Abstract:
This patent delineates methods for quantifying and mitigating dip-induced azimuthal AVO effects in seismic fracture detection using Azimuthal AVO analysis by accurately accounting for the divergence correction and azimuthal dependence of the reflection angle. Solutions are provided for three cases: (1) dipping isotropic reservoirs; (2) anisotropic reservoirs with fractures aligned in arbitrary direction; and (3) anisotropic reservoirs where vertical fractures are aligned perpendicular to the dip direction.

Description:
RELATED APPLICATIONS  
       [0001]     This application claims priority to U.S. Provisional Patent Application No. 60/629,067, which was filed on Nov. 18, 2004. 
     
    
     FIELD OF THE INVENTION  
       [0002]     This invention relates generally to the field of geophysical prospecting, including geophysical reservoir delineation. Specifically, the invention is a method of seismic data processing for extracting formation-intrinsic rock, fluid and anisotropy/fracture properties through the analysis of the variation of seismic amplitude with offset and azimuth in the presence of formation dip.  
       BACKGROUND OF THE INVENTION  
       [0003]     In seismic exploration for hydrocarbons, AVO (Amplitude-Variation-with-Offset) refers to the variation of P-wave amplitude at increasing shot-to-receiver offset or reflection angle. When rock formations are flat and isotropic (isotropic means that elastic properties of the medium do not change regardless of the directions in which they are measured), reflection amplitude at a fixed offset does not change with the azimuth (direction angle of the shot-to-receiver line measured from the North). This situation is illustrated in  FIG. 1   a , which shows a seismic ray-path beginning at source (seismic shot point) S, traveling downward to be reflected from a formation surface at D, and then back up to be detected by receiver R. The reflected ray makes an angle θ with the normal to the reflecting surface or to the vertical since the reflector is assumed to be flat.  FIG. 1   b  depicts seismic data recorded by the receiver R for several different values of the source-receiver distance  11  (called the offset), but each reflection event being from the same reflection point D. The receiver measures seismic amplitude as a function of the two-way traveltime for the seismic wave to travel down to D from S and then back up to R ( FIG. 1   a ). The traveltime is related to the depth of the reflection point by the geometry of the ray-path and the seismic wave velocity. The reflector  12  in  FIG. 1   a  is shown in  FIG. 1   b  at different traveltimes (the S-D-R distance), depending on offset. This is because the data have not yet been corrected by a standard seismic data processing procedure called normal moveout.  
         [0004]      FIG. 2   a  illustrates the above-stated definition of azimuth, i.e., the angle ψ between the North direction and the line between the source S and receiver R.  FIG. 2   b  shows a flat response for reflection amplitude as a function of azimuth, which means the medium is azimuthally isotropic. Reflection amplitude, however, becomes azimuthally dependent when the formation beneath the reflection surface is azimuthally anisotropic due to, for example, containing aligned vertical fractures. Reflection amplitude vs. azimuth might then look something like  FIG. 2   c . In such a case, the amplitude variation is called AzAVO (azimuthal AVO). Geophysicists perform AVO analysis to derive rock and fluid properties of the reservoir formation beneath the reflection boundary. (See, for example, Smith, G. C. and Gidlow, P. M., “Weighted stacking for rock property estimation and detection of gas,”  Geophys. Prosp ., Eur. Assn. Geosci. Eng., 35, 993-1014 (1987); Rutherford, S. R. and Williams, R. H., “Amplitude-versus-offset variations in gas sands,”  Geophysics  54, 680-688 (1989); Castagna, J. P., Swan, H. W., and Foster, D. J., “Framework for AVO gradient and intercept interpretation,”  Geophysics  63, 948-956 (1998).) AzAVO data may be inverted to derive rock and fluid as well as fracture properties when fractures are suspected to exist in the reservoir formation, as is disclosed in, for example, Corrigan, D., “The effect of azimuthal anisotropy on the variation of reflectivity with offset: Workshop on Seismic Anisotropy,” Soc. Expl. Geophys., 41WSA, 1645 (1990), and Ruger, A, “Variation of P-wave reflectivity with offset and azimuth in anisotropic media,”  Geophysics  63, 935-947 (1998).  
         [0005]     AzAVO can also occur when a formation is isotropic but is bounded on top by a dipping boundary surface. This phenomenon may be illustrated by a numerical example. In this synthetic example, seismic lines were shot along many azimuthal directions, as shown in  FIG. 3   a  (angular scale in degrees), over the simple earth model of  FIG. 3   b . The figure depicts ray-paths from a shot position  31  being detected by many different receivers at  32 . Because seismic waves spread out, or diverge, as they travel, divergence corrections are necessary for restoring reflection amplitudes to represent the true reflection strength at the reflection boundary. The state-of-the-art processing, however, does not properly restore amplitudes from dipping reflector because it assumes that rock formations such as  33  in  FIG. 3   b  are flat. It also neglects the amplitude correction for compensating the azimuth-dependent reflection angles. The resultant amplitude, in addition to being offset (or, incident angle) dependent, also becomes azimuthally dependent ( FIG. 3   c ). This illustrates that reflection amplitude at a fixed offset is azimuth dependent when the reflector is dipping. This type of amplitude variation may be called “dip-induced” AzAVO to distinguish it from the AzAVO induced by anisotropy due to, for example, aligned vertical fractures. The dip-induced AzAVO contaminates seismic amplitude not only when formations are isotropic but also when formations are anisotropic.  
         [0006]     Quantification and mitigation of dip-induced AzAVO is not commonly done in AVO analysis. This is due not only to negligence but also to the fact that the azimuth information is lost through data processing procedures (e.g., dip-moveout correction and migration). One method, the sector time migration, has been introduced to counter the dip effect for AzAVO inversion. This method first divides the 3-D dataset into many subsets, each containing traces in an angular range about a selected azimuth angle. The subsets are further processed through seismic migration before performing AzAVO analysis. (Seismic migration is a data processing technique that positions reflections at their true locations. The seismic migration is utilized because of variable seismic velocities and dipping horizons.) This method, however, can not fully solve the problem because reflection points are moved different amounts due to the change in apparent dip from sector to sector. Results from time sector migration method may be ambiguous.  
         [0007]     Another method in use is the AzAVO inversion of 3-D seismic data without doing seismic migration. This method assumes rock formations are flat, and therefore the divergence correction applied does not compensate the dip-induced AzAVO. The method is preferable to the sector inversion method because it uses amplitude-offset-azimuth information of all traces simultaneously in the inversion to gain statistical power for fracture-attribute estimation. The inversion result, however, may also be ambiguous because the dip-induced AzAVO is not eliminated from the data.  
         [0008]     Because oil and gas reservoirs are often not flat, a method to quantify and mitigate the dip-induced AzAVO during seismic-amplitude analysis with or without anisotropy may be beneficial. To increase the reliability of results for both AVO and AzAVO analysis, analytical relationships linking amplitude, dip angle and azimuth angles are beneficial to gain insights, quantify the degree of impact, and design procedures to mitigate the effect. The present invention addresses these needs.  
       SUMMARY OF THE INVENTION  
       [0009]     In one embodiment, a method for compensating for dip-induced errors in Amplitude-Variation-with-Offset (AVO) attributes or in Azimuthal AVO (AzAVO) attributes derived from a 3-D seismic data volume obtained from a seismic survey of a dipping reservoir lying beneath isotropic overburden is described. The method comprises (a) accounting for azimuth dependence of energy divergence in seismic wave reflected from the dipping reservoir; and (b) accounting for azimuth dependence of reflection angle reflected from the dipping reservoir in the 3-D seismic data volume.  
         [0010]     In a second embodiment, a method for compensating for dip-induced errors in AVO attributes derived from a 3-D seismic data volume obtained from a seismic survey of a dipping isotropic reservoir lying beneath isotropic overburden is described. The method comprises the steps of: (a) applying Azimuthal AVO (AzAVO) inversion to the seismic data to generate four attribute data volumes A, B, B′ and ψ a  corresponding to amplitude-offset-azimuth relationship of a hypothetical flat layer with aligned vertical fractures, where A and B are AzAVO equivalents of AVO intercept and slope attributes, respectively, B′ is an AzAVO attribute related to anisotropy intensity and ψ a  is the azimuth of the aligned fractures; (b) calculating dip angles φ at the reservoir&#39;s upper surface and multiplying cos φ by A to obtain dip-compensated AVO intercept attribute A 0  for the actual dipping reservoir; (c) calculating dip-compensated AVO slope attribute B 0  for the actual dipping reservoir from B 0 =(B+B′)cos φ; and (d) calculating the actual dipping reservoir&#39;s dip azimuth ψ 0  from ψ 0 =ψ a .  
         [0011]     In a third embodiment, a method for compensating for dip-induced errors in Azimuthal Amplitude-Variation-with-Offset (“AzAVO”) attributes derived from a 3-D seismic data volume obtained from a seismic survey of a dipping anisotropic reservoir lying beneath isotropic overburden is described. This method comprises the steps of: (a) calculating a dip angle φ and a dip azimuth angle ω 0  sample-by-sample from the 3-D seismic data volume; (b) calculating a scale factor for each sample in normal-moveout corrected common mid-point (CMP) gathers of the 3-D seismic data volume, the scale factor being determined to cause amplitudes of the 3-D seismic data volume to satisfy an AzAVO equation for a hypothetical flat anisotropic layer containing aligned fractures; (c) applying the scale factor to the 3-D seismic data sample-by-sample; and (d) inverting the AzAVO equation on CMP gathers of the scaled 3-D seismic data volume to generate four dip-compensated attribute data volumes A, B, B′ and ψ f  for the actual dipping anisotropic reservoir, where A and B are AzAVO equivalents of Amplitude-Variation-with-Offset (AVO) intercept and slope attributes, respectively, B′ is an AzAVO attribute related to anisotropy intensity and ψ f  is the azimuth of the aligned fractures.  
         [0012]     In a fourth embodiment, a method for compensating for dip induced errors in Azimuthal Amplitude-Variation-with-Offset (AzAVO) attributes derived from a 3-D seismic data volume obtained from a seismic survey of a dipping anisotropic reservoir lying beneath isotropic overburden, anisotropy being substantially due to fractures oriented substantially perpendicular to a dip azimuth of the dipping anisotropic reservoir is described. The method comprises the steps of (a) applying AzAVO inversion to the 3-D seismic data volume to generate four attribute data volumes A, B, B′, and ψ 0 ′ corresponding to a hypothetical flat layer with aligned vertical fractures, where A and B are AzAVO equivalents of AVO intercept and slope attributes, respectively, B′ is an AzAVO attribute related to anisotropy intensity and ψ 0 ′ is the estimated azimuth of the aligned vertical fractures; (b) calculating dip angles φ at the dipping anisotropic reservoir&#39;s upper surface and obtaining dip-compensated AzAVO intercept attribute A 0  for the actual dipping anisotropic reservoir by multiplying A by cos φ; (c) adding the B and B′ attributes at each spatial location on the actual dipping anisotropic reservoir&#39;s upper surface, and multiplying the sum by cos φ; (d) estimating dip-compensated AzAVO slope attribute B 0  for the actual dipping anisotropic reservoir; (e) subtracting B 0  from (B+B′) cos φ at each location to estimate dip-compensated anisotropic slope attribute B 1  for the actual dipping anisotropic reservoir; and (f) iterating steps (a) to (e) with the estimated attributes as constraints to the AzAVO inversion until a pre-determined convergence criterion is achieved.  
         [0013]     In a fifth embodiment, a method for estimating a magnitude of dip-induced error in calculated values of Amplitude-Variation-with-Offset (AVO) intercept and slope attributes derived from seismic data from a 3-D survey of a dipping isotropic reflector lying beneath isotropic overburden is described. The method comprises the steps of (a) calculating a Magnitude quantity representative of the maximum amount of amplitude variation in the dip-induced AzAVO from  
       Magnitude   =       (       B   0     -       1   2     ⁢     A   0         )     ⁢     tan   2     ⁢   φ   ⁢           ⁢     sin   2     ⁢     θ   i           
 
 where A 0  and B 0  are representative values of the AVO intercept and slope attributes, respectively, φ is the dip angle of the dipping isotropic reflector, and θ i  is a reflection angle that is characteristic of reflection events in the seismic data from the dipping isotropic reflector&#39;s surface assuming the dipping isotropic reflector to be flat; (b) calculating a Baseline Amplitude quantity representative of a flat isotropic reflector&#39;s surface from 
 
Baseline Amplitude= A   0   +B   0  sin 2 θ i ; and 
 
 (c) calculating a fractional dip-induced error estimate by dividing the Magnitude quantity by the Baseline Amplitude quantity. 
 
         [0014]     In a sixth embodiment, a method for compensating for dip-induced errors is described. The method comprises obtaining seismic data from a survey of a dipping formation; and compensating for energy divergence and a reflection angle in the seismic data for a dipping formation. It should be noted that this method may be a computer implemented method that is executed on a computer and displays or generates a report based on the described method. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0015]     The present invention and its advantages may be better understood by referring to the following detailed description and the attached drawings in which:  
         [0016]      FIG. 1   a  illustrates the relationship between seismic raypath, shot, receiver, offset, and reflection angle in a horizontal stratified earth;  
         [0017]      FIG. 1   b  illustrates seismic reflections from a layer boundary depicted as waves, reflection amplitude being measured at the peak of the waveform at each offset;  
         [0018]      FIG. 2   a  illustrates the definition of azimuth of a shot-receiver line;  
         [0019]      FIG. 2   b  illustrates that reflection amplitude at a fixed offset does not change with the azimuth for an interface between flat isotropic media;  
         [0020]      FIG. 2   c  illustrates that reflection amplitude become azimuth-dependent when the formation beneath the reflection surface is azimuthally anisotropic;  
         [0021]      FIG. 3   a  illustrates the geometry of azimuth shooting;  
         [0022]      FIG. 3   b  illustrates the numerical earth model and an example of raypaths along a shot line;  
         [0023]      FIG. 3   c  illustrates that reflection amplitude at a fixed offset is azimuthal dependent for the earth model of  FIG. 3   b;    
         [0024]      FIG. 4   a  illustrates an isotropic formation overlying a dipping, isotropic formation;  
         [0025]      FIG. 4   b  illustrates an isotropic formation overlying a dipping anisotropic formation with fractures perpendicular to the dipping surface;  
         [0026]      FIG. 5  illustrates the linear relationship between reflection coefficient and the square of the sine of the reflection angle;  
         [0027]      FIG. 6  illustrates the two-dimensional (2-D) relationship between seismic raypath, shot, receiver, offset, and reflection angle for a dipping reflection surface;  
         [0028]      FIG. 7  is a three-dimensional (3-D) perspective diagram to aid in transforming ray-path geometry from a flat reflector to a dipping reflector;  
         [0029]      FIG. 8  is a flow chart indicating the primary steps of one embodiment of the present inventive method (Case 1) for compensating for a dipping isotropic reservoir;  
         [0030]      FIG. 9  is a flow chart indicating the primary steps of one embodiment of the present inventive method (Case 2) for compensating for a dipping anisotropic reservoir with oriented vertical fractures;  
         [0031]      FIG. 10  is a flow chart indicating the primary steps of one embodiment of the present inventive method (Case 3) for compensating for a dipping anisotropic reservoir with vertical fractures aligned perpendicular to the dip direction;  
         [0032]      FIGS. 11   a - c  shows three parameter sections along a seismic line derived from AzAVO inversion; and  
         [0033]      FIG. 12  illustrates the procedure of adding two attributes to derive formation intrinsic values for the AVO slope attribute B 0  along a seismic line in a 3-D seismic data cube. 
     
    
       [0034]     The invention may be described in connection with its preferred embodiments. However, to the extent that the following detailed description is specific to a particular embodiment or a particular use of the invention, this is intended to be illustrative only, and is not to be construed as limiting the scope of the invention. On the contrary, it is intended to cover all alternatives, modifications and equivalents that may be included within the spirit and scope of the invention, as defined by the appended claims.  
       DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS  
       [0035]     The present invention is a method for quantifying and mitigating dip effects in both AVO analysis and AzAVO inversion. The inventive method uses the previously described CMP-based AzAVO-inversion method as the starting point. Equations are derived to describe AzAVO properties in the presence of formation dip for three cases: (1) an isotropic layer  18  (i.e., overburden) over a dipping, isotropic reservoir layer  19  as illustrated in  FIG. 4   a , (2) an isotropic layer  14  over a dipping and anisotropic reservoir  15  with oriented vertical fractures  16  as illustrated in  FIG. 4   b , and (3) a special sub-case of Case (2) when the fracture azimuth is perpendicular to the dip azimuth of the fractured formation (also illustrated by  FIG. 4   b ). As used herein, “vertical fractures” means the fractures are perpendicular to the dipping reflection surface above them. The fracture azimuth is defined as the angle between (a) the line formed by the intersection of the fracture plane with a horizontal plane, and (b) a reference direction that is typically geographic North. Dip azimuth is the angle between the dip direction of the formation and the North. Insights from these equations are used to quantify the impact of the dip effect and to develop simple and data-driven methods to remove the dip effect from AzAVO inversion.  
         [0000]     Case 1: No Fractures—Isotropic Overburden Over a Dipping Isotropic Reservoir ( FIG. 4   a )  
         [0000]     1. Derivation of Formula  
         [0036]     When rock formations are isotropic, Shuey (“A simplification of the Zoeppritz-equations,”  Geophysics  50(4), 609-614 (1985)) found that there is a linear relationship between reflection coefficient (R) and reflection angle (θ) for reflection angle less than 30 degrees: 
 
 R=A   0   +B   0  sin 2 θ.  (1) 
 
         [0037]     As is illustrated in  FIG. 5 , A 0  and B 0  are the intercept and slope, respectively, of the least-square-fit line  51  drawn through the R vs. sin 2 θ cross-plot derived from seismic data. They are the AVO parameters (called “attributes”) used to derive the intrinsic lithology and fluid properties of the underlying reservoir formation (see, for example, the 1998 article by Castagna, et al.). The relationship between reflection coefficient R and amplitude Amp is approximately 
 
Amp=div· R =div·[ A   0   +B   0  sin 2 θ]  (2) 
 
 where div is the divergence term that describes how much of wave energy is retained after dispersal through wave-front expansion during wave propagation. The magnitude of the divergence is close to, and may be approximated by, the reciprocal of the travel distance along the raypath from shot point S to receiver R via reflection point D in  FIG. 1   a . When the reflection surface is horizontal (i.e., not dipping), the quantity div varies with the offset between the shot and the receiver ( FIG. 1   a ). The reflection amplitude is corrected for divergence prior to AVO analysis. 
 
         [0038]     In common practice, divergence correction in AVO analysis is calculated assuming rock formations are flat as illustrated in  FIG. 1   a . In reality, however, most of reservoir formations are dipping and energy divergence becomes azimuth dependent due to the fact that the length of the raypath S-D-R in the dipping reflector case ( FIG. 6 ) depends on the azimuth. By treating a dipping formation as a flat formation, error is introduced in two quantities in Eqn. (2). First, energy divergence is not fully compensated as can be seen by comparing the length of raypath S-D-R in  FIG. 6  to that of raypath S-D-R in  FIG. 1   a . Second, the reflection angle θ in Eqn. (2) is calculated using the geometry of  FIG. 1   a  when it should be based on  FIG. 6 . To make AVO analysis work for a dipping formation (after divergence correction assuming flat layers), equation (1) should be re-written to compensate for the change in divergence and reflection angle. (The embodiments of the present inventive method for all three cases described herein compensate seismic amplitudes for both sources of error.)  
         [0039]     Based on ray-path geometry shown in  FIG. 7 , the angular quantities θ and θ i  can be approximately related by the following expression:  
                 sin   2     ⁢   θ     =         1     cos   ⁢           ⁢   φ       ⁡     [     1   -       sin   2     ⁢   φ   ⁢           ⁢       cos   2     ⁡     (     ψ   -     ψ   0       )           ]       ⁢     sin   2     ⁢     θ   i               (   3   )             
 
 where φ is the dip angle of the reflection formation  72  (i.e., the angle by which the formation surface deviates from horizontal), ψ is the azimuth angle of the shot-receiver (S-R) line, ψ 0  is dip azimuth of the dipping formation (i.e., the direction  73  of maximum dip), θ is the true reflection angle, and θ i  is the mid-point angle, i.e., the reflection angle that may be obtained by incorrectly assuming that the dipping, subsurface reflector plane  72  is parallel to the horizontal, surface plane  71 . In  FIG. 7 , O is the midpoint between source S and receiver R, D is the reflection point on reflector  72 , and M, located vertically below O, is where the reflection point may be if reflector  72  were flat. 
 
         [0040]     To compensate the change in divergence correction due to the difference between flat and dipping formation, we derived a “divergence compensating” term divcomp based on the difference in length between ray-paths S-D-R and S-M-R ( FIG. 7 ) to account for formation dip:  
               divcomp   =     cos   ⁢           ⁢     φ   ⁡     [     1   -       1   2     ⁢     tan   2     ⁢   φ   ⁢           ⁢       sin   2     ⁡     (     ψ   -     ψ   0       )       ⁢     sin   2     ⁢     θ   i         ]           ,           (   4   )             
 
 and the resultant amplitude, being fully corrected in divergence for dipping formations, is expressed by the following equation: 
 
AMP=divcomp·[ A   0   +B   0  sin 2 θ].  (5) 
 
 AMP is equivalent to reflection coefficient R assuming other energy-dissipation factors (e.g., wave attenuation) are not influential on AVO analysis. Numerical tests on these equations indicate that Equations (3) and (4) are valid for dip angle up to approximately 20 degrees and reflection angle up to 30 degrees. 
 
         [0041]     Substituting Equations (3) and (4) into equation (5), one gets  
             AMP   ≈       1     cos   ⁢           ⁢   φ       ⁢     {       A   0     +       [       B   0     +       (       B   0     -       1   2     ⁢     A   0         )     ⁢     tan   2     ⁢   φ       ]     ⁢     sin   2     ⁢     θ   i       -       (       B   0     -       1   2     ⁢     A   0         )     ⁢     tan   2     ⁢   φ   ⁢           ⁢       cos   2     ⁡     (     ψ   -     ψ   0       )       ⁢     sin   2     ⁢     θ   i         }               (   6   )             
 
 Equation (6) describes the relationship between amplitude, dip angle of the reflecting formation, and the mid-point reflection angle θ i  of the reflection event. It indicates that when an isotropic formation is not flat, reflection amplitude at the dipping boundary becomes azimuthal dependent. This equation may be called the “dip-induced AzAVO equation”. 
 
 2. Quantification of Dip-Induced AzAVO 
 
         [0042]     The dip-induced AzAVO equation provides a way to quantify the effect of reflector dip on reflection amplitude. Multiplying both sides of Equation (6) by cos φ, the equation becomes  
                     cos   ⁢           ⁢     φ   ·   AMP       ≈       ⁢       A   0     +       [       B   0     +       (       B   0     -       1   2     ⁢     A   0         )     ⁢     tan   2     ⁢   φ       ]     ⁢     sin   2     ⁢     θ   i       -                     ⁢       (       B   0     -       1   2     ⁢     A   0         )     ⁢     tan   2     ⁢   φ   ⁢           ⁢       cos   2     ⁡     (     ψ   -     ψ   0       )       ⁢     sin   2     ⁢     θ   i                   =       ⁢       A   0     +       B   0     ⁢     sin   2     ⁢     θ   i       +         sin   2     ⁡     (     ψ   -     ψ   0       )       ·                       ⁢       (       B   0     -       1   2     ⁢     A   0         )     ⁢     tan   2     ⁢   φ   ⁢           ⁢     sin   2     ⁢       θ   i     .                     (   6.1   )             
 
 The left side of the equation can be thought of as a “scaled” amplitude of a seismic reflection event in a CMP gather. The right side of the equation can be separated into two parts. The first part, consisting of the first and second terms, represents reflection coefficient at the formation boundary without dip (see Eq. (1)). The second part, consisting of the third term, quantifies the azimuthal variation in amplitude due to dip. The following defined terms facilitate further discussion: 
 
Baseline Amplitude= A   0   +B   0  sin 2 θ i , 
 
Amplitude Variation=sin 2 (ψ−ψ 0 )·( B   0 −½ A   0 )tan 2 φ sin 2 θ i .  (6.2) 
 
 As sin 2 (ψ-ψ 0 ) varies between θ and  1 , the range of Amplitude Variation varies between θ and (B 0 −½ A 0 )tan 2 φ sin 2 θ i . The magnitude of this variation is simply  
             Magnitude   =       (       B   0     -       1   2     ⁢     A   0         )     ⁢     tan   2     ⁢   φ   ⁢           ⁢     sin   2     ⁢       θ   i     .               (   6.3   )             
 
 This is the maximum amount of amplitude change in dip-induced AzAVO. Its value is determined not only by midpoint and azimuth angles, but also by the contrast in intrinsic rock properties across the reflection boundary (i.e., A 0  and B 0 ). 
 
         [0043]     Practically speaking, the Amplitude Variation part can be thought as an “anomaly” on reflection amplitude due to formation dip. It is observable when its amplitude level is above the level of random noise of the seismic data. To compare the strength between this anomaly (i.e., dip-induced AzAVO) and seismic noise, we define the following quantity:  
               %   ⁢           ⁢   variation     =     100   ×       Magnitude   BaselineAmplitude     .               (   6.4   )             
 
 This quantity can be calculated for a specific reservoir setting and compare to noise level on seismic data to evaluate if dip-induced AzAVO is detectable (i.e., greater than noise-to-signal ratio) on seismic data. If dip-induced AzAVO is detectable, mitigation of dip effect becomes necessary. This approach is illustrated in the example below. 
 
         [0044]     Table 1 shows an example of applying Equation (6.4) to four different reservoir settings common in oil and gas exploration. Assuming noise-to-signal ratio is less than 5 percent on seismic data (this ratio can be measured from seismic data), the example shows that dip-induced AzAVO is significant in cases 1 and 2 (i.e., % variation greater than noise level) but not in cases 3 and 4. Therefore, mitigation of the dip-induced AzAVO is useful for the case 1 and case 2 reservoirs.  
                                                                                   TABLE 1                           Maximum percent variation of dip-induced AzAVO in four shale/reservoir settings.            Case   Reservoir Type   Porosity   Dip Angle   Midpoint Angle   Ao   Bo   % variation                    1   sandstone   20%   15 degrees   26 degrees   0.15   −0.4   9.63       2   sandstone   25%   15 degrees   26 degrees   0.03   −0.28   16.39       3   sandstone   34%   15 degrees   26 degrees   −0.1   −0.16   1.19       4   limestone   20%   15 degrees   26 degrees   −0.111   −0.142   3.41                  
 
 3. Method for Removing Dip Effect in AVO Analysis 
 
         [0045]     It may be noted that the dip-induced AzAVO equation (Eq. 6) has the same form as the AzAVO equation derived by Ruger (1998): 
 
 R≈A+B  sin 2   θ+B ′ cos 2 (ψ−ψ a )sin 2 θ,  (7) 
 
 if one replaces ψ a  in Eq. 7 by dip azimuth angle ψ 0 . The quantity ψ a  in Ruger&#39;s equation is the azimuth of the “cause” of the anisotropy, e.g., the fracture azimuth. ψ is the azimuth angle of the shot-receiver line. Parameters A and B are equivalent to intercept and slope in the AVO equation, i.e., A 0  and B 0  in Eq. (1), and B′ is related to the intensity of the anisotropy. Equation (7) is the basic equation used in AzAVO inversion to derive these anisotropy parameters from seismic data. 
 
         [0046]     Equating coefficients of like terms in equations (6) and (7) yields the following relationships:  
         A   =       1     cos   ⁢           ⁢   φ       ·     A   0         ,     
     ⁢     B   =       1     cos   ⁢           ⁢   φ       ⁡     [       B   0     +       (       B   0     -       1   2     ⁢     A   0         )     ⁢     tan   2     ⁢   φ       ]         ,     
     ⁢       B   ′     =         -   1       cos   ⁢           ⁢   φ       ⁢     (       B   0     -       1   2     ⁢     A   0         )     ⁢     tan   2     ⁢   φ       ,     
     ⁢       ψ   0     =       ψ   a     .           
 
 Further manipulation of these equations leads to the following relationships between parameters intrinsic to the dipping isotropic formation and the parameters derived from a traditional AzAVO inversion of the 3-D seismic data: 
 
 A   0   =A ·cos φ,  (8.1) 
 
 B   0 =( B+B ′)·cos φ, and  (8.2) 
 
ψ 0 =ψ a ·  (8.3) 
 
         [0047]     Equations (8.1)-(8.3) indicate that in the case of isotropic dipping formations, the formation intrinsic parameters can be derived through AzAVO inversion of the seismic data. Based on this realization, a simple, data-driven procedure to mitigate the dip effect for AVO analysis is readily derived. This procedure, summarized in the flow chart of  FIG. 8 , may be stated as follows: 
        1). Apply AzAVO inversion to the 3-D seismic data to generate four attribute (i.e., parameter) data cubes A, B, B′ and ψ a . (Step  81 ) Attribute ψ a  is now the dip azimuth of the dipping isotropic formation, as indicated by Eq. (8.3).     2) Derive the dip angle at the target reflector from the seismic data after conventional processing (e.g., CMP stacked or migration-stack data). (Step  82 )     3) As suggested by Eq. (8.1), multiply the cosine of the dip angle (i.e., cos φ) by the A-attribute derived at each CMP location along the target reflection horizon to obtain the formation intrinsic (i.e., dip-compensated) parameter A 0 . (Step  83 )     4) As suggested by Eq. (8.2), add the B and B′ attributes at each CMP location along the target reflection horizon and multiply the sum by the cosine of dip angle at that location to get the formation intrinsic parameter B 0 . (Step  84 ) The resultant parameters A 0  and B 0  can be used to determine rock property and fluid type in the dipping reservoir by known procedures, e.g., the above-referenced 1998 paper by Castagna, et al.        
 
         [0052]     The presence of fractures in a reservoir is usually indicated by samples from the well (e.g., core, formation images, etc.), the well&#39;s performance data, or seismic interpretation. When fractures are not evident, the preceding simple method can be applied to extract “formation intrinsic” parameters A 0  and B 0  for lithology and fluid interpretation, for flat or dipping reservoirs. This method is preferably applied to formation with dip angle less than 20 degrees. Dip angle can be calculated from 3-D seismic images (e.g., migrated seismic data) and used in the process. When fractures are evident, the following method can be applied.  
         [0000]     Case 2: With Fractures—Isotropic Overburden Over Dipping Anisotropic Reservoir ( FIG. 4   b )  
         [0000]     1. Derivation of Formula  
         [0053]     In this case, reflection coefficient is described by the AzAVO equation but modified by the divergence-compensation term: 
 
AMP=divcomp·[ A+B  sin 2   θ+B ′ cos 2 (ψ−ψ f )sin 2 θ].  (9) 
 
         [0054]     Note that angle θ refers to true reflection angle at the dipping surface ( FIG. 2   a ). To decouple the effect of dip from the effect of fractures, Eq. (3) can be rewritten  
                   sin   2     ⁢   θ     =       C   ·     sin   2       ⁢     θ   i         ⁢     
     ⁢   where   ⁢     
     ⁢     C   =         1     cos   ⁢           ⁢   φ       ⁡     [     1   -       sin   2     ⁢   φ   ⁢           ⁢       cos   2     ⁡     (     ψ   -     ψ   0       )           ]       .               (   10   )             
 
 Substituting Eq. (10) into Eq. (9) yields  
             AMP   =     C   ·   divcomp   ·       [       A   C     +     B   ⁢           ⁢     sin   2     ⁢     θ   i       +       B   ′     ⁢       cos   2     ⁡     (     ψ   -     ψ   f       )       ⁢     sin   2     ⁢     θ   i         ]     .               (   11   )             
 
         [0055]     It can be seen that Eq. (9) is now expressed in terms of the mid-point angle θ i  and the quantity within the brackets has the form of the AzAVO-inversion equation, i.e., Eq. (7). Also, in this equation both C and divcomp can be calculated for every reflection event. These two quantities can be combined and defined as the “scale factor”:  
             scftr   =       1     C   ·   divcomp       .             (   12   )             
 
 Substituting Eq. (12) into Eq. (11) and moving the scale factor to left-hand side of the equation yields  
               AMP   ·   scftr     =       A   C     +     B   ⁢           ⁢     sin   2     ⁢     θ   i       +       B   ′     ⁢       cos   2     ⁡     (     ψ   -     ψ   f       )       ⁢     sin   2     ⁢     θ   i                 (   13   )             
 
         [0056]     This equation indicates that, by “scaling” seismic amplitude with the scale factor scftr, the amplitude equation is in the same form as the AzAVO equation even when the anisotropic formation has a dip. Following this insight, a simple method can be designed to remove the dip-effect from seismic data for fracture detection.  
         [0000]     2. Method for Removing Dip Effect in AzAVO Analysis  
         [0057]     Equation (13) provides a simple way to mitigate the dip-effect for the case of dipping anisotropic formations. The procedure, summarized in the flow chart of  FIG. 9 , is as follows: 
        1) Calculate dip azimuth ψ 0  and dip angle φ sample-by-sample (i.e., at every space-time location that has reflection amplitude or energy) from the stacked 3-D seismic data. (Step  91 )     2) Calculate the scale factor scftr in normal-moveout corrected CMP gathers of the seismic data according to equations (4), (10), and (12) and apply the scale factor to scale the amplitude at every reflection sample. (Step  92 ) A CMP gather is a set of seismic traces that have a common midpoint (point O in  FIG. 7 ).     3) Invert Eq. (13) on the scaled CMP gathers to derive parameters A, B, B′, and ψ f , preferably using least-square inversion. (Step  93 ) 
 
 Persons skilled in the art will understand how to perform least-square inversion. 
       
 
         [0061]     Parameters A and B can be used to determine rock and fluid properties in the reservoir, while B′ and ψ f  indicate intensity and orientation of the fractures in the reservoir.  
         [0062]     This method involves more calculations during data processing than the method in Case 1. It is applicable when the presence of fractures is suspected or expected. With dip angle derived from 3-D seismic images, scale factors can be derived and applied to the CMP gathers. AzAVO-inversion of the scaled amplitude derive the rock-property attribute A and B, and the fracture-property attributes B′ and ψ f .  
         [0000]     Case 3: With Fractures—when the Fracture Azimuth is Perpendicular to the Dip Azimuth of the Fractured Formation ( FIG. 4   b )  
         [0000]     1 Derivation of Formula  
         [0063]     It is observed that in fractured formations the azimuth of the aligned (vertical) fractures is usually perpendicular to the direction of formation dip. This is a special case of Case 2. In this situation, ψ f =ψ 0 ±90°. Substituting Eqs. (3) and (4) into Eq. (9) and replacing ψ f  by ψ 0 +90°, one gets  
                   AMP   =       ⁢       1     cos   ⁢           ⁢   φ       ⁢     {       A   0     +       [       B   0     +       (       B   0     -       1   2     ⁢     A   0         )     ⁢     tan   2     ⁢   φ       ]     ⁢     sin   2     ⁢     θ   i       +                         ⁢         [       B   1     -       (       B   0     -       1   2     ⁢     A   0         )     ⁢     tan   2     ⁢   φ       ]     ⁢       cos   2     ⁡     (     ψ   -     ψ   0       )       ⁢     sin   2     ⁢     θ   i       +                       ⁢         1   4     ⁢     B   1     ⁢     tan   2     ⁢   φ   ⁢           ⁢     sin   2     ⁢   2   ⁢     (     ψ   -     ψ   0       )     ⁢     sin   2     ⁢     θ   i       +   …     }     .                 (   14   )             
 
 Here A 0 , B 0  and B 1  denote the AVO intercept, slope, and the AzAVO anisotropy parameter, respectively. As with Eq. (6) in Case 1, Eq. (14) has the same form as the AzAVO equation (an alternate form of Eq. (7)): 
 
AMP= A+B  sin 2   θ+B ′ cos 2 (ψ−ψ a )sin 2   θ+N   (15) 
 
 with the further exception that fracture azimuth ψ a  is now replaced by dip azimuth ψ 0 . N is the difference between the measured reflectivity (i.e., amplitude after divergence correction) and the reflectivity calculated from Equation 7. Just as in Case 1, a simple method can be found to derive rock-property attributes and fracture attributes for this special case. 
 
 2. Method for Removing Dip Effect in AzAVO Analysis 
 
         [0064]     By equating coefficients of like terms in equations (14) and (15), one obtains the following relationships:  
               A   =       1     cos   ⁢           ⁢   φ       ⁢     A   0         ,     
     ⁢     B   =       1     cos   ⁢           ⁢   φ       ⁡     [       B   0     +       (       B   0     -       1   2     ⁢     A   0         )     ⁢     tan   2     ⁢   φ       ]         ,     
     ⁢       B   ′     =       1     cos   ⁢           ⁢   φ       ⁡     [       B   1     -       (       B   0     -       1   2     ⁢     A   0         )     ⁢     tan   2     ⁢   φ       ]         ,     
     ⁢       ψ   0   ′     =       ψ   0     +     ɛ   .                 (   16   )             
 
         [0065]     The estimated azimuth angle, ψ′ 0 , now suffers a small error, ε, from the true fracture or dip azimuth angle. This is due to the neglected higher order terms represented by N. Just as in Case 1, these relationships suggest a simple method for deriving rock and fracture properties without the contamination of dip-induced anisotropy. The procedure, summarized in the flow chart of  FIG. 10 , is as follows for one embodiment of the present inventive method: 
        1) Apply least-square inversion to the 3-D seismic data to generate four attribute data volumes A, B, B′ and ψ′ 0 . Attribute ψ′ 0  is the estimated dip azimuth of the fractured, dipping formation. (Step  101 )     2) Calculate the dip angles and the cosines of them (i.e., cos φ) at the target reflection horizon and multiply the A-attribute by the corresponding cosine to obtain the dip-compensated parameter A 0 . (Step  102 )     3) Add the B and B′ attributes at each spatial location on the target reflection horizon and multiply the sum by the cosine of the dip angle at that location. (Step  103 ) This result is the sum of unknowns B 0  and B 1 .     4) Estimate B 0  through conventional AVO inversion or angle stacks. (Step  104 )     5) At each location, subtract B 0  from the value of (B+B′) cos φ from step 3 to obtain an estimate of the anisotropic slope term B 1  that measures the azimuthal amplitude variation caused by fracturing. (Step  105 )     6) Iterate this process (step 1-5) with the newly estimated attributes as constraints in the inversion until a desired precision is reached. (Step  106 )        
 
       EXAMPLE  
       [0072]     The Case 1 method was applied to a 3-D seismic dataset to demonstrate the simplicity and data-driven nature of the method. First, AzAVO inversion was applied to derive AzAVO attributes A, B, B′ and ψ 0 . The results for the first three attributes are displayed in  FIGS. 11   a - c  with in-line position plotted as the abscissa and two-way travel time as the ordinate. Attribute intensity is indicated by a gray scale shown in  FIG. 11   a , which displays the attribute A. Attributes B and B′ are displayed in  FIGS. 11   b  and  11   c , respectively. Attributes B and B′ were summed to derive the formation-intrinsic “slope” attribute B 0 , and the results are shown in  FIG. 12 . In this case, the dip angle of the formations is less than 5 degrees according to geological studies. (The dips of events may be directly observed from the attribute displays in each of these sections. The observed dip appears to be higher than 5 degrees. This is an illusion because the horizontal distance has been compressed along the abscissa for convenience of display.) This small dip angle makes it unnecessary to multiply the A and (B+B′) attributes by cos φ to get the formation-intrinsic attributes A 0  and B 0  (see equation 8) because cos φ is very close to 1.0 for such a small dip. In cases of large dip (5°≦φ≦20°), dip angle should be calculated for this transformation.  
         [0073]     It should be appreciated that the particular embodiments may be implemented as part of a program or application operated from a processor based system, such as a computer system. The computer system may include servers and workstations configured to store data and applications in memory to perform the above mentioned methods and processes. Indeed, the computer system may generate a report, which may be displayed on a monitor coupled to the computer system, stored in memory of the computer system, or printed from a printer coupled to the computer system. Further, a user may interact with the computer system to perform the embodiments or the computer system may perform the method without user intervention, as can be appreciated by those skilled in the art. Regardless, at least a portion of the particular embodiments, which are discussed above, may be stored in computer readable media for execution by the computer system.  
         [0074]     The foregoing description is directed to particular embodiments of the present invention for the purpose of illustrating it. It may be apparent, however, to one skilled in the art, that many modifications and variations to the embodiments described herein are possible. All such modifications and variations are intended to be within the scope of the present invention, as defined by the appended claims.