AVO Effects Research Articles

The AVO Effect of Formation Pressure on Time-Lapse Seismic Monitoring in Marine Carbon Dioxide Storage

The AVO Effect of Formation Pressure on Time-Lapse Seismic Monitoring in Marine Carbon Dioxide Storage

ОТДЕЛЬНЫЕ ВОПРОСЫ ДИНАМИЧЕСКОЙ ИНВЕРСИИ ВОЛНОВОГО ПОЛЯ

Currently, reservoir parameter prediction methods based on the amplitude wave field inversion play an important role in solving geological problems in the joint interpretation of seismic and well data. From a formal point of view, well data are used to obtain additional conditions for solving inverse problems of seismic. But the formal description of solution is conditional, there is rather an adjustment of results obtained independently from seismic and well data. The paper considers the following issues: stability of the simultaneous inversion parameter estimation; calculation features of background model and coordination of background and seismic solution components; compliance with restrictions on the maximum sourcereceiver distances by kinematic muting and the range of reflection angles during AVO analysis. The AVO effect is analyzed, it displays itself in a change of the reflection coefficient sign and, correspondently, phase inversion of reflected wave.

2.5D Forward Modeling - a Cost Effective Solution that Runs on Small Computing Systems

Full wave elastic forward modeling from full 3D depth models to produce 3D ? 3C shot records is extremely compute intensive. A methodology has been developed that enables geophysicists to utilize an extremely complex geologic model in the X direction, but that is consistent in the Y direction to produce 3D ? 3C full wave elastic forward modeling results. This methodology can be successfully used to test the viability of recording parameters in thrust belt environments that exhibit extremely complex structures in the dip direction but relatively stable structures in the strike direction. Many other geologic situations involving fracture systems can be effectively modelled using this technology. The method is capable of taking into account the quasianisotropic and velocity dispersion effects of thin beds. Also, for the case of TTI anisotropy (or tilted fracturing, or some combination of tilted fracture systems) 2.5 D modeling allows us to simulate both ?fast? and ?slow? shear waves and also simulates the effects of wave coupled refraction. In addition, Q parameters for P and S waves can be defined to accurately simulate polarization effects for both surface waves and volume waves. The accuracy of the method is such that geophysicists can predict the azimuthal AVO and velocity effects of fracture systems and test the effectiveness of full elastic inversions and various seismic methods that are available to measure azimuthal variations of seismic parameters. The mathematical derivation of the process will be discussed and examples of the usage of 2.5 D forward modeling in exploration will be illustrated.

AUTOMATIC ESTIMATION OF STACKING VELOCITY BASED ON SPARSE INVERSION

AbstractStacking velocity analysis is a routine procedure in seismic data processing, and is also a classical method for initial velocity model building. Usually, stacking velocity analysis is divided into two steps: calculating stacking velocity spectra and picking spectra maximums. Until now, many researchers are trying to improve the stacking velocity spectra by computing a better semblance, considering the AVO effect or improving the anti‐noise ability of algorithm. However, it is seldom discussed on how to calculate the stacking velocity automatically. In this paper, we try to solve this problem by combining the velocity spectra calculation and picking procedure into a model parameter estimation under the framework of sparse inversion. Therefore, it is possible to invert the stacking velocity automatically and shorten the turn‐around time of initial velocity model building and reduce human costs considerably. To solve this problem, first we give the definition of forward problem, which is the prediction model for CMP gather using stacking velocity and t0 time as model parameters. Then, the inverse problem is defined as finding the sparse model parameters with the given CMP gather. Using the sparsity of model parameters as model constraint, we reformulate the conventional stacking velocity analysis problem as a new sparse inverse problem, and present an adaptive matching pursuit (MP) algorithm to solve it. The proposed method is quite promising for automatic initial model building, and can provide a good initial model for subsequent high‐resolution velocity inversion methods. Numerical and field data tests demonstrate the effectiveness of the proposed method.

Spectral decomposition influence on AVO effect

Delineating the extend of a producing reservoir is one of the main challenge of exploration and development interpreters. Our approach to address this challenge is to use ?spectral decomposition? of pre-stack data couple with an AVA/AVO studies (Amplitude Versus Angle/Offset). Seismic spectral decomposition is a known method to determine more accurately the lithology of an area of interest. AVO effect are used to identify and quantify the extend of a fluid anomaly in a potential reservoir. Combine together, the aim of this method is to provide a better delineation of the producing area. A shared earth approach will be used in order to perform cross validation of the results at each step. The first step is a 1D study well bore centred: Using well logs information: Vp (compressional velocity), Vs (Shear velocity) and the density to compute a first set of synthetic gather that will constitute our reference. The chosen well has an AVO effect and should be visible on this reference set. A real set of pre-stack gather at the well bore will then go through a series of tests to identify the best frequency bandwidth that identify more accurately the AVO effect. In a second phase, this frequency bandwidth will be used to produce two results: A 3d set of gather with this optimum bandwidth. Producing Gradient and the Intercept of this set, a cross plot of those attributes should confirm the result of the 1D study and will help to delineate the AVO effect spatial extent. An inversion based on this spectral decomposition should help to delineate more accurately the reservoir lithology Those results unified well bore information, seismic pre and post stack data, frequency analysis and inversion results. The analysis will tend to demonstrate that lithology and gas anomaly can be better mapped using combined methodology, compare to a juxtaposition of methods.

AVO inversion and Lateral prediction of reservoir properties of Amangi hydrocarbon field of the Niger Delta area of Nigeria

Well log modelling was performed using a complete suite of compressional, shear and density logs to understand and determine the expected angle dependent effects in the seismic reflection data and also to estimate wavelets for the different input stacks. The available well controls were used in wavelet estimation and we incorporated AVO modelling to properly account for AVO effects. We partitioned the 3D seismic reflection data into three partial angle stacks of near (0 o - 10 o ), mid (11 o - 20 o ) and far (21 o - 30 o ). Wavelets were estimated separately for each angle stack to enable the inversion to compensate for offset dependent phase, bandwidth, tuning and normal moveout (NMO) stretch effects which could affect the amplitude and phase spectra of the data. We then simultaneously inverted multiple angle stacks to transform P-wave offset seismic reflection data to P-impedance and S-impedance volumes. These impedance volumes were interpreted separately. This method supported interpretation in this field where the reservoirs' sandstones and shales cannot be distinguished from the P- impedance alone.

Multi-scale characterisation of the Paaratte Formation, Otway Basin, for CO2 injection and storage

A resurgent interest in the gas potential of the Gulf of Papua has been enhanced by the recent announcement of developing new LNG facilities in Port Moresby. Petroleum Geo-Services (PGS) has recently acquired a 6,000-km2Multi-Client 3D (MC3D) survey in the gulf. Although most of the discoveries in PNG are from the highland areas, the gulf is a proven hydrocarbon province with gas/condensate accumulations previously discovered in several reef build-ups. It is thought that sediments from the Papuan Fold Belt produced clastic dominated deltas in the Gulf area. Although this play is untested offshore, there is evidence these sandy facies exist and could contain hydrocarbons. On the first phase of acquisition/interpretation, an efficient screening workflow called Prospect Scanner, developed to highlight areas of AVO effects in large 3D seismic datasets, was tested. It uses pre-stack seismic time migrated (PSTM) gathers to extract AVO attributes that are then inverted to derive relative acoustic and shear impedance volumes. Using idealised cross-plots, the relationship between Vp/Vs ratio and the Ip values gives a good indication of the fluid and lithology of the tested interval. The results are loaded into a conventional interpretation package for interpretation/visualisation. Prospect Scanner has highlighted previously undrilled turbidite and basin floor fan prospects in the region. The Vp/Vs versus Ip cross-plot shows clustering ofthe sand anomaly and good separation from the majority of the plot. These points correspond to the idealised location for a gas sand. Past concerns about lateral prediction of reservoir presence and quality associated with the basin floor fans can be addressed through this workflow.

Amplitude-versus-offset (AVO) screening in frontier basins: an example from the Gulf of Papua, Papua New Guinea

A resurgent interest in the gas potential of the Gulf of Papua has been enhanced by the recent announcement of developing new LNG facilities in Port Moresby. Petroleum Geo-Services (PGS) has recently acquired a 6,000-km2 Multi-Client 3D (MC3D) survey in the gulf. Although most of the discoveries in PNG are from the highland areas, the gulf is a proven hydrocarbon province with gas/condensate accumulations previously discovered in several reef build-ups. It is thought that sediments from the Papuan Fold Belt produced clastic dominated deltas in the Gulf area. Although this play is untested offshore, there is evidence these sandy facies exist and could contain hydrocarbons. On the first phase of acquisition/interpretation, an efficient screening workflow called Prospect Scanner, developed to highlight areas of AVO effects in large 3D seismic datasets, was tested. It uses pre-stack seismic time migrated (PSTM) gathers to extract AVO attributes that are then inverted to derive relative acoustic and shear impedance volumes. Using idealised cross-plots, the relationship between Vp/Vs ratio and the Ip values gives a good indication of the fluid and lithology of the tested interval. The results are loaded into a conventional interpretation package for interpretation/visualisation. Prospect Scanner has highlighted previously undrilled turbidite and basin floor fan prospects in the region. The Vp/Vs versus Ip cross-plot shows clustering of the sand anomaly and good separation from the majority of the plot. These points correspond to the idealised location for a gas sand. Past concerns about lateral prediction of reservoir presence and quality associated with the basin floor fans can be addressed through this workflow.

Seismic amplitude-based characterisation of the E-BD reservoir. A modelling approach

Research Article| December 01, 2006 Seismic amplitude-based characterisation of the E-BD reservoir. A modelling approach Tobias R. Tonsing Tobias R. Tonsing Tullow Oil (previously with PetroSA) 21st Floor, Metropolitan Centre, 7 Coen Steytler Avenue, Cape Town, e-mail: tobias.tonsing@tullowoil.com Search for other works by this author on: GSW Google Scholar South African Journal of Geology (2006) 109 (4): 551–554. https://doi.org/10.2113/gssajg.109.4.551 Article history first online: 09 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation Tobias R. Tonsing; Seismic amplitude-based characterisation of the E-BD reservoir. A modelling approach. South African Journal of Geology 2006;; 109 (4): 551–554. doi: https://doi.org/10.2113/gssajg.109.4.551 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietySouth African Journal of Geology Search Advanced Search Abstract The geometry of the E-BD reservoir is such that that the thickness of the oil-leg and the water-leg are usually below the seismic limit of separability. Seismic amplitudes from a 3D survey have previously been used to characterise the reservoir. The validity of this approach is however affected by a thin, silt-rich unit that overlies the reservoir in places. This unit has been termed abandonment facies (AF), and modifies the seismic amplitude of the reservoir-top reflection. AVO effects along reservoir-associated interfaces also influence the stacked seismic amplitude. Five boreholes intersect the E-BD channel. Log data from these boreholes indicate changes in acoustic properties across the sandstone interval. These changes also affect the amplitude of the observed seismic data. In this article, the results of a 2D modeling study are presented, which was undertaken to understand these seismic amplitude effects. You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

AVO attribute analysis and seismic reservoir characterization

This article summarizes some basic concepts in AVO processing and the computation of prestack seismic attributes. Seismic modelling forms the basis for understanding the seismic signature. It helps in the prediction of reservoir characteristics away from well control points. Reliable estimation of petrophysical parameters is needed as input for such studies. These petrophysical estimates are an integral part of more advanced reservoir characterization and modelling. First, the AVO principles are described and various prestack attributes are presented. Subsequently, the elastic approach is discussed and finally the benefits of seismic modelling with advantages of multi-disciplinary reservoir studies are demonstrated. The amplitude character of seismic reflections varies with offset, due to changes in the angle of incidence. The commondepth- point (CDP) gather (Fig. 1a) shows the variation for different traces. Figure 1b illustrates the changes in the seismic response when a water-wet brine-filled reservoir is replaced by oil or gas. The synthetics are calculated along a normal incidence and zero offset trajectory. The hydrocarbon saturation is set at 80% (Robinson et al., 2005). Both hydrocarbon cases show brightening of the reflection with respect to the brinefilled scenario. The sands have lower acoustic impedance (AI) than the encasing shales. Not only the top reservoir reflection shows this increased contrast tendency, but the seismic loop directly below it also manifests considerable changes. Figure 2 illustrates a positive gas-sand reflection decreasing with offset, while the negative water-wet reservoir above shows less reflectivity change. The polarity of the data is normal, i.e. an increase in acoustic impedance with depth (or hard kick) corresponds to a peak to the right on the seismic traces. The two highlighted reservoirs are of differing petrophysical character and the encasing geology (compaction/lithology) changes with depth. Although this kind of amplitude variation is evident on the prestack CMP gathers, it has been somewhat ignored in the past by interpreters because they work primarily with the stacked migration data set. Nowadays, special studies are conducted on a routine basis to analyse the behaviour of the ‘amplitude-versus-offset’ (AVO-studies). This type of data contains detailed information on the porefill of reservoirs (e.g. Ostrander 1984; Castagna and Backus 1993; Chiburis et al., 1993; Hilterman 2001; Veeken et al., 2002; Da Silva et al., 2004a). Ultimately it will lead to a more efficient evacuation of hydrocarbons with substantially improved recovery factors (Fig. 3). The amplitude behaviour of the different raypaths also varies according to the porefill and lithology. Water-filled reservoirs often show variations in amplitude with offset that are different from those of hydrocarbon-filled reservoirs. The change in zero-offset reflectivity R0, or intercept, is the most diagnostic feature. The seismic response depends on the encasing geology, porefill, and interference effects. It varies with depth and differs in various parts of the world. Studying the prestack differences in detail can indicate the causes of near- and far-offset amplitude variability (Fig. 4). The seismic signature from a gas sand is different from the brine-filled response when the same reservoir is observed under similar conditions. In such a situation, the encasing geology is probably the same and has little influence on the observed anomalous amplitude behaviour. A distinct change in zero-offset reflectivity is probably the most remarkable phenomenon. Changes in amplitude with offset can occur in hydrocarbon- as well as water-bearing reservoirs; in that case the intercept might contain the vital porefill information. The AVO effect represents a potentially powerful tool to discriminate between water- and hydrocarbon-saturated reservoirs. However, it means going back to the prestack domain. It should be ensured that the data on individual CDP gathers come from a consistent subsurface location. This is generally achieved by a proper migration of the input data set (prestack time migration, Da Silva et al., 2004b). Careful data preconditioning is essential when quantitative interpretation is the ultimate aim (Veeken and Da Silva, 2004).

Seismic Inversion Methods and some of their constraints

The interest in seismic inversion techniques has been growing steadily over the last couple of years. Integrated studies are essential to hydrocarbon development projects (e.g. Vazquez et al. 1997, Cosentino 2001) and inversion is one of the means to extract additional information from seismic data. Various seismic inversion techniques are briefly presented. Inversion replaces the seismic signature by a blocky response, corresponding to acoustic and/or elastic impedance layering. It facilitates the interpretation of meaningful geological and petrophysical boundaries in the subsurface. Inversion increases the resolution of conventional seismics in many cases and puts the study of reservoir parameters at a different level. It results in optimised volumetrics, improved ranking of leads/ prospects, better delineation of drainage areas and identification of ‘sweet spots’ in field development studies (e.g. Veeken et al. 2002). The main steps in an inversion study are: ■ Quality control and pre-conditioning of the input data. ■ Well–to-seismic match, zero-phasing of data in zone of interest and extraction of the wavelet. ■ Running of the inversion algorithm with generation of acoustic or elastic impedance cubes and extraction of attributes. ■ Visualisation and interpretation of the results in terms of reservoir development. The inversion methods are either deterministic or probabilistic and the approach can be post- and/or pre-stack. Inversion schemes generally use migrated time data as basic input. The pre-stack method exploits AVO effects on migrated CDP gathers. There is a trade-off between method/cost/time and quality of inversion results. Feasibility studies with synthetic modelling are recommended before embarking on an inversion or AVO project (Da Silva et al., in prep.). The past track record has demonstrated the benefits of the seismic inversion method. However, it should be realised that the inversion procedure is not a unique process, i.e. there is no single solution to the given problem. Care should be taken when interpreting the inversion results. Adequate data preconditioning is a prerequisite for quantitative interpretation of the end results.

Numerical and physical modelling of P-wave AVO response for fractured media

In this study we investigate variations of P-wave reflection coefficients with offset (AVO) and with azimuth (AVA) for a transversely isotropic medium with a horizontal axis of symmetry (HTI) in contact with water, and also with another HTI medium. Aligned, equidistant, vertical fractures, inbedded in an isotropic background, were used to represent a HTI medium. To grasp the effect of fractures their contribution was computed separately and then added to the isotropic background. The total response of a medium is then obtained by adding the two.An approximate equation is used to compute partitioning of seismic energy at layer interfaces. The solution compares well to the results obtained in physical modelling experiments. To analyse AVO and AVA effects we used 3-D multi-azimuth transmission and reflection surveys. The results show that AVA effects are significant even at moderate angles whilst they are dominant for large incident angles. Routine 2-D AVO analysis, as commonly performed, is clearly unsuitable for HTI media.

A case study on using AVO walkaway VSP data - Barrow Sub-basin, Western Australia

In December 1999 the TL/1 JV partners acquired a 2D walkaway VSP survey in the Monty-2 well in the Barrow Sub-basin, Western Australia. The survey was designed to analyse AVO effects and possible later calibration of surface seismic data. The survey was recorded using CGG?s 12 level array tool, the SST-500, and comprised a total of 4 walkaway lines, with 2 azimuths at each of two array positions. Each of the 4 walkaway lines had a length of 6000 meters. Walkaway VSP data was acquired by positioning the array tool just above the two target reflectors, the North Rankin and the Mungaroo ``B' sandstone formations. The VSP data was processed using an `isotropic' sequence, which allowed for a perfect preservation of the amplitude and phase relationships between the three receiver components. AVO estimates were computed from the reflected P-wavefield after shaping deconvolution, derived from the down going P-wavefield. P-wave polarisation information was used to compute reflection angles at the target horizon and the local reflector dip. Finally, synthetic P-wave reflectivity curves were computed for the North Rankin and the Mungaroo ``B' sandstone formation and compared with the borehole seismic measurements. The AVO/AVA response at the top North Rankin reflection was found to be strongly affected by a thin overlaying carbonate layer. The best match between measured AVO curves and isotropic modeling therefore was found for a shale/carbonate model rather than a carbonate/sandstone model. In contrast, the AVO response of the Mungaroo ``B' reflection was found to be in very good agreement with isotropic modeling results.

Numerical and Physical Modelling of P-Wave AVO Response for Fractured Media

In this study we investigate variations of P-wave reflection coefficients with offset (AVO) and with azimuth (AVA) for a transversely isotropic medium with a horizontal axis of symmetry (HTI) in contact with water, and also with another HTI medium. Aligned, equidistant, vertical fractures, inbedded in an isotropic background, were used to represent an HTI medium. To grasp the effect of fractures their contribution was computed separately and then added to the isotropic background. The total response of a medium was then obtained by adding the two.An approximate equation is used to compute the partitioning of seismic energy at layer interfaces. The solution compares well with the results obtained in physical modelling experiments. To analyse AVO and AVA effects we used 3-D multi-azimuth transmission and reflection surveys. The results show that AVA effects are significant even at moderate angles whilst they are dominant at large incident angles. Routine 2-D AVO analysis, as commonly performed, is clearly unsuitable for HTI media and should be preceded by AVA analysis.

To: “Bottom simulating reflectors: Seismic velocities and AVO effects,” J. M. Carcione and U. Tinivella (GEOPHYSICS, 65, 54–67)

There are correct expressions for the elastic moduli K1 and K3

Analysis of Four-Component Data for AVO Effects

This article is a synopsis of paper OTC 10984, "Analysis of 4C Data for AVO Effects at Teal South, Eugene Island 354," G.W. Purnell, B.J. Nolte, P.M. Krail, and D.A. Ebrom, Texaco, originally presented at the 1999 Offshore Technology Conference, Houston, 3-6 May.

Bottom‐simulating reflectors: Seismic velocities and AVO effects

We obtain the wave velocities of ice‐ and gas hydrate‐bearing sediments as a function of concentration and temperature. Unlike previous theories based on simple slowness and/or moduli averaging or two‐phase models, we use a Biot‐type three‐phase theory that considers the existence of two solids (grain and ice or clathrate) and a liquid (water), and a porous matrix containing gas and water. For consolidated Berea sandstone, the theory underestimates the value of the compressional velocity below 0°C. Including grain‐ice interactions and grain cementation yields a good fit to the experimental data. Strictly speaking, water proportion and temperature are closely related. Fitting the wave velocity at a given temperature allows the prediction of the velocity throughout the range of temperatures, provided that the average pore radius and its standard deviation are known. The reflection coefficients are computed with a viscoelastic single‐phase constitutive model. The analysis is carried out for the top and bottom of a free‐gas zone beneath a gas hydrate‐bearing sediment and overlying a sediment fully saturated with water. Assuming that the bottom‐simulating reflector is caused solely by an interface separating cemented gas hydrate‐ and free gas‐bearing sediments, we conclude that (1) for a given gas saturation, it is difficult to evaluate the amount of gas hydrate at low concentrations. However, low and high concentrations of hydrate can be distinguished, since they give positive and negative anomalies, respectively. (2) Saturation of free gas can be determined from the reflection amplitude, but not from the type of anomaly. (3) The P to S reflection coefficient is a good indicator of high amounts of free gas and gas hydrate. On the other hand, the amplitude‐variation‐with‐offset curves are always positive for uncemented sediments.

Deepwater reservoir prediction using seismic and geomechanical methods

In deepwater exploration, due to a lack of well information, seismic data become the main means of predicting reservoirs and hydrocarbons. AVO is the most popular method to detect hydrocarbons. However, factors such as pressure, lithology, and thin‐bed effects can cause false AVO effects. The deepwater Gulf of Mexico, in addition to these complex factors, has simple‐to‐complex salt sheet morphologies. The evolution of these salt sheets through time significantly influences the accumulation and migration pathways of deepwater sediments. In this article, we propose that the hydrocarbon migration pathway and seal integrity can be better understood by combining information about pore‐fluid pressure, effective stress, lithology, and seismic energy attenuation.

Thin‐bed AVO effects

Tuning caused by closely spaced impedance boundaries affects seismic amplitudes. At zero‐offset the shape of the composite reflected signal approaches the time‐derivative of the original pulse as the layer thickness decreases. For layers thinner than half of the tuning thickness, the reflected amplitude is modified by a factor equal to twice the time‐thickness of the thin layer. Offset‐dependent tuning can be approximated by the time differences between primary reflections. For high‐velocity contrasts locally converted waves will also affect the total reflected seismic response. The contribution from intrabed multiples can, in most cases, be ignored. Correction for offset‐dependent tuning should be considered before conventional AVO analysis.

Fracture Detection Using P-wave AVO Measurements

Physical modelling of seismic wave propagation can provide insights into complex structural, stratigraphic and reservoir characterisation problems. The detection and delineation of fracture zones is very important in development drilling. Determination of fracture orientation within a reservoir may play an important role in EOR programs. The fundamental principle used in AVO studies is the extraction of shear wave information present in the reflection amplitude variation with source-receiver distance. The objective of this study was to determine if the shear information in 3-D AVO surveys can be utilised for fracture detection and delineation.A 3-D physical modelling experiment was conducted over a simulated fracture system at the Allied Geophysical Laboratories at the University of Houston. The ‘fracture system’ consisted of three isotropic homogeneous layers with a transversely isotropic Phenolite disc embedded in the central portion of the middle layer. The three layers are: an upper layer of black resin 2741LV; a middle layer of blue Stycast resin 2850MT (containing the anisotropic disc); and a lower layer of Evercoat casting resin. Two 3-D seismic surveys were acquired over the model, one with acquisition lines oriented parallel to, and a second survey with the acquisition lines perpendicular to, the fracture direction. Multi-offset and multi-azimuth seismic experiments were also conducted over the simulated fracture system. After applying corrections for spherical divergence and source-receiver directivity the reflection amplitudes from the black/Stycast resin interface were analysed.The results show that the ‘fractured’ disc is characterised by low AVO gradients in both surveys. In addition, the 3-D AVO gradient estimates from the survey perpendicular to the fracture orientations are 30% to 40% lower than the AVO gradient estimates from the survey with line orientation parallel to the fracture direction. Also, AVO effects along different line orientations suggest that at near offsets the amplitude behavior is similar for all azimuths but at far offsets an anomalous amplitude is seen along an azimuth perpendicular to the fracture zone.