Seismic inversion for the parameters of two orthogonal fracture sets in a VTI background medium

Geophysics ◽  
2002 ◽  
Vol 67 (1) ◽  
pp. 292-299 ◽  
Author(s):  
Andrey Bakulin ◽  
Vladimir Grechka ◽  
Ilya Tsvankin
Keyword(s):  
Seismic Data ◽  
Fractured Reservoirs ◽  
Crack Density ◽  
Transversely Isotropic ◽  
Seismic Inversion ◽  
Naturally Fractured Reservoirs ◽  
Multiple Fracture ◽  
Effective Parameters ◽  
Wide Range

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).

Feasibility of seismic characterization of multiple fracture sets

Geophysics ◽  
2003 ◽  
Vol 68 (4) ◽  
pp. 1399-1407 ◽  
Author(s):  
Vladimir Grechka ◽  
Ilya Tsvankin
Keyword(s):  
Host Rock ◽  
Fractured Reservoirs ◽  
Transversely Isotropic ◽  
Naturally Fractured Reservoirs ◽  
Multiple Fracture ◽  
Stiffness Tensor ◽  
Fracture Detection ◽  
Estimation Of Parameters ◽  
Fracture Characterization ◽  
Underlying Assumption

Estimation of parameters of multiple fracture sets is often required for successful exploration and development of naturally fractured reservoirs. The goal of this paper is to determine the maximum number of fracture sets of a certain rheological type which, in principle, can be resolved from seismic data. The main underlying assumption is that an estimate of the complete effective stiffness tensor has been obtained, for example, from multiazimuth, multicomponent surface seismic and vertical seismic profiling (VSP) data. Although typically only a subset of the stiffness elements (or some of their combinations) may be available, this study helps to establish the limits of seismic fracture‐detection algorithms. The number of uniquely resolvable fracture systems depends on the anisotropy of the host rock and the rheology and orientation of the fractures. Somewhat surprisingly, it is possible to characterize fewer vertical fracture sets than dipping ones, even though in the latter case the fracture dip has to be found from the data. For the simplest, rotationally invariant fractures embedded in either isotropic or transversely isotropic with a vertical symmetry axis (VTI) host rock, the stiffness tensor can be inverted for up to two vertical or four dipping fracture sets. In contrast, only one fracture set of the most general (microcorrugated) type, regardless of its orientation, is constrained by the effective stiffnesses. These results can be used to guide the development of seismic fracture‐characterization algorithms that should address important practical issues of data acquisition, processing, and inversion for particular fracture models.

Anisotropic parameters and P‐wave velocity for orthorhombic media

Geophysics ◽  
1997 ◽  
Vol 62 (4) ◽  
pp. 1292-1309 ◽  
Author(s):  
Ilya Tsvankin
Keyword(s):  
Fractured Reservoirs ◽  
Transversely Isotropic ◽  
Azimuthal Velocity ◽  
Analytic Solutions ◽  
Seismic Inversion ◽  
P Wave ◽  
Weak Anisotropy ◽  
P Waves ◽  
Velocity Anisotropy ◽  
Wide Range

Although orthorhombic (or orthotropic) symmetry is believed to be common for fractured reservoirs, the difficulties in dealing with nine independent elastic constants have precluded this model from being used in seismology. A notation introduced in this work is designed to help make seismic inversion and processing for orthorhombic media more practical by simplifying the description of a wide range of seismic signatures. Taking advantage of the fact that the Christoffel equation has the same form in the symmetry planes of orthorhombic and transversely isotropic (TI) media, we can replace the stiffness coefficients by two vertical (P and S) velocities and seven dimensionless parameters that represent an extension of Thomsen's anisotropy coefficients to orthorhombic models. By design, this notation provides a uniform description of anisotropic media with both orthorhombic and TI symmetry. The dimensionless anisotropic parameters introduced here preserve all attractive features of Thomsen notation in treating wave propagation and performing 2-D processing in the symmetry planes of orthorhombic media. The new notation has proved useful in describing seismic signatures outside the symmetry planes as well, especially for P‐waves. Linearization of P‐wave phase velocity in the anisotropic coefficients leads to a concise weak‐anisotropy approximation that provides good accuracy even for models with pronounced polar and azimuthal velocity variations. This approximation can be used efficiently to build analytic solutions for various seismic signatures. One of the most important advantages of the new notation is the reduction in the number of parameters responsible for P‐wave velocities and traveltimes. All kinematic signatures of P‐waves in orthorhombic media depend on just the vertical velocity [Formula: see text] and five anisotropic parameters, with [Formula: see text] serving as a scaling coefficient in homogeneous media. This conclusion, which holds even for orthorhombic models with strong velocity anisotropy, provides an analytic basis for application of P‐wave traveltime inversion and data processing algorithms in orthorhombic media.

scholarly journals Integration of Seismic Anisotropy and Reservoir Performance Data for Characterization of Naturally Fractured Reservoirs Using Discrete Feature Network Models

2005 ◽  
Vol 8 (02) ◽  
pp. 132-142 ◽  
Author(s):  
Robert Will ◽  
Rosalind A. Archer ◽  
William S. Dershowitz
Keyword(s):  
Seismic Data ◽  
Elastic Anisotropy ◽  
Fractured Reservoirs ◽  
Seismic Attributes ◽  
Performance Data ◽  
Naturally Fractured Reservoirs ◽  
Fracture System ◽  
Reservoir Performance ◽  
Naturally Fractured ◽  
System Characteristics

Summary This paper proposes a method for quantitative integration of seismic(elastic) anisotropy attributes with reservoir-performance data as an aid in characterizing systems of natural fractures in hydrocarbon reservoirs. This method is demonstrated through application to history matching of reservoir performance using synthetic test cases. Discrete-feature-network (DFN) modeling is a powerful tool for developing fieldwide stochastic realizations of fracture networks in petroleum reservoirs. Such models are typically well conditioned in the vicinity of the wellbore through incorporation of core data, borehole imagery, and pressure-transient data. Model uncertainty generally increases with distance from the borehole. Three-dimensional seismic data provide uncalibrated information throughout the interwell space. Some elementary seismic attributes such as horizon curvature and impedance anomalies have been used to guide estimates of fracture trend and intensity (fracture area per unit volume) in DFN modeling through geostatistical calibration with borehole and other data. However, these attributes often provide only weak statistical correlation with fracture-system characteristics. The presence of a system of natural fractures in a reservoir induces elastic anisotropy that can be observed in seismic data. Elastic attributes such as azimuthally dependent normal move out velocity (ANMO), reflection amplitude vs. azimuth (AVAZ), and shear-wave birefringence can be inverted from 3D-seismicdata. Anisotropic elastic theory provides physical relationships among these attributes and fracture-system properties such as trend and intensity. Effective-elastic-media models allow forward modeling of elastic properties for fractured media. A technique has been developed in which both reservoir-performance data and seismic anisotropic attributes are used in an objective function for gradient-based optimization of selected fracture-system parameters. The proposed integration method involves parallel workflows for effective elastic and effective permeability media modeling from an initial DFN estimate of the fracture system. The objective function is minimized through systematic updates of selected fracture-population parameters. Synthetic data cases show that3D-seismic attributes contribute significantly to the reduction of ambiguity in estimates of fracture-system characteristics in the interwell rock mass. The method will benefit enhanced-oil-recovery (EOR) program planning and management, optimization of horizontal-well trajectory and completion design, and borehole-stability studies. Introduction Anisotropy and heterogeneity in reservoir permeability present challenges during the development of hydrocarbon reserves in naturally fractured reservoirs. Predicting primary reservoir performance, planning development drilling or EOR programs, completion design, and facilities design all require accurate estimates of reservoir properties and the predictions of future reservoir behavior computed from such estimates. Over the history of naturally-fractured-reservoir development, many methods have been used to characterize fracture systems and their effect on fluid flow in the reservoir. These include the use of geologic surface-outcrop analogs; core, single-well, and multiwell pressure-transient analysis; borehole-imaging logs; and surface and borehole seismic observations. To date, efforts to integrate seismic data into the workflow for characterization of naturally fractured reservoirs have been focused on the use of post-stack data. CDP stacking of seismic data takes advantage of redundancy in seismic data sets for the attenuation of noise. Unfortunately, CDP stacking also eliminates valuable information about spatial and orientational variations in the data. Such variations are often related to fracture-system characteristics. CDP-stacked seismic data are typically used to define the main structural elements of the reservoir. Fracture density has been correlated successfully with horizon curvature determined from seismic horizons. Seismic attributes frequently can be correlated with reservoir properties such as shale fraction, which often correlates with fracture-population statistics. Acoustic impedance computed from seismic data frequently exhibits dim spots in the presence of fractures.

Evaluation of Foam-Gels for Conformance Control in High Temperature High Salinity Carbonates

2021 ◽  
Author(s):  
Lyla Almaskeen ◽  
Abdulkareem AlSofi ◽  
Jinxun Wang ◽  
Ziyad Kaidar
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Concentration Ratio ◽  
High Salinity ◽  
Fractured Reservoirs ◽  
Gelation Time ◽  
Resistance Factor ◽  
Naturally Fractured Reservoirs ◽  
Conformance Control ◽  
Wide Range

Abstract In naturally fractured reservoirs, conformance control prior to enhanced oil recovery (EOR) application might be essential to ensure optimal contact and sufficient sweep. Recently, few studies investigated combining foams and gels into what is commonly coined as foamed-gels. Foamed-gels have been tested and shown to be potential for some field conditions. Yet, very limited studies were performed for high temperature and high salinity carbonates. Therefore, in this work, we study the potential of foamed-gels for high temperature and high salinity carbonates. The objective is to evaluate the potential of such synergy and to compare its value to the individual processes. For that purpose, in this work, we rely on bulk and core-scale tests. Bulk tests were used for initial screening. Wide range of foam-gel solutions were prepared with different polymer types and polymer concentrations. Test tubes were hand shacked thoroughly to generate foams. Foam heights were then measured from the test tubes. Heights were used to screen foaming agents and to study gelant effects on foamers in terms of foam strength (heights). The effect of foamers on gelation was evaluated through bottle tests. Based on the results, an optimal concentration ratio of gelant to foamer was determined and used in core-scale displacements, to further study the potential of this hybrid foam-gel process. Bulk results suggested that addition of the gelant up to a 4:1 foam to gel concentration ratio resulted in sufficient foam generation in some of the polymer samples. Yet, only two of the foam-gel samples generated a strong gel. Increasing the foamer concentration delayed the gelation time and in some samples, the solution did not gel. Through the coreflooding experiment, resistance factor (RF) and residual resistance factor (RRF) were obtained for different conformance control processes including foam, foam-gel, and gel. Foam-gel injection exhibited higher RF and RRF values than conventional foams. However, conventional gels showed even higher RF and RRF values than foam-gels. Combining two of the most widely used conformance control methods (foams and gels) can strike a balance. Foam-gel may offer a treatment that is deeper and more sustainable than foams and on the other a treatment that is more practical, and lower-cost than gels. Our laboratory results also demonstrate that such synergetic conformance control can be achieved in high salinity and high temperature carbonates with pronounced impact.

Prediction of elastic properties using seismic prestack inversion and neural network analysis

2015 ◽  
Vol 3 (2) ◽  
pp. T57-T68 ◽  
Author(s):  
Islam A. Mohamed ◽  
Hamed Z. El-Mowafy ◽  
Mohamed Fathy
Keyword(s):  
Neural Network ◽  
Network Analysis ◽  
Seismic Data ◽  
Seismic Inversion ◽  
Neural Network Analysis ◽  
Inversion Result ◽  
Amplitude Variation With Offset ◽  
Well Control ◽  
Prestack Inversion

The use of artificial intelligence algorithms to solve geophysical problems is a recent development. Neural network analysis is one of these algorithms. It uses the information from multiple wells and seismic data to train a neural network to predict properties away from the well control. Neural network analysis can significantly improve the seismic inversion result when the outputs of the inversion are used as external attributes in addition to regular seismic attributes for training the network. We found that integration of prestack inversion and neural network analysis can improve the characterization of a late Pliocene gas sandstone reservoir. For inversion, the input angle stacks was conditioned to match the theoretical amplitude-variation-with-offset response. The inversion was performed using a deterministic wavelet set. Neural network analysis was then used to enhance the [Formula: see text], [Formula: see text], and density volumes from the inversion. The improvement was confirmed by comparisons with logs from a blind well.

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