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- Volume 57, Issue 2, 2009
Geophysical Prospecting - Volume 57, Issue 2, 2009
Volume 57, Issue 2, 2009
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Vertically fractured transversely isotropic media: dimensionality and deconstruction
More LessABSTRACTA vertically fractured transversely isotropic (VFTI) elastic medium is one in which any number of sets of vertical aligned fractures (each set has its normal lying in the horizontal x1, x2‐plane) pervade the medium and the sets of aligned fractures are the only features of the medium disturbing the axi‐symmetry about the x3‐axis implying that in the absence of fractures, the background medium is transversely isotropic (TI). Under the assumptions of long wavelength equivalent medium theory, the compliance matrix of a fractured medium is the sum of the background medium's compliance matrix and a fracture compliance matrix. For sets of parallel rotationally symmetric fractures (on average), the fracture compliance matrix is dependent on 3 parameters − its normal and tangential compliance and its strike direction. When one fracture set is present, the medium is orthorhombic and the analysis is straightforward. When two (non‐orthogonal) or more sets are present, the overall medium is in general elastically monoclinic; its compliance tensor components are subject to two equalities yielding an 11 parameter monoclinic medium. Constructing a monoclinic VFTI medium with n embedded vertical fracture sets, requires 5 TI parameters plus 3×n fracture set parameters. A deconstruction of such an 11 parameter monoclinic medium involves using its compliance tensor to find a background transversely isotropic medium and several sets of vertical fractures which, in the long wavelength limit, will behave exactly as the original 11 parameter monoclinic medium. A minimal deconstruction, would be to determine, from the 11 independent components, the transversely isotropic background (5 parameters) and two fracture sets (specified by 2 × 3 = 6 parameters). Two of the background TI medium's compliance matrix components are known immediately by inspection, leaving nine monoclinic components to be used in the minimal deconstruction of the VFTI medium. The use of the properties of a TI medium, which are linear relations on its compliance components, allows the deconstruction to be reduced to solving a pair of non‐linear equations on the orientations of two fracture sets. A single root yielding a physically meaningful minimum deconstruction yields a unique minimal representation of the monoclinic medium as a VFTI medium. When no such root exists, deconstruction requires an additional fracture set and uniqueness is lost. The boundary between those monoclinic media that have a unique minimal representation and those that do not is yet to be determined.
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Seismic characterization of reservoirs containing multiple fracture sets
More LessABSTRACTNatural fractures in reservoirs play an important role in determining fluid flow during production and knowledge of the orientation and density of fractures is required to optimize production. Variations in reflection amplitude versus offset (AVO) are sensitive to the presence of fractures but current models used to invert the seismic response often make simplified assumptions that prevent fractured reservoirs from being characterized correctly. For example, many models assume a single set of perfectly aligned fractures, whereas most reservoirs contain several fracture sets with variable orientation within a given fracture set. In addition, many authors only consider the azimuthal variation in the small offset amplitude versus offset and azimuth response (the variation in AVO gradient with azimuth), while the effect of fractures on amplitude versus offset and azimuth increases with increasing offset. In this paper, the variation in the reflection coefficient of seismic P‐waves as a function of azimuth and offset due to the presence of multiple sets of fractures with variable orientation within any fracture set is used to determine the components of a second‐rank fracture compliance tensor αij. The variation in the trace of this tensor as a function of position in the reservoir can be used to estimate the variation in fracture density with position in the reservoir and may be used to choose the location of infill wells in the field. The principal axes of αij reveal the most compliant direction within the reservoir and may be used to optimize the trajectory of deviated wells. The determination of the principal axes of αij requires wide azimuth acquisition and the use of the small‐offset amplitude versus offset and azimuth (the azimuthal variation of the AVO gradient) may give misleading results.
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Aligned vertical fractures, HTI reservoir symmetry and Thomsen seismic anisotropy parameters for polar media
More LessABSTRACTCertain crack‐influence parameters of Sayers and Kachanov are shown to be directly related to Thomsen's weak‐anisotropy seismic parameters for fractured reservoirs when the crack/fracture density is small enough. These results are then applied to the problem of seismic wave propagation in polar reservoirs, i.e., those anisotropic reservoirs having two axes that are equivalent but distinct from the third axis), especially for horizontal transversely isotropic seismic wave symmetry due to the presence of aligned vertical fractures and resulting in azimuthal seismic wave symmetry at the Earth's surface. The approach presented suggests one method of inverting for fracture density from wave speed data. A significant fraction of the technical effort in the paper is devoted to showing how to predict the angular location of the true peak (or trough) of the quasi‐SV‐wave for polar media and especially how this peak is related to another angle that is very easy to compute. The axis of symmetry is always treated here as the x3‐axis for either vertical transversely isotropic symmetry (due, for example, to horizontal cracks), or horizontal transversely isotropic symmetry (due to aligned vertical cracks). Then, the meaning of the stiffnesses is derived from the fracture analysis in the same way for vertical transversely isotropic and horizontal transversely isotropic media, but for horizontal transverse isotropy the wave speeds relative to the Earth's surface are shifted by 90o in the plane perpendicular to the aligned vertical fractures. Skempton's poroelastic coefficient B is used as a general means of quantifying the effects of fluids inside the fractures. Explicit Biot‐Gassmann‐consistent formulas for Thomsen's parameters are also obtained for either drained or undrained fractures resulting in either vertical transversely isotropic or horizontal transversely isotropic symmetry of the reservoir.
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Laboratory‐scale study of field of view and the seismic interpretation of fracture specific stiffness
Authors Angel Acosta‐Colon, Laura J. Pyrak‐Nolte and David D. NolteABSTRACTThe effects of the scale of measurement, i.e., the field of view, on the interpretation of fracture properties from seismic wave propagation was investigated using an acoustic lens system to produce a pseudo‐collimated wavefront. The incident wavefront had a controllable beam diameter that set the field of view at 15 mm, 30 mm and 60 mm. On a smaller scale, traditional acoustic scans were used to probe the fracture in 2 mm increments. This laboratory approach was applied to two limestone samples, each containing a single induced fracture and compared to an acrylic control sample. From the analysis of the average coherent sum of the signals measured on each scale, we observed that the scale of the field of view affected the interpretation of the fracture specific stiffness. Many small‐scale measurements of the seismic response of a fracture, when summed, did not predict the large‐scale response of the fracture. The change from a frequency‐independent to frequency‐dependent fracture stiffness occurs when the scale of the field of view exceeds the spatial correlation length associated with fracture geometry. A frequency‐independent fracture specific stiffness is not sufficient to classify a fracture as homogeneous. A nonuniform spatial distribution of fracture specific stiffness and overlapping geometric scales in a fracture cause a scale‐dependent seismic response, which requires measurements at different field of views to fully characterize the fracture.
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P‐wave dispersion and attenuation in fractured and porous reservoirs – poroelasticity approach
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.
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Computed tomography scan imaging of natural open fractures in a porous rock; geometry and fluid flow
Authors Ole Petter Wennberg, Lars Rennan and Remy BasquetABSTRACTComputed tomography scan imaging techniques have been used on core samples to investigate the effect of natural open fractures on reservoir flow in the Snøhvit Gas Condensate Field. Firstly, computed tomography (CT) scanning was used to describe the 3D geometrical properties of the fracture network including orientation and fracture density. Two types of fractures were observed: F1 fractures are short and stylolite related and F2 fractures are longer, cross‐cutting the core and without any obvious relationship to stylolites. Secondly, monitoring of single and two phase flow experiments on samples containing these two types of natural open fractures was performed under 10 and 80 bar net confining pressure while using CT scanning. 1‐phase miscible flooding experiment shows approximately 3 times higher flooding velocity in an open F2 fracture than in the matrix. 2‐phase flooding by gas injection into a 100% water saturated core gave early gas breakthrough due to flow in the fracture and thereafter very little water production. The flow experiments showed that the presence of open fractures has a significant local effect on fluid flow even in a case with relatively high matrix porosity (200–300 mD). The sample containing F1 fractures showed a complex flow pattern influenced both by open fractures and stylolites. The CT scan data enables an exact representation of the fracture network in core scale simulation models and therefore improves the understanding of fracture influence on flow in a fractured porous medium. CT scanning of core samples provides an effective tool for integrating geology and fluid flow properties of a porous fractured medium.
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Reconstruction of the layer anisotropic elastic parameters and high‐resolution fracture characterization from P‐wave data: a case study using seismic inversion and Bayesian rock physics parameter estimation
Authors Ran Bachrach, Mita Sengupta, Antoun Salama and Paul MillerABSTRACTWide‐azimuth seismic data can be used to derive anisotropic parameters on the subsurface by observing variation in subsurface seismic response along different azimuths. Layer‐based high‐resolution estimates of components of the subsurface anisotropic elastic tensor can be reconstructed by using wide‐azimuth P‐wave data by combining the kinematic information derived from anisotropic velocity analysis with dynamic information obtained from amplitude versus angle and azimuth analysis of wide‐azimuth seismic data. Interval P‐impedance, S‐impedance and anisotropic parameters associated with anisotropic fracture media are being reconstructed using linearized analysis assuming horizontal transverse anisotropy symmetry. In this paper it is shown how additional assumptions, such as the rock model, can be used to reduce the degrees of freedom in the estimation problem and recover all five anisotropic parameters. Because the use of a rock model is needed, the derived elastic parameters are consistent with the rock model and are used to infer fractured rock properties using stochastic rock physics inversion. The inversion is based on stochastic rock physics modelling and maximum a posteriori estimate of both porosity and crack density parameters associated with the observed elastic parameters derived from both velocity and amplitude versus angle and azimuth analysis. While the focus of this study is on the use of P‐wave reflection data, we also show how additional information such as shear wave splitting and/or anisotropic well log data can reduce the assumptions needed to derive elastic parameter and rock properties.
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An integrated multi‐azimuth VSP study for fracture characterization in the vicinity of a well
Authors Sonja Maultzsch, Ramin Nawab, Sung Yuh, Muhammad Idrees and Bernard FrignetABSTRACTWe present the analysis of a multi‐azimuth vertical seismic profiling data set that has been acquired in a tight gas field with the objective of characterizing fracture distributions using seismic anisotropy. We investigate different measurements of anisotropy, which are shear‐wave splitting, P‐wave traveltime anisotropy and azimuthal amplitude variation with offset. We find that for our field case shear‐wave splitting is the most robust measure of azimuthal anisotropy, which is clearly observed over two distinct intervals in the target. We compare the results of the vertical seismic profiling analysis with other borehole data from the same well. Cross‐dipole sonic and Formation MicroImager data from the reservoir section suggest that no open fractures intersect the well or are present within half a metre of the borehole wall. Furthermore, a detailed dispersion analysis of the sonic scanner data provides no indication of stress‐induced seismic anisotropy along the logged borehole section. We therefore explain the azimuthal anisotropy measured in the vertical seismic profiling data with a model that contains discrete fracture corridors, which do not intersect the well itself but lie within the vertical seismic profiling investigation radius. We show that such a model can reproduce some basic characteristics of azimuthal anisotropy observed in the vertical seismic profiling data. The model is also consistent with well test data that suggest the presence of a fracture corridor away from the well. With this study we demonstrate the necessity of integrating different data types that investigate different scales of rock volume and can provide complementary information for understanding the characteristics of fracture networks in the subsurface.
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A fracture network model and open fracture analysis of a tight sandstone gas reservoir in Dongpu Depression, Bohaiwan Basin, eastern China
Authors Qi Li, Tuofu Wang, Xinong Xie, Suwei Shao and Qingqing XiaABSTRACTFracture systems can significantly influence productivity in tight sandstone reservoirs. Understanding the in situ fracture network is of importance in exploration and development of such reservoirs. This paper illustrates that stress‐strain analysis, based on geological processes, is a credible prediction method for fracture networks and enables an estimation of which fractures are likely to contribute most to flow based on fracture orientation. This study shows the workflow for fracture modelling and its application in a sandstone reservoir using structural validation tools and interactive fracture simulations constrained with lithology, well log and core data. The fracture network model can help us understand not only what a fractured reservoir looks like but also how the existing fracture network behaves. An important consideration is that we need to understand and constrain the geological history to assess the fracture network properly.
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Geomechanical simulation to predict open subsurface fractures
Authors Helen Lewis, Stephen A. Hall and Gary D. CouplesABSTRACTGeomechanical simulation of the evolution of a geological structure can play an important role in predicting open fracture development for all stages in that structure's development. In this work, three such geomechanical simulations are used to predict the evolving stress and strain fields, including dilational and compactional changes in the rock fabric in developing fault and fold systems. Their consequences for open fracture development and flow are addressed. These simulated stress and strain fields show considerable spatial and temporal heterogeneity that is consistent with deformation patterns observed in both natural examples and in laboratory‐deformed analogues. But the stress and strain states that develop are neither co‐axial nor do they bear a simple relationship to one another. The dilational and compactional strains, manifest as open fracturing or sealing, represent some significantly increased or significantly decreased flow rates. However, open‐fracture predictions based on such geomechanical simulations are extremely difficult to validate with any degree of confidence as there is little direct evidence of sub‐surface fracture distributions. In this context we also discuss possible integration of seismic anisotropy measurements, as an independent measure of open fracture alignment, to support the geomechanically derived fracture predictions. The focus of this work is on volumetric strains in fault zone evolution, though folding is also addressed.
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Fluid‐induced seismicity: Pressure diffusion and hydraulic fracturing
Authors S.A. Shapiro and C. DinskeABSTRACTBorehole fluid injections are common for the development of hydrocarbon and geothermic reservoirs. Often they induce numerous microearthquakes. Spatio‐temporal dynamics of such induced microseismic clouds can be used to characterize reservoirs. However, a fluid‐induced seismicity can be caused by a wide range of processes. Here we show that linear pore pressure relaxation and a hydraulic fracturing are two asymptotic end members of a set of non‐linear diffusional phenomena responsible for seismicity triggering. To account for the whole range of processes we propose a rather general non‐linear diffusional equation describing the pore pressure evolution. This equation takes into account a possibly strong enhancement of the medium permeability. Both linear pore pressure relaxation and hydraulic fracturing can be obtained as special limiting cases of this equation. From this equation we derive the triggering front of fluid induced seismicity, which is valid in the general case of non‐linear pore pressure diffusion. We demonstrate corresponding seismicity signatures on different case studies.
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Volumes & issues
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Volume 72 (2023 - 2024)
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Volume 71 (2022 - 2023)
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Volume 70 (2021 - 2022)
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Volume 69 (2021)
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Volume 68 (2020)
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Volume 67 (2019)
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Volume 66 (2018)
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Volume 63 (2015)
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Volume 62 (2014)
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Volume 61 (2013)
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Volume 60 (2012)
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Volume 59 (2011)
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Volume 58 (2010)
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Volume 57 (2009)
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Volume 56 (2008)
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Volume 55 (2007)
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Volume 54 (2006)
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Volume 53 (2005)
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Volume 52 (2004)
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Volume 51 (2003)
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Volume 50 (2002)
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Volume 49 (2001)
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Volume 48 (2000)
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Volume 47 (1999)
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Volume 46 (1998)
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Volume 45 (1997)
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Volume 44 (1996)
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Volume 43 (1995)
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Volume 42 (1994)
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Volume 41 (1993)
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Volume 40 (1992)
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Volume 39 (1991)
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Volume 38 (1990)
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Volume 36 (1988)
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Volume 35 (1987)
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Volume 34 (1986)
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Volume 33 (1985)
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Volume 31 (1983)
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Volume 30 (1982)
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Volume 29 (1981)
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Volume 28 (1980)
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Volume 27 (1979)
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Volume 26 (1978)
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Volume 25 (1977)
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Volume 24 (1976)
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Volume 23 (1975)
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Volume 22 (1974)
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Volume 21 (1973)
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Volume 20 (1972)
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Volume 19 (1971)
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Volume 18 (1970)
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Volume 17 (1969)
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Volume 2 (1954)
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Volume 1 (1953)