Sensitivity of 3D 3C synthetic seismograms to anisotropic attenuation and velocity in reservoir models

Geophysics ◽  
2017 ◽  
Vol 82 (2) ◽  
pp. T79-T95 ◽  
Author(s):  
Peng Guo ◽  
George A. McMechan
Keyword(s):  
Fluid Flow ◽  
Aspect Ratio ◽  
Reservoir Characterization ◽  
Fractured Reservoirs ◽  
Staggered Grid ◽  
Fracture Density ◽  
Reservoir Properties ◽  
High Fracture ◽  
Frequency Dependent ◽  
T Matrix

Anisotropic attenuation in fluid-saturated reservoirs with high fracture density may be diagnostic for reservoir characterization. Wave-induced mesoscale fluid flow is considered to be the major cause of intrinsic attenuation at exploration seismic frequencies. We perform tests of the sensitivity, of anisotropic attenuation and velocity, to reservoir properties in fractured HTI media based on the mesoscale fluid flow attenuation mechanism. The viscoelastic T-matrix, a unified effective medium theory of global and local fluid flow mechanisms, is used to compute frequency-dependent anisotropic attenuation and velocity for ranges of reservoir properties, including fracture density, orientation, fracture aspect ratio, fluid type, and permeability. The 3D 3C staggered-grid finite-difference anisotropic viscoelastic modeling with a Crank-Nicolson scheme is used to generate seismograms using the frequency-dependent velocity and attenuation computed by the viscoelastic T-matrix. A standard linear solid model relates the stress and strain relaxation times to the frequency-dependent attenuation, in the relaxation mechanism equation. The seismic signatures resulting from changing viscoelastic reservoir properties are easily visible. Velocity becomes more sensitive to the fracture aspect ratio when considering fluid flow compared with when the fluid is isolated. Anisotropy of attenuation affects 3C viscoelastic seismic data more strongly than velocity anisotropy does. Analysis of the influence of reservoir properties, on seismic properties in mesoscale fluid-saturated fractured reservoirs with high fracture density, suggests that anisotropic attenuation is a potential tool for reservoir characterization.

Outcrop Analogues to Fractured Reservoirs, UAE

2021 ◽  
Author(s):  
Abdelwahab Noufal
Keyword(s):  
Fluid Flow ◽  
Reservoir Characterization ◽  
Fractured Reservoirs ◽  
Abu Dhabi ◽  
Fracture Density ◽  
Tectonic Event ◽  
Rock Composition ◽  
Hydrocarbon Reservoir ◽  
Fracture Orientation ◽  
Bed Thickness

Abstract Fractures were not the focus of reservoir studies in Abu Dhabi for the last decades, although its importance in enhancing production, as the general understanding considering fractures are not contributing to production. The fractured carbonate outcrops provide useful analogue observations, data and concepts to support subsurface hydrocarbon reservoir characterization from well and seismic data. The fracture orientation, size, porosity, length, spacing, crosscutting relationships, fracture density versus lithology and bed thickness and connectivity are difficult to measure directly from subsurface well and core data. The understanding of fracture formation and distribution and their effects on fluid flow has been greatly improved by the use of outcrop analogue data through the current work. This paper address the fracture geometry, kinematics and mechanical properties based on outcrops matching Abu Dhabi subsurface reservoir analogues. Integrating outcrop data with fracture orientation and fracture density from core and borehole image data, and seismic capturing fractures characteristics. The outcrop analogues constrain the uncertainty and developing new concepts in characterizing the interplay of rock matrix and fracture networks relevant to fluid flow and hydrocarbon recovery. Analysing the fractures with fracture lengths, aperture, spacing per each interval and relate them to the tectonic event are extracted strictly in the reservoir section. The results showing developed highly dipping shear fractures with short length, small spacing and bimodal aperture distribution that related to fracture orientation. Fracture porosity is dependent on size and controlled by lithology, bed thickness, paleostress and rock composition. Understanding fractures and their behaviour will optimize production greatly and they create exploration targets in otherwise tight reservoir zones, including under-explored sections.

Quartic moveout coefficient for a dipping azimuthally anisotropic layer

Geophysics ◽  
2004 ◽  
Vol 69 (3) ◽  
pp. 699-707 ◽  
Author(s):  
Andrés Pech ◽  
Ilya Tsvankin
Keyword(s):  
Reservoir Characterization ◽  
Fractured Reservoirs ◽  
Symmetry Plane ◽  
Exact Expression ◽  
Naturally Fractured Reservoirs ◽  
P Wave ◽  
Orthorhombic Symmetry ◽  
Fracture Density ◽  
Weak Anisotropy ◽  
Velocity Anisotropy

Interpretation and inversion of azimuthally varying nonhyperbolic reflection moveout requires accounting for both velocity anisotropy and subsurface structure. Here, our previously derived exact expression for the quartic moveout coefficient A4 is applied to P‐wave reflections from a dipping interface overlaid by a medium of orthorhombic symmetry. The weak‐anisotropy approximaton for the coefficient A4 in a homogeneous orthorhombic layer is controlled by the anellipticity parameters η(1), η(2), and η(3), which are responsible for time processing of P‐wave data. If the dip plane of the reflector coincides with the vertical symmetry plane [x1, x3], A4 on the dip line is proportional to the in‐plane anellipticity parameter η(2) and always changes sign for a dip of 30○. The quartic coefficient on the strike line is a function of all three η–parameters, but for mild dips it is mostly governed by η(1)—the parameter defined in the incidence plane [x2, x3]. Whereas the magnitude of the dip line A4 typically becomes small for dips exceeding 45○, the nonhyperbolic moveout on the strike line may remain significant even for subvertical reflectors. The character of the azimuthal variation of A4 depends on reflector dip and is quite sensitive to the signs and relative magnitudes of η(1), η(2), and η(3). The analytic results and numerical modeling show that the azimuthal pattern of the quartic coefficient can contain multiple lobes, with one or two azimuths of vanishing A4 between the dip and strike directions. The strong influence of the anellipticity parameters on the azimuthally varying coefficient A4 suggests that nonhyperbolic moveout recorded in wide‐azimuth surveys can help to constrain the anisotropic velocity field. Since for typical orthorhombic models that describe naturally fractured reservoirs the parameters η(1,2,3) are closely related to the fracture density and infill, the results of azimuthal nonhyperbolic moveout analysis can also be used in reservoir characterization.

Effects of fractures on NMO velocities and P‐wave azimuthal AVO response

Geophysics ◽  
2002 ◽  
Vol 67 (3) ◽  
pp. 711-726 ◽  
Author(s):  
Feng Shen ◽  
Xiang Zhu ◽  
M. Nafi Toksöz
Keyword(s):  
Aspect Ratio ◽  
Fractured Reservoirs ◽  
Crack Density ◽  
P Wave ◽  
Fractured Reservoir ◽  
Fracture Density ◽  
Fracture Detection ◽  
Fluid Content ◽  
Fracture Parameters ◽  
Fractured Medium

This paper attempts to explain the relationships between fractured medium properties and seismic signatures and distortions induced by geology‐related influences on azimuthal AVO responses. In the presence of vertically aligned fractures, the relationships between fracture parameters (fracture density, fracture aspect ratio, and saturated fluid content) and their seismic signatures are linked with rock physics models of fractured media. The P‐wave seismic signatures studied in this paper include anisotropic parameters (δ(v), (v), and γ(v)), NMO velocities, and azimuthal AVO responses, where δ(v) is responsible for near‐vertical P‐wave velocity variations, (v) defines P‐wave anisotropy, and γ(v) governs the degree of shearwave splitting. The results show that in gas‐saturated fractures, anisotropic parameters δ(v) and (v) vary with fracture density alone. However, in water‐saturated fractures δ(v) and (v) depend on fracture density and crack aspect ratio and are also related to Vp/VS and Vp of background rocks, respectively. Differing from δ(v) and (v), γ(v) is the parameter most related to crack density. It is insensitive to the saturated fluid content and crack aspect ratio. The P‐wave NMO velocities in horizontally layered media are a function of δ(v), and their properties are comparable with those of δ(v). Results from 3‐D finite‐difference modeling show that P‐wave azimuthal AVO variations do not necessarily correlate with the magnitude of fracture density. Our studies reveal that, in addition to Poisson's ratio, other elastic properties of background rocks have an effect on P‐wave azimuthal AVO variations. Varying the saturated fluid content of fractures can lead to azimuthal AVO variations and may greatly change azimuthal AVO responses. For a thin fractured reservoir, a tuning effect related to seismic wavelength and reservoir thickness can result in variations in AVO gradients and in azimuthal AVO variations. Results from instantaneous frequency and instantaneous bandwidth indicate that tuning can also lead to azimuthal variations in the rates of changes of the phase and amplitude of seismic waves. For very thin fractured reservoirs, the effect of tuning could become dominant. Our numerical results show that AVO gradients may be significantly distorted in the presence of overburden anisotropy, which suggests that the inversion of fracture parameters based on an individual AVO response would be biased unless this influence were corrected. Though P‐wave azimuthal AVO variations could be useful for fracture detection, the combination of other types of data is more beneficial than using P‐wave amplitude signatures alone, especially for the quantitative characterization of a fractured reservoir.

The application of seismic attributes for reservoir characterization in Pre-Tertiary fractured basement, Vietnam-Malaysia offshore

2014 ◽  
Vol 2 (1) ◽  
pp. SA57-SA66 ◽  
Author(s):  
Nguyen Huy Ngoc ◽  
Sahalan B. Aziz ◽  
Nguyen Anh Duc
Keyword(s):  
Seismic Data ◽  
Reservoir Characterization ◽  
Rock Type ◽  
Seismic Attributes ◽  
Basement Rock ◽  
Fracture Density ◽  
High Fracture ◽  
Offshore Area ◽  
Fracture Characteristics ◽  
Basement Reservoirs

The Pre-Tertiary fractured basement forms important hydrocarbon-bearing reservoirs in the Vietnam-Malaysia offshore area, and is being produced from such reservoirs in Vietnam where the authors have extensive working experiences for both clastics and fractured basement reservoirs and in both exploration and development phases. Due to their very small matrix porosity, the basement rocks become reservoirs only when they are strongly fractured. The quality of the fractured basement reservoirs depends on basement rock type, fracture density, and fracture characteristics including aperture, azimuth, dip, continuity, and fracture system intersection. Three-dimensional seismic data is applied widely to characterize these basement reservoirs. Based on results from applying many different seismic attributes to 3D seismic data from different Pre-Tertiary fractured basements in Vietnam and Malaysia, we demonstrate the utility of attributes in characterizing fractured basement reservoirs. Seismic attributes help predict the basement rock type and fracture characteristics from near top basement to deep inside basement. In the zone near the top of basement, the characteristics of fracture systems can be predicted by amplitude, coherence, curvature, and secondary derivative attributes. Deep inside the basement, relative acoustic impedance and its attributes have been successfully applied to predict the distribution of high fracture density, while dip and azimuth, ant-tracking, and gradient magnitude attributes have proven to be effective for predicting fracture characteristics. The accuracy of fracture characterization based on seismic attributes has been verified by drilling results.

Frequency-dependent AVO analysis using the scattering response of a layered reservoir

Geophysics ◽  
2020 ◽  
Vol 85 (2) ◽  
pp. N1-N16
Author(s):  
Dhananjay Kumar ◽  
Zeyu Zhao ◽  
Douglas J. Foster ◽  
Danica Dralus ◽  
Mrinal K. Sen
Keyword(s):  
Reservoir Characterization ◽  
Seismic Analysis ◽  
Maximum Amplitude ◽  
Reservoir Quality ◽  
Seismic Velocities ◽  
Reservoir Properties ◽  
Frequency Dependent ◽  
Seismic Scattering ◽  
Gas Saturation ◽  
Avo Attributes

Sensitivity of reservoir properties to broadband seismic amplitudes can be weak, which makes interpretation ambiguous. Examples of challenging interpretation scenarios include distinguishing blocky reservoirs from fining sequences, low gas saturation from high gas saturation, and variable reservoir quality. Some of these rock and fluid changes might indicate stronger sensitivity to amplitudes over narrow frequency bands, which is a characteristic of frequency-dependent amplitude variation with offset (FAVO). We have developed a FAVO model for reservoir characterization, following a seismic scattering phenomenon through a set of isotropic elastic layers. The frequency dependency in our model comes from the time delays due to wave propagation within layers. The FAVO modeled response is a complex-valued amplitude varying with angle and frequency, and it is a function of the seismic velocities and thicknesses of individual layers, along with the conventional AVO response at all interfaces. Our FAVO seismic analysis consists of two main steps: (1) forward modeling using well logs to understand rock and fluid sensitivity to amplitudes to identify tuning frequencies with maximum amplitude excursions and (2) seismic analysis at tuning frequencies. With well-log models, we observed that the frequency-dependent tuning response is primarily dependent on the lithology stacking pattern of a reservoir; in the cases studied, the fluid and reservoir quality have secondary effects on the frequency dependence of the amplitudes. We evaluate synthetic models and field data from the Columbus Basin, Trinidad, to illustrate our frequency-dependent seismic analysis methods. For one of the sandstone reservoirs, a frequency-dependent attribute indicates better spatial resolution of the anomaly than a conventional amplitude extraction. FAVO attributes are complementary to conventional AVO attributes.

Dual attenuation peaks revealing mesoscopic and microscopic fluid flow in partially oil-saturated Fontainebleau sandstones

2020 ◽  
Vol 224 (3) ◽  
pp. 1670-1683
Author(s):  
Liming Zhao ◽  
Genyang Tang ◽  
Chao Sun ◽  
Jianguo Zhao ◽  
Shangxu Wang
Keyword(s):  
Fluid Flow ◽  
Reservoir Characterization ◽  
Seismic Analysis ◽  
Confining Pressure ◽  
Time Lapse ◽  
Seismic Attenuation ◽  
Fluid Distribution ◽  
Oil Viscosity ◽  
Measurement Results ◽  
And Shifts

SUMMARY We conducted stress–strain oscillation experiments on dry and partially oil-saturated Fontainebleau sandstone samples over the 1–2000 Hz band at different confining pressures to investigate the wave-induced fluid flow (WIFF) at mesoscopic and microscopic scales and their interaction. Three tested rock samples have similar porosity between 6 and 7 per cent and were partially saturated to different degrees with different oils. The measurement results exhibit a single or two attenuation peaks that are affected by the saturation degree, oil viscosity and confining pressure. One peak, exhibited by all samples, shifts to lower frequencies with increasing pressure, and is mainly attributed to grain contact- or microcrack-related squirt flow based on modelling of its characteristics and comparison with other experiment results for sandstones. The other peak is present at smaller frequencies and shifts to higher frequencies as the confining pressure increases, showing an opposite pressure dependence. This contrast is interpreted as the result of fluid flow patterns at different scales. We developed a dual-scale fluid flow model by incorporating the squirt flow effect into the patchy saturation model, which accounts for the interaction of WIFFs at microscopic and mesoscopic scales. This model provides a reasonable interpretation of the measurement results. Our broad-frequency-band measurements give physical evidence of WIFFs co-existing at two different scales, and combining with modelling results, it suggests that the WIFF mechanisms, related to pore microstructure and fluid distribution, interplay with each other and jointly control seismic attenuation and dispersion at reservoir conditions. These observations and modelling results are useful for quantitative seismic interpretation and reservoir characterization, specifically they have potential applications in time-lapse seismic analysis, fluid prediction and reservoir monitoring.

scholarly journals Analysis of Fracture Roughness Control on Permeability Using SfM and Fluid Flow Simulations: Implications for Carbonate Reservoir Characterization

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-19 ◽  
Author(s):  
Miller Zambrano ◽  
Alan D. Pitts ◽  
Ali Salama ◽  
Tiziano Volatili ◽  
Maurizio Giorgioni ◽  
...  
Keyword(s):  
Fluid Flow ◽  
Reservoir Characterization ◽  
Flow Simulation ◽  
Carbonate Reservoir ◽  
Single Fracture ◽  
Parallel Plates ◽  
Surface Mapping ◽  
Navier Stokes Equation ◽  
Hydraulic Aperture ◽  
Fracture Modeling

Fluid flow through a single fracture is traditionally described by the cubic law, which is derived from the Navier-Stokes equation for the flow of an incompressible fluid between two smooth-parallel plates. Thus, the permeability of a single fracture depends only on the so-called hydraulic aperture which differs from the mechanical aperture (separation between the two fracture wall surfaces). This difference is mainly related to the roughness of the fracture walls, which has been evaluated in previous works by including a friction factor in the permeability equation or directly deriving the hydraulic aperture. However, these methodologies may lack adequate precision to provide valid results. This work presents a complete protocol for fracture surface mapping, roughness evaluation, fracture modeling, fluid flow simulation, and permeability estimation of individual fracture (open or sheared joint/pressure solution seam). The methodology includes laboratory-based high-resolution structure from motion (SfM) photogrammetry of fracture surfaces, power spectral density (PSD) surface evaluation, synthetic fracture modeling, and fluid flow simulation using the Lattice-Boltzmann method. This work evaluates the respective controls on permeability exerted by the fracture displacement (perpendicular and parallel to the fracture walls), surface roughness, and surface pair mismatch. The results may contribute to defining a more accurate equation of hydraulic aperture and permeability of single fractures, which represents a pillar for the modeling and upscaling of the hydraulic properties of a geofluid reservoir.

Latest developments in seismic texture analysis for subsurface structure, facies, and reservoir characterization: A review

Geophysics ◽  
2011 ◽  
Vol 76 (2) ◽  
pp. W1-W13 ◽  
Author(s):  
Dengliang Gao
Keyword(s):  
Texture Analysis ◽  
Reservoir Characterization ◽  
Preliminary Test ◽  
Seismic Facies ◽  
Least Squares Regression ◽  
Reservoir Properties ◽  
Seismic Amplitude ◽  
Texture Model ◽  
Facies Classification ◽  
Analysis Window

In exploration geology and geophysics, seismic texture is still a developing concept that has not been sufficiently known, although quite a number of different algorithms have been published in the literature. This paper provides a review of the seismic texture concepts and methodologies, focusing on latest developments in seismic amplitude texture analysis, with particular reference to the gray level co-occurrence matrix (GLCM) and the texture model regression (TMR) methods. The GLCM method evaluates spatial arrangements of amplitude samples within an analysis window using a matrix (a two-dimensional histogram) of amplitude co-occurrence. The matrix is then transformed into a suite of texture attributes, such as homogeneity, contrast, and randomness, which provide the basis for seismic facies classification. The TMR method uses a texture model as reference to discriminate among seismic features based on a linear, least-squares regression analysis between the model and the data within an analysis window. By implementing customized texture model schemes, the TMR algorithm has the flexibility to characterize subsurface geology for different purposes. A texture model with a constant phase is effective at enhancing the visibility of seismic structural fabrics, a texture model with a variable phase is helpful for visualizing seismic facies, and a texture model with variable amplitude, frequency, and size is instrumental in calibrating seismic to reservoir properties. Preliminary test case studies in the very recent past have indicated that the latest developments in seismic texture analysis have added to the existing amplitude interpretation theories and methodologies. These and future developments in seismic texture theory and methodologies will hopefully lead to a better understanding of the geologic implications of the seismic texture concept and to an improved geologic interpretation of reflection seismic amplitude.

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