. To perform numerical simulations in these type of media using Biot''s equations of motion at the macroscale, it is necessary to employ extremely fine meshes to properly represent these mesoscopic heterogeneities and their attenuation effects on the fast waves, which makes this procedure computationally very expensive or even not feasible. An alternative approach is to employ the numerical upscaling procedure recently presented by the authors, to determine equivalent undrained complex frequency dependent plane wave and shear moduli defining at the macroscale a viscoelastic medium behaving in similar fashion as the original Biot medium. These equivalent moduli are determined performing numerical compressibility and shear tests on a representative sample of heterogeneous bulk material, allowing to reduce in several orders of magnitude the degrees of freedom needed to characterize the material. In this paper we present a finite element procedure, formulated in the space-frequency domain, to perform numerical simulations of wave propagation in highly heterogeneous fluid-filled porous sandstones employing a viscoelastic model with complex moduli determined using the mentioned upscaling procedure. The methodology is first validated by comparison with previous numerical experiments using Biot''s equations of motion. Finally, the procedure is applied to simulate and analyze the effect of underground carbon dioxide (CO2) accumulations on the amplitude and attenuation of seismic waves.

INTRODUCTION

The analysis of attenuation at seismic frequencies due to wave-induced fluid flow caused by mesoscopic-scale heterogeneities has been the object of many studies, such as White J.E. et al. (1975); Pride S. et al. (2002); Muller T. M. and Gurevich B. (2005); Mason Y. and Pride S. (2006); Carcione J.M. and Picotti S. (2006); Rubino, J. G. et al. (2007), among others. These heterogeneities in the solid frame and fluid properties, typically on the order of centimeters, are much smaller than the wavelengths of the fast P and S waves travelling in Biot''s media. Consequently, the huge number of degrees of freedom (DOF) needed to represent these heterogeneities and their attenuation effects at the macroscale in any finite element or finite difference based numerical procedure employing Biot''s equations renders such approach not feasible. In Santos, J. E. et al. (2007) the authors presented a novel numerical upscaling approach to tackle this problem. The idea is as follows: take a representative sample ?R of bulk material and perform (local) numerical oscillatory compressibility and shear tests to determine the equivalent undrained complex frequency dependent plane wave Mc(w) and shear modulus N(w) associated with WR in the range of frequencies at which the material is going to be tested by acoustic methods.

These local compressibility and shear oscillatory tests are defined as boundary value problems formulated in the space-frequency domain assuming that the sample obeys Biot''s equations of motion.

Summary

A new method uses eigenimages to construct a coherent noise model in a localized time-space window and performs the noise attenuation by adaptively subtracting the noise model from the input data. Advantages to this method include minimum spatial-amplitude smearing, effective attenuation on various types of coherent noise such as ground roll, air waves and near-surface scattered energy as well as handling both the aliased and non-aliased noise quite well. This new nonlinear filter significantly outperforms conventional techniques. We demonstrate the performance of this local-nonlinear filter with real data examples.

Summary

This paper attempts to provide a more complete analysis of tool eccentricity effects on logging-while-drilling (LWD) propagation resistivity measurement than previously published. For a typical tool size of 6.75-in., I demonstrate tool eccentricity effect for a wide range of formation resistivities. Both oil-based mud (OBM) and water-based mud (WBM) are considered. The eccentricity effect is examined for several different borehole sizes.

For a nominal hole size of 8.5 in. or a larger hole size of 9.5 in., little eccentricity effect is observed for WBM even at 2 MHz frequency. Hence, there will be no need to correct either attenuation or phase difference measurement if the well is drilled with WBM. However, an excessively large borehole (12.5 in.) filled with conductive WBM will create strong tool eccentricity effect on a short-spacing (e.g., 15 in.) response at formation resistivities above 3 Ohm.m. The long-spacing response may still be little affected by tool eccentricity.

For OBM, tool eccentricity creates more concern in conductive formations than in resistive formations. For a nominal hole size of 8.5 in., a severe eccentricity effect may be observed if the formation resistivity is below 0.5 Ohm.m. For larger boreholes (9.5 and 12.5 in.), eccentricity effect may have to be corrected if the formation resistivity is below 2 Ohm.m. Interestingly, for OBM, tool eccentricity has a larger effect on long-spacing (e.g., 45 in.) responses, whereas for WBM the opposite is true. Some physical insights were made into the tool eccentricity effect on LWD resistivity measurement. A neutral resistivity phenomenon was observed for OBM. Around a neutral resistivity value, the measurement is little affected by tool eccentricity even if the tool is fully decentralized. An explanation is provided that the mirror image transmitter produced in the formation produces a magnetic field that is tangential to the receivers and hence makes no or little contributions to the tool response.

Summary

Heavy oils are defined as having high densities and extremely high viscosities. Due to their viscoelastic behavior the traditional rock physics based on Gassmann theory becomes inapplicable. In this paper, we use effective-medium approach known as coherent potential approximation or CPA as an alternative fluid substitution scheme for rocks saturated with viscoelastic fluids. Such rocks are modelled as solids with elliptical fluid inclusions when fluid concentration is small and as suspensions of solid particles in the fluid when the solid concentration is small. This approach is consistent with concepts of percolation and critical porosity, and allows one to model both sandstones and unconsolidated sands.

We test the approach against known solutions. First, we apply CPA to fluid-solid mixtures and compare the obtained estimates with Gassmann results. Second, we compare CPA predictions for solid-solid mixtures with numerical simulations. Good match between the results confirms the applicability of the CPA scheme. We extend the scheme to predict the effective frequency- and temperature-dependent properties of heavy oil rocks. CPA scheme reproduces frequency-dependent attenuation and dispersion which are qualitatively consistent with laboratory measurements and numerical simulations. This confirms that the proposed scheme provides realistic estimates of the properties of rocks saturated with heavy oil.

Summary

In the winter of 2006/7 the BP Wamsutter team conducted an extensive seismic field trial including a world-first deployment of cable-less full-wavefield single-sensors in a 3D onshore survey, in addition to a 3DVSP and cross-well seismic. Despite weather and mechanical challenges, the acquisition operation successfully delivered a unique high density, full azimuth, full-wavefield dataset for analysis. Special care & ''designer'' processing was applied to this unconventional data to optimize resolution and retain robust amplitude and azimuthal information. This has successfully yielded a full stack image comparable in quality to that of conventional geophone arrays, despite the lower-than-anticipated trace recovery, boding well for future surveys where significantly greater recovery can be expected. Additional Prestack AVO (amplitude with offset) and AZAVO (azimuth with offset) attributes are shedding new light on a reservoir previously only imaged with full stack data; the converted-wave component is also of unusually high quality and is ultimately expected to contribute to describing the reservoir to new levels of detail. Learnings from the field trial are already impacting the onshore seismic strategy both within the Wamsutter field and across BP’s tight gas business.

Summary

In the recent years, many wide-azimuth(WA) surveys have been conducted, the main purpose of them is wide-azimuth subsurface complex structural imaging using P waves. By using wide-azimuth acquisition, more information from complex subsurface areas was acquired. In Liaohe Basin, we face a challenge that the subsurface complex structural areas can not be properly illuminated by using conventional narrow azimuth survey, so it failed to image these areas. By properly using target illumination oriented acquisition design, advanced wide-azimuth pre-processing, wideazimuth tomographic velocity and anisotropic parameter inversion and amplitude-preserved anisotropic pre-stack depth imaging, etc., satisfactory subsurface imaging result has been obtained. In addition, more information, such as anisotropic parameters, azimuthal anisotropic velocity, fracture density and direction, etc, can also be obtained, and all of them can assist reservoir characterization.

Summary

Frequency-dependent analysis of seismic data is gaining more and more attention in the seismic industry and academia, simply because it opens potential opportunities not only for indicating hydrocarbon anomalies, but also for estimating fluid mobility properties of underground reservoirs. While there has been significant advanced in the interpretation of seismic amplitude-versus-offset (AVO) anomalies, there is a lack of theory to guide the interpretation of frequency-dependent analysis. In this paper, based on White''s patchy saturation model, we analytically examined the characteristics of the reflection amplitude variations as a function of frequency at an interface between a non-dispersive medium and a dispersive medium. And then, numerical modeling based on Biot''s poroelastic wave theory was conducted on three selected reservoir models. The numerical modeling results confirmed our analytical analysis. Then, similar to AVO classification, the amplitude-versus-frequency curves are generally divided into three classes. This classification provides a guide to frequency-dependent interpretations.

SUMMARY

An analysis of two rock samples, hyaloclastites and basalts, at in-situ reservoir conditions has been done to identify the role of temperature on the seismic velocity and attenuation. The goal is to establish a temperature-dependent fluid substitution analysis of geothermal rocks using Gassmann equation within the framework of Biot''s poroelasticity. The analysis of temperature-dependent wave attenuation is shown for hyaloclastites. The results show that the general decreasing trend of seismic velocity towards temperature may be related to the thermophysical characteristics of fluid. Using Gassmann equation it has been shown that the presence of steam bubbles can reduce the effective elastic property of rocks which indirectly demonstrates the role of temperature to the seismic velocity. The Q factor, i.e., inverse of attenuation, behaves surprisingly almost in the same way as the seismic velocity with temperature, except in the lower temperature range. The Q factor increase with the temperature is supposed to be a quick viscosity decrease. The later decrease of Q factor may indicate the presence of steam bubbles due to the further temperature increase. This finding demonstrates that the application of temperature-dependent fluid substitution modelling using Gassmann equation can be applied for the characterization of geothermal reservoir systems.

INTRODUCTION

In geothermal reservoirs, fluid-steam phase transition, fluid pressure and temperature are some crucial factors that potentially produce and/ or contribute to seismic anomalies. When interpreting such anomalies, realistic assumptions based on validated rock physics models are important (Jones et al., 1980; Boitnott and Bonner, 1994).

A laboratory measurement of temperature dependent seismic velocities of rocks at high temperature reservoir conditions has been referred to, for example in (Kern, 1978; Kern et al., 2001; Punturo et al., 2005; Scheu et al., 2006). However, these laboratory experiments have been mainly employed on dry samples and under deep mantle rock condition, i.e., very high pressures (up to 600 MPa with 50 MPa interval) and very high temperatures (up to 1000°C with about 100°C interval). Meanwhile, many geothermal reservoirs, as the case of Icelandic reservoir being investigated, are characterized by temperature range up to 200-300°C and pore pressure around 10 MPa with the pore water being in the liquid phase (Flóvenz et al., 2005). A controlled petrophysical laboratory experiment simulating those conditions becomes important for the evaluation of such a geothermal resource. An analysis of core scale properties of rock sample at in-situ reservoir conditions is useful to identify the role of temperature on the seismic velocity and attenuation. The goal of this work is to present the result of using Gassmann equation within the framework of Biot''s poroelasticity for a fluid substitution analysis of temperature-dependent geothermal rocks. For that, the measurement of ultrasonic transmission wave has been performed on two samples of volcanic geothermal rocks with different alterations (Bruhn et al., 2007; Jaya et al., 2007). Gassmann equation is then used to relate the effect of temperature on the fluid and on the effective elastic property of saturated rock. In addition, the temperature-dependent wave attenuation is shown for the hyaloclastite sample.

Summary

In this paper we study theoretically the seismic properties of rocks saturated with multiple fluids. Our analysis is based on an explicit description of the pore space which allows us to describe the effect of micro-scale fluid motion on the elastic properties. A striking result of our analysis is the existence of a non-linear term which is proportional to the contrast in the two fluid bulk moduli. This implies that when we have a single fluid we expect to see linear motion, but for rocks saturated with multiple fluids, such as is expected in hydrocarbon reservoirs, the motion is nonlinear in character. We describe some of the principal implications of the analysis, in particular the interaction between different source frequencies, the generation of high frequency motion and the existence of abnormally high dispersion and attenuation, which are relevant for rocks saturated with multiple fluids.