Fractured reservoir delineation using multicomponent seismic data

… This offers the possibility of delineating fractured reservoirs and optimizing the development … in multicomponent data provides a useful phenomenon for delineating fractured reservoirs. …

… The integrated analysis and the final results confirm that we can characterize the reservoir heterogeneity from lithology to fractures as well as fluid distribution in the study area using …

High-resolution, time-lapse (4D), multicomponent (9C) seismic monitoring of a tertiary oil recovery project is being conducted by the Reservoir Characterization Project of the Colorado School of Mines. The project involves a miscible CO2 flood in a thin (30 m) carbonate reservoir at 1450 m depth in Weyburn Field, Saskatchewan. Multicomponent time-lapse seismic images illustrate the influence of fracture zones on the flood. These fracture zones are very important to characterize and monitor in order to manage the flood successfully and to achieve the desired improved recovery efficiency. The monitoring project offers insights into the future of dynamic reservoir characterization with 4D, 9C seismic technology.

… DNN and driven by multi-component seismic data, we could push the limited gas-bearing information of the known drilling area to the entire area to predict gas reservoir distribution. To …

Geophysicists have devoted great efforts to the problem of determining fluid saturation from seismic measurements, with some notable successes. It is commonly believed that fluid information is to be found in the P‐wave data, with shear‐waves being insensitive to fluid, and indeed almost all successful fluid‐detection methodologies have been based on analysis of the P‐wave.

… present a multi-component passive seismic analysis to provide in situ observations of the fault and fracture architecture of the Ekofisk reservoir. Small-scale active tectonic fractures are …

Searching for hydrocarbon reserves in deep subsurface is the main concern of wide community of geophysicists and geoscientists in petroleum industry. Exploration seismology has substantially contributed to finding and developing giant fields worldwide. The technology has evolved from two to three-dimensional method, and later added a fourth dimension for reservoir monitoring. Continuous depletion of many old fields and the increasing world consumption of crude oil pushed to consistently search for techniques that help recover more reserves from old fields and find alternative fields in more complex and deeper formations either on land and in offshore. In such environments, conventional seismic with the compressional (P) wave alone proved to be insufficient. Multicomponent seismology came as a solution to most limitations encountered in P-wave imaging. That is, recording different components of the seismic wave field allowed geophysicists to map complex reservoirs and extract information that could not be extracted previously. The technology demonstrated its value in many fields and gained popularity in basins worldwide. In this review study, we give an overview about multicomponent seismology, its history, data acquisition, processing and interpretation as well as the state-of the-art of its applications. Recent examples from world basins are highlighted. The study concludes that despite the success achieved in many geographical areas such as deep offshore in the Gulf of Mexico, Western Canada Sedimentary Basin (WCSB), North Sea, Offshore Brazil, China and Australia, much work remains for the technology to gain similar acceptance in other areas such as Middle East, East Asia, West Africa and North Africa. However, with the tremendous advances reported in data recording, processing and interpretation, the situation may change.

… matrix affected by natural fractures. This paper describes a 3D multi-component land seismic project conducted in Algeria, designed to perform a fracture characterization study. This …

… The significance of the porefracture type reservoir response … porefracture reservoirs,helps to understand the actual seismic data phenomena of complex porefracture reservoirs,and …

Summary Carbonate reservoirs are often very heterogeneous and their properties are frequently difficult to understand. The presence of faults and intense natural fractures further increases the complexity that becomes very challenging for reservoir management and field development. This is the case of the Shuaiba reservoir in Idd El Shargi North Dome (ISND) Field in offshore Qatar. The field was discovered in 1960 and was first produced in 1964. The oil is produced from multiple reservoirs, primarily carbonate, on a salt induced faulted anticline. After 1995, when Occidental Petroleum assumed the operatorship role under a Production Sharing Agreement with the State of Qatar, an extensive horizontal well drilling and waterflood campaign resulted in a substantial production increase from the primary Arab and Shuaiba reservoirs. This paper will focus on the Shuaiba development results. New technologies have been applied to effectively manage the Shuaiba waterflood and continuously increase the oil recovery factor in this complex reservoir. The practical aspects of multi-component seismic technology described in this paper can be applied in any complex fractured reservoir for improving efficiency and increasing recovery. During 2003–2005, Qatar Petroleum and Oxy acquired and processed a large 4C3D seismic survey over Idd El Shargi field (Fig.1). This technology uses multi-component phones and cross-spread acquisition geometry to record both compressional and shear (converted) waves. The survey ensured full azimuth coverage to offsets up to 3000 m, equivalent to an offset/depth ratio of two for the main target zone, achieving a nominal fold of 240 in the natural bin size, or a trace density of more than 2.7 million traces per square kilometer. The data were processed through a flow that carefully preserved the azimuthal anisotropy (Angerer et al, 2006).

In an azimuthally anisotropic medium, the principal directions of azimuthal anisotropy are the directions along which the quasi P and the quasi S waves propagate as pure P and S modes. When the azimuthal anisotropy is induced by oriented vertical fractures, two of these principal directions correspond to the directions parallel to and perpendicular to the fractures. S-waves propagating through an azimuthally anisotropic medium are extremely sensitive to the direction of their propagation with respect to the principal directions. As a result, primary or mode converted S-wave data can be used to obtain the principal directions from seismic data. Apart from the high acquisition cost, processing and interpretation of S-wave data require a special processing technology. Moreover S-wave data quality is poor in many regions. Thus, an alternative involving only P-wave data is attractive but is limited to a few qualitative studies of the amplitude-variation-with-offset (AVO) for different azimuthal directions (Mallick and Frazer, 1991; Chang and Gardner, 1993; Allen and Peddy, 1993 ; Lefeuvre, 1994 ; Lynn et.al, 1995, Rüeger and Tsvankin, 1995), and to velocity studies of selected horizons on data for different common mid point (CMP) locations (Neidell and Cook, 1986).

Abstract Seismic reflection data provide the opportunity to detect fractures in the subsurface and infer certain properties of the fractures. To help geophysicists unfamiliar with fracture-characterization techniques succeed, we introduce fundamentals of these techniques, explain the emergence and physical meaning of parameters governing the effective elasticity of fractured rocks, and discuss seismic signatures that make estimation of those governing parameters possible.

… show the advantage of multi-component seismic data for imaging the Grane reservoir, which is under development, and in particular for contributing to the reservoir characterization and …

Multicomponent seismology requires recording of seismic data with three- and sometimes four-component receivers. The three components measure displacement of the ground, usually in two horizontal and one vertical directions. The fourth component is a measurement of pressure, which is used in sea-bottom surveys. Measuring three components of ground displacement enables the recording of compressional (P) and shear (S) waves which represent the full complement of “body” waves in seismology. Earthquake seismologists have been using the full complement for years to interpret the structure of our living planet; however, exploration seismologists have been slow to bring multicomponent seismology to the forefront of their measurement system. This is finally changing. Thanks to new seismic acquisition recording systems, it is now feasible to economically record multicomponent seismic data in both land and marine (sea-bottom) settings. In the future, all land or sea-bottom seismic data will be recorded by multicomponent technology, thereby bringing us the next wave of exploration geophysics as we begin to “see the unseen.”

… performing cost-effective multicomponent (P-wave and PS-wave) surveys, there is a tremendous potential to produce fractured reservoirs more efficiently. 3D seismic surveys often cost …

… The use of multicomponent seismic data reduces the number of solutions in reservoir … In nonmarine, fractured oil-gas reservoirs, converted waves can be used to study the azimuth …

… as low permeability, developed fractures, and strong … multicomponent seismic data as well as to integrate various types of seismic data for the analysis of tight sandstone gas reservoirs. …

Amplitude variation with azimuth (AVAz) is commonly used to predict subsurface fracture properties. Published analyses demonstrate the ambiguous characterization from PP-wave AVAz for a vertical set of rotationally variant fractures. Thus, the extra information hidden in converted wave AVAz is worth being analyzed. We consider the linear-slip theory to model a vertical or tilted set of rotationally variant fractures in either of two welded half-spaces with polar anisotropy. The AVAz of PP- and converted waves are investigated to determine their ability to create unambiguous fracture characterizations. Reflectivity approximations are derived for PP- and converted waves to extract their AVAz attributes exclusively depending on fracture properties. We consider pseudo-PSV- and pseudo-PSH-waves with linear reflectivity approximations transformed from the nonlinear ones for typical converted waves in fractured media. The pseudo converted waves degenerate into the typical PSV- and PSH-waves when the incident medium is azimuthally isotropic. For a vertical fracture set, the AVAz of PSV- and PSH-waves convey no more deterministic fracture information than that of PP-waves. It is demonstrated that the unambiguous characterization is feasible for a fluid-filled vertical fracture set whereas might be not for a gas-filled one. For a tilted fracture set, the fracture normal azimuth can be obtained uniquely from the AVAz of PSV- or PSH-waves but ambiguously from the PP-wave counterpart. Using multi-wave AVAz attributes only gives rather vague estimates of the fracture tilt angle. For both vertical and titled fracture sets, numerical model tests demonstrate overall better inversions from jointly using PP- and PSV-waves than solely using either of them.

Anisotropy and fracture characterization in individual layers is realized through iterative layer stripping corrections of four, converted-wave (PS-wave) synthetic reflection seismic data sets, generated from azimuthally anisotropic (HTI and TTI) models, and a four component (4-C) data set from the Teal South, Gulf of Mexico. The corrections were applied on a layer-by-layer basis to evaluate the efficacy of constant polarization rotation and time-shift operators. Equivalent isotropic models were compared to anisotropic models after layer-stripping corrections using rms amplitude and shear-wave-splitting time-difference maps to quantify and identify inherent errors in estimating seismic polarization parameters. For HTI media radial and transverse components of PS data that have had layer-stripping corrections applied, exhibit incorrect symmetry and orientations. This may adversely affect inversion and/or amplitude-variation with angle offset (AVO) and amplitude versus azimuth (AVA)analysis. Layer-stripping corrections applied to fast and slow (PS1 and PS2, respectively) components exhibit the correct symmetry and orientation. Time differences between PS1 and PS2 are computed using crosscorrelation. Previous studies have addressed some of the problems associated with layer-stripping corrections for the case of vertical fractures (HTI media) and poststack layer-stripping analyses. This study includes an equivalent model with dipping fractures (TTI media) and extends the scope to encompass the effects of anisotropy on prestack data. The results from an application of the same technique are also applied to a limited set of 4-C data from the Teal South project in the Gulf of Mexico. Results are consistent with those of previous studies involving solely poststack 4-C rotation analysis in terms of average, or zero offset, time differences and symmetry orientation. Offset and azimuth amplitude/traveltime variations, however, indicate that there is more information contained in prestack seismic data than 4-C rotation can comprehend.

… significance for better utilizing scattered waves for fracture detection and characterization. … comprise converted reflected P waves (SP), pure reflected SH waves, and pure reflected SV …

… 3-D converted P to S-waves (PS-waves) provide an excellent opportunity to exploit upgoing shear-wave (S-wave) birefringence (splitting) for delineating reservoir fractures. In …

… along the fracture and converts into tube wave upon … external seismic wave field that illuminates the well and the fracture. … fracture of a finite size, and generated by an external seismic …

… based converted-wave technology for evaluating fractured tight… Fracture characterization is critical for ensuring economic … of P-wave techniques for characterizing these fractures has not …

Existing geophysical and geological data indicate that orthorhombic media with a horizontal symmetry plane should be rather common for naturally fractured reservoirs. Here, we consider two orthorhombic models: one that contains parallel vertical fractures embedded in a transversely isotropic background with a vertical symmetry axis (VTI medium) and the other formed by two orthogonal sets of rotationally invariant vertical fractures in a purely isotropic host rock. Using the linear-slip theory, we obtain simple analytic expressions for the anisotropic coefficients of effective orthorhombic media. Under the assumptions of weak anisotropy of the background medium (for the first model) and small compliances of the fractures, all effective anisotropic parameters reduce to the sum of the background values and the parameters associated with each fracture set. For the model with a single fracture system, this result allows us to eliminate the influence of the VTI background by evaluating the differences between the anisotropic parameters defined in the vertical symmetry planes. Subsequently, the fracture weaknesses, which carry information about the density and content of the fracture network, can be estimated in the same way as for fracture-induced transverse isotropy with a horizontal symmetry axis (HTI media) examined in our previous paper (part I). The parameter estimation procedure can be based on the azimuthally dependent reflection traveltimes and prestack amplitudes of P-waves alone if an estimate of the ratio of the P- and S-wave vertical velocities is available. It is beneficial, however, to combine P-wave data with the vertical traveltimes, NMO velocities, or AVO gradients of mode-converted (PS) waves. In each vertical symmetry plane of the model with two orthogonal fracture sets, the anisotropic parameters are largely governed by the weaknesses of the fractures orthogonal to this plane. For weak anisotropy, the fracture sets are essentially decoupled, and their parameters can be estimated by means of two independently performed HTI inversions. The input data for this model must include the vertical velocities (or reflector depth) to resolve the anisotropic coefficients in each vertical symmetry plane rather than just their differences. We also discuss several criteria that can be used to distinguish between the models with one and two fracture sets. For example, the semimajor axis of the P-wave NMO ellipse and the polarization direction of the vertically traveling fast shear wave are always parallel to each other for a single system of fractures, but they may become orthogonal in the medium with two fracture sets.

… for fracture characterization, such as amplitude variations with offset and azimuth and shear wave … P arrivals, (2) surface waves, (3) P-to-S converted waves from the interface below the …

… , and conversion of plane waves incident upon a fracture at arbitrary angles. … waves such as transmitted waves, reflected waves, converted waves, head waves, and P interface waves …

… converted to particle motions by assuming that the wave travels without dispersion and using the measured velocity of the wave to convert … useful in the characterization of fractured rock …

… cracks or macroscale fractures. Reservoir engineers … of fracture characterization. Quantitative discrimination between the two scales (micro and macro) when characterizing fractures is …

… The complete solutions for seismic wave reflection, conversion, and transmission across a displacement and velocity discontinuity between two halfspaces with different densities and …

… that require fractures to be produced economically. Therefore, techniques that can identify sets of aligned fractures are becoming more important. Fracture identification is also important …

… A system for remote seismic fracture detection as envisioned here will help maximize the cost-effectiveness of environmentally clean geothermal resources for the benefit of the general …

… and widely applied approach for fracture detection. … a method for shear-wave splitting wavefield separation and fracture … wave azimuthal anisotropy and shear-wave splitting in multilayer …

… , so that knowledge of the subsurface fracture system is of vital importance for an accurate … To detect the geometry and density of fracture systems we applied the shear-wave splitting …

… The ability to detect aligned fractures using seismic anisotropy provides a valuable tool for … by observing shear wave splitting. However, the interaction of shear waves with subsurface …

… modified appropriately, lead to fracturing, faulting and … control shear wave splitting also control low-level (pre-fracturing) … could be detected by monitoring shear wave splitting with cross-…

… variations in shear wave splitting offers a useful probe of stress-related changes in the evolution of crack and fracture networks. Here, we present shear wave splitting analysis of …

… uses of shear-wave splitting as an imaging tool in fracture-… whether shear-wave splitting measurements can detect the … the fast and slow split shear waves changed significantly and …

… for fracture delineation we are looking for split-shear waves, … and extract information from split-shear waves in seismic data. … detection and description of fractured zones from split-shear …

… Z N /Z T with shear wave splitting can potentially allow us to remotely detect changes in … Here we study shear wave splitting during a multistage hydraulic fracture stimulation in a tight-…

… shear wave splitting is caused by fluid‐filled crustal microcracks and macrofractures aligned in the N‐S direction. The shear wave splitting … No systematic change of shear wave splitting …

… vertical fractures, the shear‐wave splitting depends on the shear … fractures are not perfectly vertical, the shear‐wave splitting also varies with the normal compliance of the fractures. If the …

… Fracture detection and mapping is important in … The presence of frequency-dependent shearwave splitting requires … Thus frequency-dependent shearwave splitting and seismic …

… stiffness, one can estimate the bulk property of average fracture … to fracture detection was carried out in a multioffset survey in the fall of 1984. Compressional-wave and shear-wave …

… , which are polarized in the so-called natural coordinate system associated with the fractures… The fidelity of shearwave splitting observations on land data would certainly improve if more …

… analysis can aid identification and estimation of shear-wave splitting from seismic sections, help … Prediction of lateral variability in fracture intensity using multicomponent shear-wave …

… [1] We present an automatic shear wave splitting measurement tool for local earthquakes, with the sole manual step of choosing an S arrival time. We apply the technique to three data …

PreviousNext No AccessSEG Technical Program Expanded Abstracts 1991Thin layers and shear‐wave splittingAuthors: R. D. SlackD. A. EbromJ. A. McDonaldR. H. TathamR. D. SlackCogniSeis Development, D. A. EbromUniv. of Houston Allied Geophysical Labs, J. A. McDonaldUniv. of Houston Allied Geophysical Labs, and R. H. TathamTexaco Inc.https://doi.org/10.1190/1.1888993 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Permalink: https://doi.org/10.1190/1.1888993FiguresReferencesRelatedDetailsCited ByOPTIMAL ESTIMATION OF CRACK-STRIKE1Geophysical Prospecting, Vol. 40, No. 8 SEG Technical Program Expanded Abstracts 1991ISSN (print):1052-3812 ISSN (online):1949-4645Copyright: 1991 Pages: 1646 publication data© 1991 Copyright © 1991 Society of Exploration GeophysicistsPublisher:Society of Exploration Geophysicists HistoryPublished: 10 Feb 2005 CITATION INFORMATION R. D. Slack, D. A. Ebrom, J. A. McDonald, and R. H. Tatham, (1991), "Thin layers and shear‐wave splitting," SEG Technical Program Expanded Abstracts : 1549-1552. https://doi.org/10.1190/1.1888993 Plain-Language Summary PDF DownloadLoading ...

This case history is one of three field projects funded by the US Department of Energy as part of its ongoing research effort aimed to expand current levels of drilling and production efficiency in naturally-fractured tight-gas reservoirs. The original stated goal for the 3-D P-wave seismic survey was to evaluate and map fracture azimuth and relative fracture density throughout a naturally-fractured gas reservoir interval. At Rulison field, this interval is the Cretaceous Mesaverde, approximately 2500 ft (760 m) of lenticular sands, silts, and shales. Three-dimensional full-azimuth P-wave data were acquired for the evaluation of azimuthal anisotropy and the relationship of the anisotropy to commercial pay in the target interval. The methodology is based on the evaluation of two restricted-azimuth orthogonal (source-receiver azimuth) 3-D P-wave volumes aligned with the natural principal axes of the azimuthal anisotropy, as estimated from velocity analysis of multiazimuth prestack gathers. The Dix interval velocity, as well as the interval amplitude variation with offset (AVO) gradient, was calculated for both azimuths for the gas-saturated Mesaverde interval. The two seismic attributes best correlated with commercial gas pay (at a 21-well control set) were (1) values greater than 4% azimuthal variation in the interval velocity ratio (source-receiver azimuth N60E/N30W) of the target interval (the gas-saturated Mesaverde), and (2) the sum of the interval AVO gradients (N60E + N30W). The sum of the interval AVO gradients is an attribute sensitive to the presence of gas, but not diagnostic of an azimuthal variation in the amplitude. The two-azimuth interval velocity anisotropy mapped over the survey area suggests spatial variations in the orientation of the maximum horizontal stress field and the open (to flow) fracture system.

… of the processing on the final fracture interpretation, Figure 6 presents two sets of seismic anisotropy maps estimated from azimuthal RMS amplitude maps computed on a 100 ms time …

Studying the seismic responses of velocity and amplitude on wide-/full-azimuth seismic data is now common for unconventional reservoir characterization. Velocity variation with azimuth (VVAz) and amplitude variation with azimuth (AVAz) are two of the most popular tools to map not only the relative intensity and orientation of natural fractures but also the strength and orientation of the maximum horizontal stress SH. We prestack time migrated a wide-azimuth Barnett Shale survey in North Texas into eight azimuths and reduced noise on the gathers using prestack structure-oriented filtering. We then computed the envelope, spectral peak frequency, and prestack P-wave impedance attributes for each azimuthally limited seismic volume. We compensated the VVAz effects by flattening each sector along the Barnett Shale key horizons, thereby registering the gathers for subsequent AVAz analysis. The results indicate the intensity, orientation, and confidence of azimuthal anisotropy effects on seismic velocity and amplitude, which can be referred to smaller scale vertical cracks or natural fractures. Our analysis reveals four zones of high anisotropy intensity that can be tied to either the regional structures or paleo stress field. Analysis of production data indicate from the anisotropy interpretation results that vertical, sealed fractures are the dominant cause of anisotropy and those specific fractures inhibit production. This observation and results indicate that horizon-based azimuthal anisotropy analysis avoids the VVAz effect and can be applied to fractures and regional stress field prediction. Introduction The strike orientation of openmicrocracks, which represents the present-day stress field, plays a key role in allocating and developing shale resource plays. Our goal is to determine if the anisotropy obtained from amplitude variation with azimuth (AVAz) analysis of a wide-azimuth survey can be correlated to natural fracture distribution and orientation in a shale reservoir. Residual moveout analysis and near core characterization indicate that the Barnett Shale reservoir exhibits moderate horizontal transverse isotropy (HTI) and relatively weak layering-induced vertical transverse isotropy (Gale et al., 2007, 2010, 2014). The moderate intensity of azimuthal anisotropy allows us to use Thomsen (1986) anisotropy analysis. We assume that the main cause of azimuthal anisotropy in the survey is attributed to microcracks that are open perpendicular to the minimum horizontal stress. Natural fracture characterization Natural fracture occurrence in unconventional shale reservoirs has received considerable attention because of its potential impact on reservoir quality characterization. Numerous studies have been conducted based on outcrop, core, and subsurface data to understand the origin, preferential distribution pattern, and impact factors on fracture occurrence (Nelson, 2001; Curtis, 2002; Gale et al., 2007; Olson and Taleghani, 2009; Gale and Holder, 2010; Cho et al., 2013). Due to limited access to subsurface data, field fracture characterization is commonly used as an analog (Hennings et al., 2000; Nelson, 2001; Olson and Taleghani, 2009; Milad et al., 2018). Outcrop analogs provide linkage between natural fracture density with bedding thickness and composition. However, other controlling factors include variability in deformational history, initial burial depth, and confining pressure are involved in complexity as well (Hanks et al., 1997; Bai and Pollard, 2000; Nelson, 2001; Galvis-Portilla et al., 2016; Ghosh, 2017). Compared to outcrop analogue characterization, fractures seen in drilled core or downhole image logs are more direct ways to quantify fractures under reservoir conditions. However, such objectives provide only University of Oklahoma, Norman, Oklahoma 73071, USA and State Key Laboratory of Shale Oil and Gas Enrichment Mechanism and Effective Development, Beijing, China. E-mail: jing.zhang@ou.edu University of Oklahoma, Norman, Oklahoma 73071, USA. E-mail: jie.qi@ou.edu (corresponding author); kmarfurt@ou.edu; rslatt@ou.edu. State Key Laboratory of Shale Oil and Gas Enrichment Mechanism and Effective Development, Beijing, China. E-mail: zengyj.sripe@sinopec.com. Manuscript received by the Editor 23 September 2019; revised manuscript received 20 December 2019; published ahead of production 29 May 2020; published online 26 June 2020. This paper appears in Interpretation, Vol. 8, No. 4 (November 2020); p. SP13–SP29, 20 FIGS., 1 TABLE. http://dx.doi.org/10.1190/INT-2019-0206.1. © 2020 Society of Exploration Geophysicists and American Association of Petroleum Geologists. All rights reserved. t Special section: Seismic interpretation of fractures in deep subsurface Interpretation / November 2020 SP13 D ow nl oa de d 06 /3 0/ 20 to 6 8. 22 8. 16 8. 19 0. R ed is tr ib ut io n su bj ec t t o SE G li ce ns e or c op yr ig ht ; s ee T er m s of U se a t h ttp :// lib ra ry .s eg .o rg /p ag e/ po lic ie s/ te rm s D O I: 10 .1 19 0/ IN T -2 01 902 06 .1 a local, 1D knowledge of the subsurface, which may be difficult to extrapolate to three dimensions (Narr and Lerche, 1984; Lorenz and Hill, 1992; Narr, 1996; Nelson, 2001; Fernández-Ibáñez et al., 2018). A more promising workflow for 3D fracture analysis on a larger scale is to tie the relatively qualitative but dense 3D seismic response to the more quantitative sparse well control. Seismic-based analysis can be applied on natural fractures and hydraulic fractures (Tsvankin and Grechka, 2011; Liu, 2013; Yuan et al., 2018). However, the limited resolution of seismic data with wavelengths of approximately 50 m is challenging to show small-scale (on the order of 10 m), detailed features such as fracture spacing in the Barnett Shale. Even though there are indications of scattering form fractured zones, details on the orientation and density of the fracture system are still hard to verify (Liu, 2013). Neves et al. (2004), Chopra and Marfurt (2007), and Guo et al. (2010) find correlations between the fracture distribution and seismic attributes such as coherence and curvature. Outcrop analysis and finite element models show a good correlation of fractures to the proximity of faults and the intensity of folding, which in turn can be mapped by seismic attributes such as coherence and curvature (Busetti et al., 2012). The presence of such fractures is “inferred” using a deformation model. In contrast, AVAz provides a more direct measure of the presence of natural fractures and stress direction (Liu, 2013). Anisotropy The existence of natural fractures or discontinuities in subsurface are known to influence the traveltimes and amplitudes of seismic waves (Anderson et al., 1974; Kuster and Toksöz, 1974; Boadu, 1995; Boadu and Long, 1996). When clustered fractures are near vertical and maintain a consistent strike direction, the medium will exhibit HTI (Wang, 2002; Helbig and Thomsen, 2005; Tsvankin and Grechka, 2011; Liu, 2013; Alali, 2018; Shi et al., 2018). Seismic compressional wave (P-wave) propagation will be affected when passing through the HTI medium with a corresponding azimuthal variation: (1) a slowed P-wave velocity with the maximum velocity attenuation orthogonal to the fracture plane (fracture strike orientation) and a faster P-wave velocity along the fracture plane (fracture strike orientation) (Anderson et al., 1974; Kuster and Toksöz, 1974; Boadu, 1995; Clifford et al., 2005). This variation results in different arrival times and reflection coefficients for the sourcereceiver on different azimuths. (2) P-wave attenuation due to scattering with the maximum extent when perpendicular to the fracture strike direction, which can be reflected as the amplitude and other amplitude-related seismic attributes attenuation (Maultzsch et al., 2007; Thompson et al., 2010). The amplitude attenuation can be observed from different azimuths and offsets (Samec and Blangy, 1992; Zhu et al., 2007; Sharma et al., 2018) (Figure 1). AVAz of azimuthally sectored migrated seismic data provides a means to map the intensity and orientation of the HTI medium anisotropy (Gray and Head, 2000; Rüger, 2002; Gray et al., 2003; Gray, 2008; Mahmoudian et al., 2013; Liu, 2014; Qi et al., 2015; Wang et al., 2015). AVAz analysis requires the acquisition of wide-/full-azimuth seismic data with sufficient offsets (Rüger, 2002). Thompson et al. (2010) show how one can calculate the intensity (ε), azimuth (Ψ), and confidence (c) of these measures by fitting an ellipse to the different azimuth volumes in each gather for HTI media. For this case study, we began with conducting seismic interpretation on eight azimuthal gathers from one wide-azimuth survey and then we calculated the amplitude-related seismic attributes for each azimuthal gather; next, we flattened the attribute based on seismic key horizons from interpretation and input into AVAz workflow to obtain the key parameters of anisotropy. We conclude the relationship between natural fractures distribution and seismic azimuthal anisotropy by comparing with the gas production map in the study area. Geologic background This case study targets the Barnett Shale in the Fort Worth Basin, North Texas, USA (Figure 2). The Mississippian-age Barnett Shale is an organic-rich shale gas reservoir exploited in North America (Singh et al., 2008). The Fort Worth Basin is a foreland basin formed during the late Paleozoic due to the Ouachita orogeny (Walper, 1981; Thompson, 1988). The basin is bounded by the Red River Arch and the Muenster Arch in the north, the Ouachita Thrust-Fold Belt in the east, the Llano Uplift paleohigh in the south, and the Bend Arch in the west. Within the basin, the major Mineral Wells Fault is oriented in a northeast–southwest direction (Pollastro et al., 2007) (Figure 2). Figure 1. Seismic-wave attenuation and velocity reduction when penetrated perpendicular to the fracture strike direction. SP14 Interpretation / November 2020

We extend time-domain velocity continuation to the zero-offset 3D azimuthally anisotropic case. Velocity continuation describes how a seismic image changes given a change in migration velocity. This description turns out to be of a wave propagation process, in which images change along a velocity axis. In the anisotropic case, the velocity model is multiparameter. Therefore, anisotropic image propagation is multidimensional. We use a three-parameter slowness model, which is related to azimuthal variations in velocity, as well as their principal directions. This information is useful for fracture and reservoir characterization from seismic data. We provide synthetic diffraction imaging examples to illustrate the concept and potential applications of azimuthal velocity continuation and to analyze the impulse response of the 3D velocity continuation operator.

Recent advances in parameter estimation and seismic processing have allowed incorporation of anisotropic models into a wide range of seismic methods. In particular, vertical and tilted transverse isotropy are currently treated as an integral part of velocity fields employed in prestack depth migration algorithms, especially those based on the wave equation. We briefly review the state of the art in modeling, processing, and inversion of seismic data for anisotropic media. Topics include optimal parameterization, body-wave modeling methods, P-wave velocity analysis and imaging, processing in the τ-p domain, anisotropy estimation from vertical-seismic-profiling (VSP) surveys, moveout inversion of wide-azimuth data, amplitude-variation-with-offset (AVO) analysis, processing and applications of shear and mode-converted waves, and fracture characterization. When outlining future trends in anisotropy studies, we emphasize that continued progress in data-acquisition technology is likely to spur transition from transverse isotropy to lower anisotropic symmetries (e.g., orthorhombic). Further development of inversion and processing methods for such realistic anisotropic models should facilitate effective application of anisotropy parameters in lithology discrimination, fracture detection, and time-lapse seismology.

… prestack fracture prediction, azimuthal anisotropy is … Δ R represents azimuthal anisotropy strength, and ϕ 0 denotes fracture … Map-view comparison of field fracture-prediction results from …

… (size) of the fracture causing the azimuthal anisotropy. This paper … is azimuthal traveltimes, best quantified as PP azimuthal interval … (fault and fracture normal) mapped in the basement. …

… Field mapping documented a set of fractures striking N69E which are approximately parallel … the seismic responses theoretically expected of an azimuthally anisotropic earth, ie, one in …

We suggest and test a new way to define azimuth binning in Kirchhoff prestack migration. With this new definition, we sort seismic data by the azimuth of the average travel path traversed from the source to the subsurface image point and back to the receiver, rather than the azimuth between source and receiver on the surface of the earth. This approach avoids mixing the typically weaker side-scattered energy with the stronger in-plane reflections, thereby providing greater leverage in identifying image contributions from out-of-the-plane steeply dipping reflectors, fractures and faults. We examine the impact of this new imaging approach combined with analysis of seismic attributes that have proved useful for fracture detection, on data from the Fort Worth Basin, Texas, United States. We find that the image of features such as reflectors and discontinuities focus into azimuths perpendicular to the strike of each feature. The discrimination achieved in the azimuthal domain allows for an increased resolution in analysis of geologic features according to their strike direction. It should also result in improved residual azimuthal velocity analysis.

We have tested an amplitude-based multiazimuth approach for mapping fractures which requires only a simple azimuth-offset sorting process. By displaying the amplitudes of all traces collected within a superbin, the method predicts fractures by mapping P-wave amplitude variations, in which a lineation within the map indicates the presence and the orientation of fractures within the superbin. Test results using physical model and field data sets suggest that the amplitude-based multiazimuth approach could help to determine the presence of multiple fracture sets in a single layer, which may be expressed through subtle variations in P-wave multiazimuthal seismic reflections. Our experiments with a physical model containing manmade vertical fractures suggest that transmission effects could be one of the dominant factors which control azimuthal amplitude versus offset (AVO) behavior. The technique described in this paper can operate on any 3D P-wave seismic data with wide azimuth and offset distributions.

We have evaluated a novel fracture characterization technique using azimuthal amplitude variations (AVAz) present in 3D seismic data, and we implemented it using synthetic and real seismic data targeting the Haynesville Shale. The method we evaluated overcomes many common AVAz limitations and differs from standard AVAz approaches in the following ways: (1) It was explicitly designed to model vertically fractured transverse isotropic (VFTI) media; (2) it can correctly resolve the fracture strike azimuth without a 90° ambiguity and uses a new magnitude-based method that is invariant to the sign of seismic reflectivity (Rpp); and (3) it incorporates advanced inversion techniques to estimate a novel fracture density proxy that responds linearly to crack density. Our method is based on a newly derived relationship that relates seismic reflectivity directly to rock/fracture properties in VFTI media. We validated our method through rigorous testing on more than 400 synthetic seismic data sets. These synthetic tests indicate that our method excels at estimating fracture azimuth and fracture density from surface seismic data with overall success rates around 80%–85% for noisy data and 90%–95% for noise-free data. Applying our method to field data from the Haynesville Shale indicates that the dominant fracture set is oriented at approximately +80° relative to geodetic north, i.e., rotated slightly counterclockwise of east–west. We assume a constant azimuth of 80° throughout our relatively small 20 square miles study area, and our method clearly identifies a general area with unusually high fracture density as well as several smaller subzones of dense fracturing. These smaller features appear to be connected by a pervasive large-scale fracture network covering the area with dominant features aligned at roughly parallel and perpendicular to our calculated fracture azimuth. Although we could not directly confirm these fracture characteristics, our results largely agree with previously published information about fracturing in our study area.

Fracture monitoring is crucial for many geo-industrial applications, such as carbon dioxide storage and hydrocarbon exploration in tight reservoirs, because fractures can form storage space or leaking paths for geological sealing. We propose a fracture identification framework for geo-industrial applications by exploiting seismic reflection anisotropy and automatic multisensitive attribute fusion. Anisotropy maps extracted from different seismic attributes are automatically selected and fused according to the correlation between the predicted anisotropy strengths and the measured fracture densities at well locations. Through seismic anisotropy extraction and automatic multisensitive attribute fusion, we can acquire a more comprehensive evaluation of different fracture types in a reservoir. The proposed fracture identification framework is successfully applied to a deep, tight sandstone reservoir in Southwest China. The predicted fracture distribution is closely related to the local structures in the target reservoir. The orientations of the most predicted fractures are consistent with the local maximum principal stress direction in this area, which is good for the opening and fluid filling of fractures. The fracture identification results will be used to guide hydrocarbon exploration activities in this region, such as exploration well deployment.

… They map the regional and in situ fracture populations at a … outcrop fracture mapping, borehole televiewer data, the fracture … Bielanski, Azimuthal anisotropy: Occurrence and effect of …

Horizontally transverse isotropy (HTI) induced by vertical or subvertical, aligned fractures is common for unconventional fractured porous shale oil or gas reservoirs. Compared with the unfractured rocks, the seismic response characteristics of PP-wave azimuthal amplitudes are usually disturbed by the fractures and the in-situ stresses. Knowledge of fracture properties, as well as in-situ stresses, is required to optimize horizontal well planning and hydraulic fracturing during production, and seismic inversion for in-situ stresses from the PP-wave azimuthal amplitude data in fracture-induced anisotropic media is an essential step. Using the linear-slip theory and the effective stress law, we derive the fluid-saturated effective elastic stiffness tensors parameterized by background elastic moduli, the effective stress coefficient of isotropic host rocks, fluid modulus, porosity, and fracture parameters based on the anisotropic Gassmann’s fluid substitution equation. Combining the perturbations in saturated stiffness tensors and scattering theory, we formulate the reflection coefficient equation of PP-wave data as a function of background porosity-related stress parameter, and two (i.e., normal and shear) fracture weakness parameters. Following Bayes’ rule, we estimate the porosity-related stress parameter and fracture weaknesses using the inversion method of azimuthal Fourier coefficients. We finally compute the effective horizontal and vertical in-situ stresses using the estimated elastic moduli, porosity-related stress parameter and fracture weaknesses. Synthetic and real data sets demonstrate that our proposed inversion approach based on the derived reflection equation provides us another way to obtain reasonable estimates of in-situ stresses in a complex fractured porous shale reservoir.

Amplitude variation with offset and azimuth (AVOAz) analysis can be separated into two separate parts: amplitude variation with offset (AVO) analysis and amplitude versus azimuth (AVAz) analysis. Useful information about fractures and anisotropy can be obtained just by examining the AVAz. The AVAz can be described as a sum of sinusoids of different periodicities, each characterized by its magnitude and phase. This sum is mathematically equivalent to a Fourier series, and hence the coefficients describing the AVAz response are azimuthal Fourier coefficients (FCs). This FC parameterization is purely descriptive. The aim of this paper is to help the interpreter understand what these coefficients mean in terms of anisotropic and fracture parameters for the case of P-wave reflectivity using a linearized approximation. The FC representation is valid for general anisotropy. However, to gain insight into the significance of FCs, more restrictive assumptions about the anisotropy or facture system must be assumed. In the case of transverse anisotropic media with a horizontal axis of symmetry, the P-wave reflectivity linearized approximation may be rewritten in terms of azimuthal FCs with the magnitude and phase of the different FCs corresponding to traditional AVAz attributes. Linear slip theory is used to show that the FCs can be interpreted similarly for the cases of a single set of parallel vertical fractures in isotropic media and in transverse anisotropic media with a vertical axis of symmetry (VTI). The magnitude of the FCs depends on the fracture weakness parameters and the background media. For the case of vertical fractures in a VTI background, the AVOAz inverse problem is underdetermined, so extra information must be incorporated to determine how the weights are modified due to this background anisotropy. We evaluated this on a 3D data set from northwest Louisiana for which the main target was the Haynesville shale.

ABSTRACTTraditional amplitude variation with offset and azimuth (AVOAz) analysis for fracture characterization extracts fracture properties through analysis of reflection AVOAz to determine anisotropic parameters (e.g., Thomsen’s parameters) that are then related to fracture properties. The validity of this method relies on the basic assumption that a fractured unit can be viewed as an equivalent anisotropic medium. As a rule of thumb, this assumption is taken to be valid when the fracture spacing is less than λ/10. Under the effective medium assumption, diffractions from individual fractures destructively interfere and only specular reflections from boundaries of a fractured layer can be observed in seismic data. The effective medium theory has been widely used in fracture characterization, and its applicability has been validated through many field applications. However, through numerical simulations, we find that diffractions from fracture clusters can significantly distort the AVOAz signatures when a ...

Fractures that develop in coal seams threaten safety in many ways, but they can be predicted using fracture parameters derived from seismic data. However, the post-stack split shear waves are difficult to thoroughly separate by Alford rotation due to wavefield mixing. We propose a method of predicting fractures in a coal seam using multi-component seismic data, which was applied to coal seam 13-1 of the Huainan coalfield, China. We employed the Alford rotation to separate the split PS-waves (P-to-S converted waves) and perform interlayer travel-time inversion of the fast shear waves using geophysical logs, rock-physics parameters, and tunnel-excavation information as constraints. However, post-stack wavefield mixing of the coal seam interfered with the Alford rotation of the real post-stack seismic data. Therefore, we only performed the Alford rotation on radial and transverse component post-stack sections to derive fracture azimuths, which were then applied to the pre-stack separation of the split PS-waves. Using joint PP- and PS-wave inversion, anisotropy parameters were derived for use in fracture prediction. Finally, we predicted unsafe mining areas with a high probability of coal and gas outbursts. The application results were verified by excavation data from the mine tunnels. Our method contributes to fracture prediction on coal mine safety.

… for seismic inversion. Since fractured reservoirs are azimuthally anisotropic, their comprehensive characterization requires acquisition of wideazimuth, multicomponent seismic data. …

… requires knowledge of fractures and rock … Multicomponent 3D-3C seismic data is input for more reliable estimation of rock physical parameters. This info is useful to optimise fracture …

Several P-wave azimuthal anisotropy studies have been conducted for the SEAM II Barrett model data. However, these analyses provide fracture property estimation that is inconsistent with the actual model properties. Therefore, we perform a feasibility study to understand the influence of the overburden and reservoir properties, and the processing and inversion steps, which together determine the success of the fracture interpretation from seismic data. 1D model properties (orthorhombic for both overburden and reservoir) are first extracted from the actual Barrett model properties at two locations. Anisotropic prestack reflectivity modeling exposes the true orthorhombic response of the 1D medium in the form of Common Offset and Common Azimuth (COCA) gathers. The true anisotropic response is obscured in the Barrett data (generated by finite element modeling) due to the mild lateral velocity variations and orthorhombic anisotropy in the overburden. We then expose the reservoir anisotropic response by using an isotropic overburden in the reflectivity modeling. This shows that the P-wave VVAZ responses generated by the reservoir itself are weak, which leads to an unstable VVAZ inversion to estimate the interval NMO velocity anisotropy. The reservoir thickness (125m or 65ms TWT) or NMO velocity anisotropy (6-7%) needs to be at least doubled to obtain a stable VVAZ inversion. Anisotropic geometrical-spreading correction improves the amplitude-versus-azimuth (AVAZ) inversion results when reflectivity modeling models orthorhombic overburden. The converted wave ( C-wave) has a stronger VVAZ response compared to the P-wave. We suggest that the C-wave data could be useful to constrain fracture interpretation in the Barrett model. We conclude that the results of previous studies are due to the combination of the residual influence of overburden after processing and imaging, and the weak anisotropy responses from the reservoir.

… The amplitude levels of the events in multicomponent seismic data … from the fracture when we attempt to invert elastic properties for the … 3 and seismic inversion in Chap. 4 of this book. …

Characterization of naturally fractured reservoirs often requires estimating parameters of multiple fracture sets that develop in an anisotropic background. Here, we discuss modeling and inversion of the effective parameters of orthorhombic models formed by two orthogonal vertical fracture sets embedded in a VTI (transversely isotropic with a vertical symmetry axis) background matrix. Although the number of the microstructural (physical) medium parameters is equal to the number of effective stiffness elements (nine), we show that for this model there is an additional relation (constraint) between the stiffnesses or Tsvankin's anisotropic coefficients. As a result, the same effective orthorhombic medium can be produced by a wide range of equivalent models with vastly different fracture weaknesses and background VTI parameters, and the inversion of seismic data for the microstructural parameters is nonunique without additional information. Reflection moveout of PP- and PS-waves can still be used to find the fracture orientation and estimate (in combination with the vertical velocities) the differences between the normal and shear weaknesses of the fracture sets, as well as the background anellipticity parameter ηb. Since for penny-shaped cracks the shear weakness is close to twice the crack density, seismic data can help to identify the dominant fracture set, although the crack densities cannot be resolved individually. If the VTI symmetry of the background is caused by intrinsic anisotropy (as is usually the case for shales), it may be possible to determine at least one background anisotropic coefficient from borehole or core measurements. Then seismic data can be inverted for the fracture weaknesses and the rest of the background parameters. Therefore, seismic characterization of reservoirs with multiple fracture sets and anisotropic background is expected to give ambiguous results, unless the input data include measurements made on different scales (surface seismic, borehole, cores).

… fractured reservoir can be characterised by employing quantities obtained from the inversion of seismic … ) data to constrain the construction of a discrete fracture network. In section 2, the …

A seismic source excites a rich variety of elastic waves in the Earth, so it seems reasonable to try to use them all to create a more compelling picture of the subsurface. While P-wave imaging has been enormously successful in this regard, there are conditions when it is less so. But, the demands of energy discovery and recovery require an increasingly comprehensive portrayal of reservoir lithologies, stresses, fractures, and fluids. The multicomponent seismic method is a superset of conventional seismic technology and has the potential to answer to some of these demands. Recording horizontal motion, as well as vertical vibrations and pressures, allows further capturing of the full seismic wavefield, and the additional resultant pictures can provide greater comprehension of subsurface properties, fluids, and their changes. We might liken this to a more complete conversation with “loud” waves (P-waves arriving first with high amplitudes) and “shy” waves (S-waves with lower voices and a more complicated message).

Based on a model of attenuative cracked rock, we have derived a simplified and frequency-dependent stiffness matrix associated with (1) a rock volume containing aligned and partially saturated cracks and (2) a new indicator of oil-bearing fractured reservoirs, which is related to pressure relaxation in cracked rocks and influenced by fluid viscosity and saturation. Starting from the mathematical form of a perturbation in this stiffness matrix across a reflecting interface separating two attenuative cracked media, we set up a linearized P-wave to P-wave reflection coefficient as an azimuthally and frequency-dependent function of dry rock elastic properties, dry fracture weaknesses, and the new indicator. By varying this reflection coefficient with azimuthal angle, we derive a further expression referred to as the quasidifference in elastic impedance, or [Formula: see text], which is primarily affected by the dry fracture weaknesses and the new indicator. An inversion approach is established to use differences in frequency components of seismic amplitudes to estimate these weaknesses and the indicator based on the derived [Formula: see text]. In synthetic inversion tests, we determine that the approach produces interpretable parameter estimates in the presence of data with a moderate signal-to-noise ratio (S/N). Testing on a real data set suggests that reliable fracture weakness and indicator are generated by the approach; fractured and oil-bearing reservoirs are identified through a combination of the dry fracture weakness and the new indicator.

Summary Unconventional resource plays involve the development of some unusual reservoirs, such as shales or other very tight formations with very low natural permeability in the nano-darcy range. Reservoir development for these plays requires the identification of "sweet spots" for fracturing/production purposes, in what is usually a very inhomogeneous "reservoir". The nature of these sweet spots is somewhat elusive and we will choose to define the term as any portion of the reservoir that gives enhanced hydrocarbon production after optimization of the reservoir through some mechanical process such as hydraulic fracturing. The geophysical characterization of these sweet spots is highly dependent on the detailed rock properties of the shale, but most often takes the form of some highly optimized seismic attributes obtained after careful seismic processing and a seismic inversion. These seismic attributes may not be derived from p-wave data alone. In fact we will argue that the seismic attributes most often used in the identification of sweet spots in shale plays usually require a reasonably accurate determination of formation density which, in most circumstances, cannot be accurately estimated from p-wave data alone. We will then present the impact of converted waves and the additional information that they can bring to these developments when combined with other data. The workflows and technologies discussed in this paper are generally applicable to any unconventional resource play. However to focus the discussion we will only use examples from the Marcellus shale play in the US.

… One of the main goals of this research is to use the multicomponent seismic to … multicomponent seismic for structural fault interpretation and s-wave splitting analysis for natural fracture …

Fractured reservoirs have been encountered worldwide and in general they are profitably produced, however it is safe to say that none of them have been depleted efficiently. As the seismic industry focuses more on production and development it is becoming more important to recognize the presence of fractures for optimal reservoir management. In reservoirs producing primarily from secondary porosity like fractures, the flow is largely controlled by the fracture system and characterizing these fractures is key to effectively managing these reservoirs. Aligned fractures will affect the average stiffness of the rocks even when fractures are smaller than seismic wavelengths. Small scale aligned fractures lead to variations in the seismic velocities that are directionally dependent, an effect known as anisotropy. Measuring this seismic anisotropy provides information on the fracture systems properties, such as fracture density and orientation. Such information can be used to identify sweet spots and in general be used for better reservoir management, like guiding directional and infill drilling. Since fractures are often nearly vertical to bedding the dominant seismic effect is azimuthal anisotropy, which is observed both on P- and S-waves. AVOA (azimuthal AVO-effect) and variations in the NMO velocities have been used to estimate P-wave anisotropy. S-waves will split into one fast and one slow mode and this splitting is very sensitive to small changes in the subsurface. The fast shear-wave direction aligns with the fracture strike and the amount of time splitting between the fast and slow mode depends on fracture density. Apart from the difference in sensitivity between the P- and S-wave measurements there are attributes of the fracture system that can only be observed on the S-wave data. The asymmetry in the converted waves (PS-data) can say something about the tilt of the fractures. Multicomponent seismic provides access to both the P- and S-wave azimuthal information. Combining these two can enable the extraction of information about the fluid in the fractures. In this paper we will give an overview of the theory and several cases where multi-component data has been used to characterize fractures and fracture attributes.

… P-Wave Anisotropy: Seismic P-wave energy travels faster parallel to fractures and slower … rock properties from seismic inversion followed by well log-based facies inversion to enhance …