VSP INTERPRETATION, ESTIMATION OF ATTENUATION AND ANISOTROPY

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1 VSP INTERPRETATION, ESTIMATION OF ATTENUATION AND ANISOTROPY F. BABAIA, D.R.D - ENAGEO, HMD Algeria, f_babaia@yahoo.fr F. CHEGROUCHE, D.R.D - ENAGEO, HMD Algeria, f_chegrouche@yahoo.fr. INTRODUCTION An expected advantage of borehole seismic imaging techniques such as vertical seismic profile (VSP) over surface seismic profiles is to reduce travel path for the seismic waves. Because the energy travels only one way through the earth, high frequency components of the borehole seismic signal are attenuated less than those of a surface seismic signal. Therefore, borehole seismic data usually contain higher frequencies and have better signal-to-noise ratios at high frequencies than do seismic surface data at depth where the difference in the lengths of the travel paths is significant. Consequently, The vertical seismic profile measurements have proven useful for estimating rock properties near a well and imaging around it. Basic use of the VSP survey is to determine interval velocities, identify and correlate major reflectors across well logs and surface seismic image. It provides better information about the local formations but its resolution is significantly less than the sonic measurement (which is vulnerable to errors arise from fluid invasion and other borehole effects), although better than the surface seismic data. The VSP techniques are also widely used to determine the attenuation coefficient, anisotropy and lithology. From the source point to receiver, seismic waves are affected by different changes of amplitude, phase or frequency, as function of propagating medium. Because of such different properties as pore structure, fluids content and mineral composition, fluid and rocks respond differently to wave propagation. Consequently, seismic attenuation is recognised as potentially important quantity in reservoir characterization. Attenuated zone may contribute to apparent differences in velocities. The wave amplitude is affected, however, not just by attenuation but also by local elastic constants of medium. If measured elastic constants of a medium vary with direction of wave propagation, the medium is called anisotropic. The seismic anisotropy in sedimentary basins due to some or all of the following: Lithological anisotropy of clay and shale. Thin layering Aligned fractures, cracks and pore space. The VSP data used in this study were acquired in a borehole in the south of Algeria. The survey includes zero offset VSP and offset VSP. The zero offset VSP was used to provide a normal seismic traces at the well bore, P-wave interval velocities and attenuation coefficients. The offset VSP was acquired for S-wave interval velocities, lateral extension and V p /V s ratio. To have a qualitative approach on anisotropy, we ve computed an anisotropic the ratio (V h -V v )/V s ; where V v is the vertical velocity calculated from zero offset VSP, and V h is the horizontal velocity assuming equal to oblique velocity derived from offset VSP. 2. GEOLOGY SETTING The main objective of this drilling is the investigation of the Cambrian s sandstone, which is productive of oil nearby the well, as well as the confirmation of the north s extension of Quartzite formation productive of oil in other wells situated in the south. The region geology is composed essentially of sedimentary rocks. We have alternating sequence of salt and anhydrite of 350m thick, shale layer of 00m, a thin layer of eruptive rock of 20m, a relatively thick quartzite formation of 20m, a thin sandstone layer of 5m, shale layer of 00m... The reservoir lithology is essentially constitute of Ordovician sequence of quartzite formation composed of white grey to white sandstone, very fine to fine, sometimes average, silica quartzitique, passing by place in quartzite, compact, hard and bituminous. We denote also the presence of vertical filled cracks of pyrites. Objectives assigned to the well to be known the investigation of the Cambrian and the confirmation of the extension of Quartzite northward, are reached. The evaluation of well logs, relative to fluids and to petro-physical characteristics of reservoirs, harmony of very near with the results of the DST and those of the analysis of carrots. Indeed, well logs interpretation shows that only the median

2 part of the Quartzite formation is saturated in hydrocarbons with an average porosity of 6 %, a volume of clay of 0 % and saturation in water of 30 %. Whereas the two parts, top and bottom, turned out compact and being characterized by a porosity lower than 5%. The shale formation presenting two sandy levels to the summit, which are not foreseen as objective, show a significant saturation in water (SW = %), the rest of the reservoir is compact. When to the Cambrian, it is water bearing or compact. A test casing was made in the Quartzite formation and produced some oil and gas. 3. VSP INTERPRETATION 3. VSP acquisition. The zero offset VSP data set (96 traces) was acquired in borehole from depth 70m to 3685m. Depth interval varies from nearly 00m between 70m to 28m and nearly 20m from 28m to 3685m. At every top of layers we took a measure. Three components downhole geophone was used to record a vertical component (Z), and two horizontal components (H and H2). Data were sampled in 2ms. The geophone tool was clamped to the borehole wall. A vibrator source, generating compressional P wave, was placed at 60m from the borehole with 2s sweep running from 8-80hz. For the offset VSP, 76 levels with regular geophone spacing (20m), with depth range ( m) were recorded using source-offset equal to 94m. At each measured depth (for either zero offset VSP and offset VSP), several shots were taken to have an acceptable S/N ratio after quality control (vertical stacking). 3.2 VSP processing 3.2. Zero offset VSP processing The raw vertical component of the zero offset VSP is shown in Figure. These traces are plotted in trace normalized form. Several events can be identified in these data such as the downgoing P wave field and reflected P wave, and further processing is necessary to enhance these events. The first break time was picked to be used: to compute depth-time curve, to flatten the direct arrivals in the up and downgoing waves separation process, and to shift data to two way time. The conventional zero offset VSP processing flow include the main following steps: Pre-processing: mute, band pass filter [ Hz] to remain all coherent energy seen on the data, and true amplitude recovery using time variant exponential gain (T.2 ). Median filter for separation of upgoing and downgoing wavefield. Wave shaping deconvolution using the downgoing P waves to design the deconvolution operator to be applied to the upgoing P waves. Shift to two way time by doubling the first break time of the upgoing P waves. The reflections, which are coherent within corridor, are summed to create corridor stack. Fig : Raw vertical channel of the zero offset VSP (Normalized traces) Offset VSP processing The offset VSP data have been processed using a three component processing flow. The flow is designed to extract the P-P and mode converted P-SV reflections from the data. The processing flow is similar in pre-processing, wavefield separation and deconvolution steps. In addition, the three component processing flow includes tool rotation before wavefield separation and offset mapping of PP and PS waves (imaging). Tool orientation: The estimation of the rotation angles is realized by rotating the horizontal receiver components to maximize the projection of the first arrival energy on the horizontal components aligned with the source-receiver direction. The linear polarization of the P-wave arrival constitutes the main assumption of this processing step. Once estimated, the angles have been applied for each measured level. The rotated horizontal component of the seismic wavefield with the maximum direct arrival P-wave energy is defined as the radial component. The transverse component is defined as the component perpendicular to the radial direction. Wavefield separation: After the correction of tool rotation, the vertical and radial seismic wavefield is separated in to upgoing and downgoing compressional and shear wave modes.

3 Median filter was used for this separation. Following the wavefield separation process, waveshaping deconvolution was applied to the data. Subsurface mapping: The final step in the processing flow is to map the upgoing P and SV wavefields to the true offset positions. The Kirchhoff migration and VSPCDP transform were performed for P-P wavefield using the velocity model computed from zero offset VSP. 3.3 Discussion After processing, the VSP data will be interpreted. The objective of VSP interpretation is to Time (msec) Shale Gogger Lagoonal Gogger Anhyd. Lias Salt Lias Anhyd. Lias 2 Salt Lias Horizon B Salt Lias ( & 2) Salt Lias 3 Shale Lias Quartzite Gassi s shale Cambrien Ri Cambrien Ra (a) (b) (c) (d) (e) (f) (g) (h) Fig 2: composite plot: (a) stratigraphic sequence, (b) sonic log, (c) gamma ray log, (d) density log, (e) synthetic seismogram, (f) corridor stack, (g) Kirchhoff migration image and (h) VSP CDP transform image. Shale Lias Quartzite El-Hamra Cambrien Ri Fig 3: surface seismic section correlated with Offset VSP (Kirchhoff migration image).

4 correlate the layers interfaces from the well log to the zero offset VSP corridor stack. In the next step, the corridor stack will be correlated with the offset VSP image and the surface seismic section. A convolution modal was used to compute a synthetic seismogram. The calibrated sonic log (with VSP check shot) and the bulk density log were used to calculate the reflection coefficients. These were converted from depth to time domain using Integrated sonic log (time-depth curve), and then convolved with Klauder wavelet. The composite plot (Figure 2) includes stratigraphic section, well logs, synthetic seismogram, corridor stack and offset VSP subsurface images. There is a good correlation between the corridor stack and synthetic seismogram. The amplitude and seismic character match reasonable well. The zone of interest (Quartzite formation) is between 2.8 and 2.66 s, which is clearly identified on the well logs, synthetic seismogram, and VSP. We ve identified some other interfaces such as salt Lias (&2) at.832s, shale Lias at 2.05s, el Gassi s shale at 2.72s and Cambrian RI at s (Figure 3) Vp, Vs, and Poisson s ratio Good interpretation of the seismic P-wave and S-wave velocities variations and their ratio V p /V s help to obtain information on rock properties. Because any change in structure or composition of rock will causes some change in the propagation characteristics of seismic wave. To understand how different lithology affect Vp, Vs and the ratio V p /V s we must measured them in pure minerals that have no porosity, permeability and fractures. Unfortunately, sedimentary rock will not. P wave velocity V p and S wave velocity V s are dependent on density and the elasticity constants as following: k + 3 µ compression wave velocity: = 4 Vp shear wave velocity: where k: bulk modulus; µ: shear modulus. V s = µ ρ ρ The elasticity constants k and µ are dependent of lithology such as: mineral composition, compaction, cementation and pore filling. Poisson s ratio, which represents the ratio of the transverse contraction to the longitudinal extension under compression or dilatation, can be written in function of k and µ as: 3k 2µ σ = 6k + 2µ Vp 2 Vs and in function of velocities as: σ = 2 2 Vp Vs In this study, P wave velocity was calculated from zero offset VSP data and S wave velocity from fixed offset VSP data. Figure 4 illustrates V s versus V p for the following layers: The quartzite layer composed essentially of sandstone and quartz gives a V p /V s ratio between.50 and.85 corresponding to Poisson s ratio between 0.0 and The El-Gassi s shale layer gives a V p /V s ratio between.60 and 2.2 corresponding to Poisson s ratio between 0.8 and The salt and anhydrite Lias layer gives a V p /V s ratio between.44 and 2.28 corresponding to Poisson s ratio between 0.03 and The shale Lias layer gives a V p /V s ratio between.58 and.8 corresponding to Poisson s ratio between 0.6 and S - Wave velocity [m/ sec] P - Wave velocity [m/ sec] Fig. 4: S wave velocity versus P wave velocity : Salt & Anhydrite Lias : Shale Lias : Quartzite : Gassi s Shale

5 4. ATTENUATION Attenuation is fundamental property of rocks. The attenuation process is known as the decay in amplitude of the seismic wave and the accompanying change in frequency content. The raisons for this attenuation are numerous such as pore structure, fluids content, connectivity of pore, mineral composition and fractures. Therefore, study of the seismic wave attenuation gives information on the rocks and fluids that compose the propagation medium. The amplitude and the shape of seismic wave are not affected only by the intrinsic attenuation due to the rocks and fluids properties, but, many other factors such as the layering, reflection and mode conversions, transmission, source, coupling and spherical divergence are responsible. Our goal is to quantify and eliminate effect of these factors and estimate the attenuation due only to the lithology (intrinsic attenuation). The attenuation measurements are sensitive to frequencies, phase and amplitude of the signal; consequently, seismic borehole data (VSP) give good results because the seismic wave travels only one time through the weathered zone characterized by high loss of seismic wave energy. Three approach are generally used to estimate the attenuation coefficient from seismic data: The spectral ratio method: comparison between spectral of the signal at two different levels after external effects elimination. The amplitude decay method: the decay of the seismic wave amplitude (corrected from spherical divergence and coupling) with distance is attribute to the attenuation. The pulse broadening method: measurement of change in pulse width with distance. The attenuation is expressed as an exponential decay exp(-αz), where β represents the attenuation coefficient and z the distance (depth). The relationship between α and f is: α = πf/qv. Where v is the P-wave velocity and Q is the quality factor (dissipation factor). 4. Q factor estimation: Assuming that the offset VSP source is negligible compared to the target depth and the earth is laterally homogenous, the amplitude spectrum of the windowed zero offset VSP traces at depth z, A(z,f) can be written as: A ( z, f ) = S( z, R( z, E( z, f, α). () where: f : frequency. S(z,f) : source and coupling factor. R(z, f) : recording system transfer function. E(z,f,α) : earth effect including multiples, transmission and intrinsic attenuation (absorption). Where: and ( f ) πf Qv E α( f )z. ( z, f, α) G( z) M( z, T( z, e α =, G(z) : geometric spreading factor. M(z, f) : short periodic multiple effect. T(z, f) : transmission effect. So : = (2) π f ( f ) = S( z, R( z, G( z). M( z, T( z, e Qv A z, (3) z where where Q is the quality factor and v average velocity in the depth range of interest. The amplitude spectral ratio for z and z 0 is: f ( ) ( ) ( ) ( ) ( ) ( z z ) a z f s z f r z f g z m~ 8.7 π 0, =, +, + + z, f QV a ( z, f ) = 20 log A ( z 0, f ) A( z, f ) S( z, f ) s, ( z, f ) = 20 log S ( z 0, f ) (4)

6 R( z, f) r ( z, f ) = 20 log, R( z0, f) G( z) ( ) g z = 20 log, G( z 0 ) ~ M ( z, f ) T ( z, f ) m = 20 log. M ( z 0, f ) T ( z 0, f ) To compute attenuation, two methods are proposed using equation (4), both based on the logarithm of amplitude ratios. The first method assume the quality factor Q to be constant, and the ratios are calculated for variable f and fixed z. Than α is equal to the slop of the best fit straight line. In the second method used in this paper, the ratios are calculated for fixed frequency (f) and variable depth (z). This method has no assumption about dependence of quality factor (Q) on frequency (f), which is its major advantage. The instrument filter is generally the same for all records. Assuming that the downhole geophone coupling effect is independent of frequency, the recording system transfer function R(z, f) is constant, consequently, the ratio r(z, f) is set equal to zero. Assumed to be the same for all depths, source coupling effect ratio s(z, f)=0. Equation (4) can be written as : f z a ~ 8.7 π ( z, f ) = a( z, f ) g( z) = m~ ( z, f ) QV (5) where ã(z,f) is the spectral ratio of real data correcting from spherical divergence effect using equation 8 and z= z-z 0. a ~ ( z, f ) and m ( z, f ) a ~ ( z, f ) and m ( z, f ) ~ are plotted as function of depth z. The slops of the best fits least squares line of ~ give the attenuation coefficients β and β. Equation (5) can be written as: m f a ( z f ) m~ 8.7 π, ( z, f ) = ( β βm ). z= z= i. z QV (6) The coefficient β is the total effective attenuation obtained from real data (zero offset VSP) and the coefficient β m is the attenuation caused by intrabed multiples and transmission loss. To estimate β m we generate a synthetic VSP using the calibrated sonic and bulk density logs. Therefore, the intrinsic attenuation (absorption) β i is equal to the difference of the total attenuation and that caused by multiples and transmission loss. The quality factor (dissipation) is given by: 8.7 π f Q= (7) βiv 4.2 Factors affecting attenuation measurements: One of the most important factors affecting seismic wave amplitude is the lithology (absorption), but there are some other factors affecting seriously the amplitude and the shape of the signal. These factors are related to the propagation of wave in homogenous media and to acquisition and processing data. Therefore, to have an. accurate computation of the intrinsic attenuation, we must take account for all other factors Spherical divergence: The maximum amplitude of each trace is shown in figure 5, both corrected and uncorrected for geometrical spreading losses. Therefore, it is necessary to estimate this factor with accuracy. For horizontal stratification medium the geometric spreading correcting factor G n at the bottom of n-th layer can be written as (O Brien and Lucas, True depth [m] 97): Fig. 5: First arrivals amplitude curve versus depth before and after spherical divergence correction Amplitude after before.

7 G 2 n cosθ cosθn = 2 v n i= r v n i i i= r v cos i i 2 θ i (8) where r i is the distance travelled by the ray in the i-th layer, θ i is the angle between the ray and the vertical, and v i interval velocity Intrabed multiples: Generally, the subsurface layering complicates the estimation of attenuation coefficient (absorption) because; the measurement contains not only the anelastic dissipation but some other factors. Several works realized by Schoenberger and Levin (974, 978) have demonstrated that the short period multiples generated in finely layered medium are very important in seismic energy transmission. The accumulative energy caused by intrabed multiples reduce the downgoing wave energy loss, but the tapered first arrival used in the spectral-ratio method is not the pure direct P-wave. The downgoing source pulse is superimposed on unwanted reverberations generated in the vicinity of the geophone location which produces its broadening. The effect of the intrabed multiples is similar to that due to the intrinsic attenuation (absorption), therefore, it s very difficult to separate them. Estimation of the intrinsic attenuation enables removal of intrabed multiples contribution from the total effective attenuation. A synthetic VSP in non absorptive medium (Q = in all layers), generated with the velocity and density logs derived from data well, is used to estimate the intrabed multiple effect Transmission loss: The transmission coefficient is given by: T = 2. Z / (Z + Z 2 ), where Z indicates acoustic impedance (velocity x density) and the subscripts and 2 refer, respectively, to the upper and lower layers. The transmission coefficient is related to the acoustic impedance. When the acoustic impedance increases, the downgoing arrival amplitude decrease, on the contrary, if the acoustic impedance decreases the amplitude increase. To quantify the effect of transmission, a synthetic VSP is used Source and coupling: Relocating source during acquisition and change in source coupling with the earth produce changes in the shape and amplitude of the source signature. If the downhole geophone coupling to the wall of the borehole is poor, the attenuation measurements are sensitively affected. The good quality of VSP data used in this paper suggests that there is no problem of coupling Interference from upward waves: Reflectors below the downhole geophone generate reflected P wave and mode converted SV waves. Interference of these upward waves with the first arrival causes drastically changes in the shape and amplitude of the downgoing wavelet. These upgoing events can be easily identified in the VSP records, they have opposite slope sign to the downgoing first arrival. Therefore, using apparent velocity filters we can eliminate them, but this did not enhance the depth resolution of attenuation, and they introduced too much mixing of the data. Because of deficient in improvement, we did not apply filtering. 4.3 Results and discussion The VSP was recorded between 28m and 3685m, in an uncased borehole. The quality factor (Q) was computed using equation 6. Since, during VSP acquisition there was not a source (vibrator) move up, the source coupling effect could be the same for all measured depth. The control of downhole geophone coupling to borehole wall was performed using an oscillator in the recording unit. On the observer report there was no coupling problems mentioned during acquisition; therefore its effect was negligible. The intrabed multiples and transmission effects were accounted by the synthetic VSP, which was computed using the calibrated sonic log, the bulk density log, and the following parameters: depth range [28 to 3685m], recording length 2s and sample rate 2ms. The convolved wavelet was extracted from the no-interfered first arrivals of the real data. Finally, we have selected a narrow window centred about the first arrivals to isolate the downgoing wavelet and to minimize the effect of Interference from upward waves. The selecting window must not be rectangular to avoid the leakage effect in the amplitude spectrum caused by the time window truncation. As well as, the uses of tapering is necessary, but it must be slowly to reduce the leakage and no large to avoid

8 the broadening of the spectrum. After several test, we have opted to 6 ms linear tapering at the top and the bottom of 62 ms selected window (respectively, 36 ms and 26 ms before and after the first break pick time). Figure 6 illustrates the real and synthetic windowed aligned downgoing first arrivals used in the amplitude spectral ratio computation for all traces. The amplitude spectrum of the no-interfering first arrival is illustrated in figure 7. Frequency range is limited between 5-45hz. The attenuation coefficient and Q factor are estimated for each formation separately as following: Calculation of amplitude spectral ratios between measured depth (z) and chosen reference depth (z 0 ) for both real and synthetic data. In experiment VSP data set, for each frequency, slop of the best fit straight line of amplitude spectral ratios versus depth curve, is equal to the total effective attenuation coefficient β t. With synthetic VSP data set, the slop is equal to the attenuation coefficient β m (caused by intrabed multiples and transmission).. The difference between β t and β m gives the intrinsic attenuation coefficient (absorption) β i. Then the quality factor Q was computed using equation 7 (where v is the average velocity of actual layer). Time (ms) Time (ms) Hz (a) Traces (b) Traces Fig. 6: windowed data used in attenuation computation; (a) Real data after divergence corrections. (b) Synthetic (with transmission and multiples effects) Amplitude Frequency [Hz] Fig. 7: Amplitude spectrum of reference trace Hz 4.3. Quartzite formation (Reservoir): [ m] This layer is composed of quartzite sandstone and quartzite rocks. It represents the reservoir, which is fractured and produces oil with a very low porosity. The results obtained from the spectral ratio method applied to the data recorded at depths range [ m] are illustrated in figure 8. Where symbols ( ) represent the spectral amplitude ratio variations, the straight line in each plot is the best linear fit to the observed variations. The number at the bottom left corner of each plot indicates the frequency in Hz. Attenuation coefficients versus frequencies are plotted in figure 9. The curve in gray represents the total attenuation, which increases with frequency until 38 Hz. This does not describe the attenuation caused only by the lithological properties of rocks. So, the dash curve (transmission and short multiple effects) illustrates small amplitude decay at low frequencies and an important increase of amplitude at high frequencies. The solid curve (pure intrinsic attenuation) demonstrates the linear relationship between intrinsic attenuation and frequencies. (db) 8.8 Hz 39.6 Hz 35.4 Hz 3.2 Hz 27. Hz 22.9 Hz 4.6 Hz Depth [m] (a) (db) 8.8 Hz 4.6 Hz Depth [m] (b) Fig. 8: Amplitude ratio vs. depth for each frequency; (a) Real data; (b) Synthetic data (for Quartzite formation) Hz 35.4 Hz 3.2 Hz 27. Hz 22.9 Hz

9 Attenuation [db/ m] Multiples and transmission attenuation Total attenuation Intrinsic attenuation Frequency [Hz] Fig. 9: Attenuation coefficient vs. frequency; multiples and transmission attenuation coefficient curve; total effective attenuation coefficient; intrinsic attenuation coefficient. The last column of table represents the Q factor of the quartzite formation. It has an average value of 30 corresponds to relatively high attenuation due to the presence of fractures f β m 0-3 β 0-3 β i 0-3 Q Table : attenuation coefficients (db/m) and Q-factor for Quartzite rock Salt and Anhydrite Lias formation: [ m] This formation is constituted of massive salt with plastic shale intercalation and anhydrite. Table 2 illustrates a low attenuation for frequencies between [5-35Hz], and an important attenuation coefficient for high frequencies [35-45Hz], and an average Q factor of 70 corresponding to the dominant frequency ( 30 Hz).

10 f β m 0-3 β 0-3 β i 0-3 Q Table 2: attenuation coefficient (db/m) and q-factor for salt and anhydrite Lias El-Gassi s shale formation: [ m] This formation is composed of compact shale with P wave velocity of 4400 m/s (average). We denote the presence of hydrocarbon in the top of formation. The attenuation is more important at low frequencies (Table 3). The Q factor corresponding to the dominant frequency is about 30. f β m 0-3 β 0-3 β i 0-3 Q Table 3: attenuation coefficient (db/m) and q-factor for shale el-gassi rock Cambrian Ri formation: [ m] This formation is constituted of massive consolidated fine grey-white sandstone, siliceous to silicaquartzite, with shale intercalation. Although its high velocity (5000m/s), the Cambrian Ri is characterised by high attenuation coefficient may be caused by presence of water (sw 00%). The Q factor is about 8.

11 f β m 0-3 β 0-3 β i 0-3 Q Table 4: attenuation coefficient (db/m) and q-factor for Cambrien Ri Shale Lias : [ m] This layer is composed of clay brown and rarely brown red, soft, and slightly dolomitic with past of anhydrite white, pulverulent and of translucent white salt. The application of the amplitude spectral ratio method gave a quality factor of a large values (superior to 80), what corresponds to a very weak attenuation. The negative values of the attenuation coefficient β i are due to instability of the least square fitting for very weak slops. The reduced number of measured depth can also be the cause of this instability. f β m 0-3 β 0-3 β i 0-3 Q Table 5: attenuation coefficient (db/m) and q-factor for Shale Lias Carbon and Anhydritic Lias: [244076m] This layer is composed of clay brown, soft to hard, sometimes plastic, slightly dolomitic, with crossed of anhydrite white, pulverulent and of dolomite limestone beige gray and hardened microcrystalline. We have obtained a quality factor Q, which is sensitively important for low frequencies. For the

12 dominant frequency (f=30hz), the quality factor Q is approximately equal to 28. The results in table 6 demonstrate that the high frequencies were more attenuated than the low frequencies in this layer. 5. ANISOTROPY f β m 0-3 β 0-3 β i 0-3 Q Table 6: attenuation coefficient (db/m) and q-factor for Anhydrite & Salt Lias 5. backgrounds Current methods of P wave seismic data imaging ignore the traveltime and velocity distortions caused by seismic anisotropy. And the velocity isotropy remains the usual assumption in conventional reflection seismic analysis, even if most rocks are anisotropic. Recently, the implication of anisotropy in seismic imaging resolution has been recognized. Velocity anisotropy of given layer can help in lithology description. The medium is called anisotropic, while a measured physical property varies with direction. Conversely, if the physical property is equal in all directions, the medium is called isotropic. In sedimentary rocks, the anisotropy, which is a fundamental property of wave propagation, could be caused by: Lithological anisotropy of clay and shale (argillaceous) rocks due to foliation of clay minerals; Thin layering; Aligned fractures, cracks and pore space. We can distinct two type of anisotropy based on the symmetry of the elastic properties:. Transverse anisotropy: with a symmetry axis normal to the bedding. It can be defined by five elastic constants of the stiffness tensor. Lithological anisotropy of clay and shale, and anisotropy due to thin layering have a rotation axis normal to the bedding planes. In sedimentary basins, the axis is usually near vertical. This is called Transverse Isotropy about a Vertical axis of symmetry (TIV). 2. Azimuthal anisotropy: a medium is called azimuthally anisotropic if velocity of seismic wave varies with azimuthal angle. Aligned fractures and cracks, and dipping transversely isotropic shale would be azimuthally anisotropic. If a sequence of thin layers contains vertical fractures and aligned cracks would be orthorhombic anisotropic, defined as combination of both transverse and azimuthal anisotropy. 5.. Lithological anisotropy of argillaceous rocks Most sedimentary basins are essentially composed of argillaceous rocks (between 50-75%), so it s obviously important to know the anisotropy caused by this type of rocks. Field experiments have demonstrated that argillaceous rocks are transversely isotropic about a direction of symmetry perpendicular to the bedding. Scanning electron micrographs allow estimating the distribution of clay platelet alignments.

13 5..2 Fractures, cracks and pore space Fractures control much of the mechanical strength and transport properties of its solid structure. Fracture systems are also crucial for hydrocarbon production. Seismic shear wave is the most successful methods for the detection and characterization of fractures and prediction of fluid flow direction Results and discussion P wave Velocity anisotropy is the percentage measure of the maximum variation in velocities usually defined by the ratio (V max - V min )/V max x 00, where V max, is the maximum velocity (horizontal velocity) assuming equal to oblique velocity derived from offset VSP using first break time and the incidence angles of direct arrivals. V min is the minimum velocity (vertical velocity) computed from zero offset VSP. A hodogram (recorded at 2720m measured depth) showing the vertical motion of P wave from offset VSP is plotted in figure 0. The angle of incidence estimated from hodogram will vary with depth because of changing geometric relationship between the source and receivers and of the downgoing P wave refraction as it passes through media with different velocities. The angles of incidence (Figure ) used in maximum velocity computation are calculated in three different methods. Geometric angle of incidence: assuming a homogeneous medium with a constant velocity, the seismic ray is a straight line from source location to receiver. Theoretical angle of incidence: computed from a synthetic model with ray tracing method in homogeneous and isotropic medium. Zero offset VSP interval velocities are used. Real angle of incidence: estimated from particle motion analysis (hodogram analysis) using experiment offset VSP. Figure illustrates that the geometric angles of incidence are more vertical than the theoretical angles. This could be due to refraction through medium where P wave velocity increase with depth. The same observation for the hodogram angles of incidence except for depth ranges from 3220 to 3400 m and from 3540 to 3600m, where the geometric angles are sensitively more horizontal. These anomalies can be attribute to an anisotropic medium. To confirm this assumption we must analyse the vertical and oblique P wave velocities. For a vertical well, the velocity (vertical component) at the receiver array for a given source position can be calculated directly from the arrival times of the zero offset VSP wavefront measured at the geophones placed within the formation of the interest. Velocity [m/sec] Incidence angle [degrees] Z-Component X-Component Fig 0: particle motion analysis to estimate first break polarization angle Depth [m] Fig : (a): incidence angle computed from hodogram (solid), incidence angle computed from synthetic model (dashed), geometric angle (gray). (b): First arrival s polarization ratio Fig. 2: oblique velocity computed using: geometric angles (gray), theoretical angles (dashed), and hodogram angles (solid) (a) (b) Depth [m]

14 Meaningful interval velocities from offset VSP can only be computed if we have a good idea of the angle of incidence. Supposing that there are no severe lateral variations, we compute the interval velocities using three methods: Method based on geometric angles of incidence. Method based on the theoretical angles of incidence derived from ray tracing. Method based on the real angles of incidence derived from the hodogram analysis Figure 2 shows velocities computed from three methods. It is not surprising to see that the geometric velocity is greater than the theoretical and hodogram velocities. We can also denote that theoretical and hodogram velocities converge in depth range from 2700 to 3200m, and diverge from 3200 to 3600m. Figure 3 shows sonic velocity, vertical velocity derived from zero offset VSP, and oblique velocity derived from offset VSP. Salt Lias formation presents a good convergence between different velocities with velocity anisotropy ratio between 0.7% and 3.4%, which mean that the Salt Lias is a near isotropic formation. In Shale formation the anisotropic ratio is more important (6.4 %) probably due to presence of clay. In the Quartzite rocks, the velocity anisotropy ratio is about %. Since sonic log shows no presence of thin layers in this formation we can attribute this important magnitude of anisotropic ratio to intrinsic anisotropy probably due to vertical fractures in the reservoir rocks. The shale formation presents abnormal observation with oblique velocity less than the vertical velocity. Probably, this anomaly is caused by uncertainly of estimating incidences angles as visible in figure 0 with a relatively poor polarisation ratio, or the vertical velocity derived from experiment VSP is not exact. Solt Lias Horizon B CONCLUSION Our goal is to extract maximum information from the VSP data. First, the correlation of VSP data with synthetic seismogram and well logs gives excellent results. The reservoir top and bottom (Quartzite) are clearly identified. Fixed offset VSP image gives laterally extension (450m) from well in which we denote the presence of discontinuous (faults). Three components downhole used in acquiring VSP data permit to have converted shear wave component. Therefore, converted shear wave velocity V s was combined with V p to give additional information on lithology. The attenuation is important in seismic exploration because it affects the seismic wave amplitudes, phase and frequency. The study of quality factor also describes the lithology, and fluid saturation of propagation medium. Data set from borehole give a good signal to noise ratio from direct waves. In this study, we have found several problems in estimating Q factor with accuracy using amplitude spectral ratio method due to interference of primary reflections with direct arrival, and missing information such as downhole geophone monitor. So we have proceeded to estimate the Q factor for each formation separately. The reservoir has an important attenuation coefficient (Q 30). Water saturation (Cambrian R i ) causes high attenuation (Q 8). The estimation of the rate of P wave velocity anisotropy allowed us to have an idea on the geologic layers. Obtained results showed that salt Lias rock presents a weak rate of anisotropy, contrary to the shale Lias rock which presents a rate relatively important (6 %) due to the presence of the clay. The reservoir presents a raised percentage of anisotropy of % due to the vertical cracks as well as to the presence of hydrocarbons. This method is sensitive to angles of incidence where from the necessity of a scrupulous analysis of the particles motion. Salt Lias & 2 Salt Lias 3 Depth [m] Shale Lias Eruptive rocks Quartzite El-Gassi s shale Alternating zone 3600 Velocity [m/sec] 0.7 % 3.4 % 6.4 % -0. %.0 % Fig. 3: vertical velocity (dashed) compared to oblique velocity (solid)

15 ACKNOWLEDGMENTS This work was supported by the National Enterprise of Geophysics (ENAGEO). We thank Dr A. BENHAMA for comment on the manuscript and Dr A. ZEGADI and A. GUERCHAOUI for useful discussion. Conversation with S. FERRAZ helped in well logs interpretation. We also extend our appreciation to Mr S. AGOUNIZERA for help. We thank SONATRACH/Exploration for permission to publish this paper. REFERENCES. J. Pujol and S. Smithson: Seismic wave attenuation in volcanic rocks from VSP experiments, Geophysics 99, Vol. 56, N 9, p J. Pujol, E. Luschen and Yiguang Hu: Seismic wave attenuation in metamorphic rocks from VSP data recorded in Germany s continental super-deep borehole, Geophysics998, Vol. 63, N 2, p A. Kebaili and D. R. Schmitt: Velocity anisotropy observed in wellbore seismic arrivals: Combined effects of intrinsic properties and layering, Geophysics 996, Vol. 6, N, p J. O. Parra, Chris L. Hackert, Qingwen Ni, Hughbert A. Collier : Annual report May 2000, Southwest Research Institute, San Antonio, Texas. 4. Marie Josèphe PETIT: Evaluation des mesures d atténuation sismique à partir des enregistrements du profil sismique vertical, thèse de doctorat 3 ème cycle, Université de Paris sud Colin M. Sayers : Determination of an anisotropic velocity models from walkaway VSP data acquired in the presence of dip, Geophysics 997, Vol 62, N 3, p K. Dautenhahan yatt: Synthetic 6. R. H. Tatham and M. D. McCormack Multicomponent seismology in petroleum exploration, investigation in geophysics n 6, society of exploration geophysicists. 7. R. H. Danbom and S. N. Dominico Shear wave exploration, geophysical development series, volume, society of exploration geophysicists.