Amplitude Versus Offset Effects Research Articles

Spectral Decomposition AVO attributes for identifying potential hydrocarbon-related frequency anomalies

Low-frequency seismic anomalies have long been a subject of interest to geoscientists involved in hydrocarbon exploration since such ‘gas-shadows’ can be a direct hydrocarbon indicator (DHI). Published studies have demonstrated evidence for them potentially resulting from increased seismic attenuation and velocity dispersion, as a result of hydrocarbon saturation. The topic gained wide interest during the 2000s with well-cited publications by Castagna et al. (2003), Ebrom (2004), Chapman et al. (2005, 2006) and Odebeatu et al. (2006), to name a few. The consensus of these studies was that hydrocarbon related frequency effects are predicted to be detectable on stacked seismic data. Furthermore, it has been suggested that low frequencies tend to show the highest sensitivity to fluid changes. (e.g. Korneev et al., 2004). The effect has been shown not only from seismic data; studies involving laboratory tests and borehole data provide similar conclusions. Overall there is general agreement that the effect exists. However the physical cause remains inconclusive. Several studies have also shown evidence that hydrocarbon reservoirs have an amplitude-versus-offset (AVO) frequency dependence (e.g. Chapman et al. (2005, 2006), Odebeatu et al. (2006), Liu et al. (2006), Ren et al. (2007), Zhang et al. (2007), Chen et al. (2008), Wu et al. (2014)). In the modelled case of gas-saturated sands, low frequencies have tended to show the greatest change in amplitude with offset (Figure 1a). The idea of using AVO and Spectral Decomposition (SD) to understand frequency anomalies and potential links to reservoir fluid content has been approached by several of these authors. The published work largely used model-based techniques to predict AVO effects for different frequencies (Figure 1b), and then applied this information to aid interpretation of anomalies observed on iso-frequencies sections. The results convincingly suggest that there are differences in the spectral content of seismic data which could be exploited for improved hydrocarbon identification. The results of these pioneering publications is the basis from which the workflow presented in this paper was conceived. Here these ideas are approached from an interpretation perspective and applied in a practical manner using commercial interpretation software.

Amplitude versus offset (AVO) modelling and analysis for quantitative interpretation of porosity and saturation: A case study for Sawan gas field, middle Indus basin, Pakistan


 
 
 Porosity and water saturation are among the important reservoir parameters in terms of reservoir monitoring which in turn are necessary for placement of future production wells. Amplitude versus offset (AVO) modelling and analysis technique have been utilized for quantitative interpretation of porosity and water saturation. For AVO modeling, Gassmann fluid substitution model in connection with 2D seismic angle gathers were used for reservoir monitoring over Sawan-4 and Sawan-7 wells. AVO modellingresults showed significant increase of density log by substituting gas by water, moderate increase of P-wave velocity and no change in S-wave velocity. Moreover, AVO modelling proved a strong relationship between porosity and reflection amplitude for all offset ranges. The class IV anomaly was evident for all porosities down to 5%. From fluid substitution modelling it is evidentthat changes in water saturation do not change the AVO effect significantly which further substantiate by investigation of pre-stack time migration (PSTM) gathers verifying the modelling results. The amplitude relationship between Sawan-4 and Sawan-7 is close to the modelled result. The amplitude and the AVO behaviour indicate lower porosity or significantly reduced sand thickness in the vicinity of Sawan-4 and Sawan-7 wells.
 
 

An Amplitude-Based Modeling Method and its Application on the Impedance Inversion in Heterogeneous Paleokarst Carbonate Reservoirs

For the modeling of complex reservoirs with strong heterogeneity, for instance the deeply buried paleokarst reservoirs in the Tarim Basin, the traditional method by lateral interpolation and extrapolation of measured logs between well locations with the guiding of interpreted seismic horizons is driven by distance and often leads to non-geologic solutions, while the past improvements via adding seismic velocities or attributes information are still not accurate due to the resolution limitation or AVO (amplitude versus offset) effects contamination. In this paper, we present an amplitude-based modeling method by utilizing the heterogeneous information from seismic data to guide the geological model construction, based on the inverted pure P-wave data which have removed the AVO effects. The proposed method is applied in the impedance inversion of the paleokarst carbonate reservoirs in the Tarim Basin, where the reservoirs are characterized by substantial heterogeneity. Both the constructed Low frequency model (LFM) and the inverted impedance results of proposed method are more correlative with drilling data than that of traditional method. This method is more beneficial for strong heterogeneous reservoirs description especially in well insufficient or absent areas, suggested by the comparisons with traditional methods in the ZG8 area.

The Comparison between Full-Stack Data and Pure P-Wave Data on Deeply Buried Ordovician Paleokarst Reservoir Prediction

<span style="font-size: 10.5pt; font-family: 'Times New Roman','serif'; mso-bidi-font-size: 12.0pt; mso-fareast-font-family: 宋体; mso-font-kerning: 1.0pt; mso-ansi-language: EN-US; mso-fareast-language: ZH-CN; mso-bidi-language: AR-SA;" lang="EN-US">The present burial depth of the paleokarst reservoirs in the Tarim Basin is greater than 5000m, which premises rigorous demands for the data quality for accurate predictions. Although routinely used for reservoir prediction, the conventional full-stack data are often contaminated by the AVO (amplitude versus offset) effects no matter how much signal to noise ratio degree can be enhanced via stacking. This contamination usually changes with different geological deposits, and could reach an inappropriate and unacceptable level for the deeply buried carbonate reservoir in the Tarim Basin. In this paper, the pure P-wave data theoretically inverted through AVO effects removal are employed to improve reservoir prediction, which are illustrated by the comparisons with that of the conventional full-stack data for the classical four AVO models and the field data in the ZG8 area, Tazhong Uplift, central Tarim Basin. The dominant frequency has been improved for 8 Hz from 15 to 23 Hz in the target Yingshan formation, Ordovician through AVO effects removal, and the reflection events of the pure P-wave data are obviously more continuous comparing with that of the full-stack data. The fake potential reservoir caused by AVO effects in the northeast area has been removed, while the integral delineation of paleokarst reservoirs have been significantly improved with a higher fitness with the oil-testing results, which are more beneficial for later on exploration. The pure P-wave data inversion is in essence an important complement to current processing strategy.</span>

Seismic processing, inversion, and AVO for gold exploration — Case study from Western Australia

We investigate the potential of using high-resolution seismic methods for rock characterization and for targeting of gold deposits at the St. Ives gold camp. The application of seismic methods in hard-rock environments is challenged by complex structures, intrinsically low signal-to-noise ratio, regolith distortions, and access restrictions. If these issues can be addressed, then the unparalleled resolving power of reflection seismic can be used for mineral exploration. Appropriate spatial sampling of the wavefield combined with a survey geometry design and rigorous data processing to incorporate high fold and long offsets are necessary for creation of high-quality seismic images. In the hard-rock environment of Western Australia, accurate static corrections and multiphase velocity analysis are essential processing steps. This is followed by a rigorous quality control following each processing step. In such a case, we show that the role of reflection seismic could be lifted from mere identification of first-order structures to refined lithological analyses. Five deep boreholes with sonic logs and core sample test data were used to calibrate 2D seismic images. Despite seismic images were produced with relatively robust scaling it was possible to achieve reasonably high seismic-log correlation across three of the tightly spaced boreholes using a single composite wavelet. Amplitude-versus-offset (AVO) analysis indicated that gold-bearing structures may be related to elevated AVO effect and increased reflectivity. Consequently, partial stack analysis and acoustic and elastic inversions were conducted. These results and impedance crossplots were then evaluated against known gold occurrences. While still in the preliminary stages, hard-rock seismic imaging, inversion, and the application of AVO techniques indicated significant potential for targeting mineral reserves.

Prestack migration concepts for AVO measurements on horizontal and dipping layers

Amplitude versus offset (AVO) processing is typically based on a model of horizontal reflectors and common midpoint (CMP) gathers. Seismic prestack migration on constant offset sections has also been used to improve the signal to noise ratio (SNR) of the AVO effect on the migrated CMP gathers that are referred to as common reflection point (CRP) gathers. The use of prestack migration in AVO measurements is aided by the scatterpoint concept that assumes reflectors can be composed of many scatterpoints (or reflecting elements) that are aligned along the reflector. The energy scattered by each point reconstructs to match the specula reflected energy. The energy from each scatterpoint forms a surface in the prestack volume that is often referred to as Cheops pyramid. The location of specula energy from a scatterpoint is identified by the tangential area between the reflected specula energy and the surface of Cheops pyramid. In addition, the incident and reflection angles from a scatterpoint may be superimposed on Cheops pyramid to identify any smearing that may occur. These principles apply to both horizontal and dipping layering. Conventional constant offset prestack migration can map horizontal and dipping specula energy to corresponding CRP gathers for AVO analysis. This method, however, requires an accurate velocity model before AVO measurements can be obtained. The equivalent offset method (EOM) of prestack migration forms prestack migration gathers that are referred to as common scatterpoint (CSP) gathers with no time shifting of the input data. This process uses minimal velocity information to rapidly form CSP gathers that that are also well suited for AVO analysis. After the gathers are formed, accurate velocities can be estimated and AVO measurements made.

A, B AVO cross plotting and its application in Greenland and the Barents Sea

Recent amplitude versus offset (AVO) interpretations in the Norwegian Barents Sea and offshore West Greenland have identified subtle and complex anomalies which are best interpreted using a layer-specific, amplitude and gradient cross plot analysis scheme. The creation of AVO intercept (A) and gradient (B) seismic sections allows for a variety of stacks including A, B, A times B, and A plus B. Also, A versus B cross plots are easily generated to help define shale, wet sand and hydrocarbon trend lines that better differentiate the anomalies and provide information concerning the geological framework that created the AVO response. Determination of the background trend on an A versus B cross plot is problematic in AVO analysis since variations in lithology and depth are interdependent, with both factors greatly influencing this trend. Also, the background trend is empirically defined by the AVO response of shale-on-shale boundaries or shale-on-silt reflectors, and this may not be indicative of the trend line for a shale-on-wet sand response. However, once the empirical background trend or wet trend is established, A and B data can be rescaled such that the shale line takes on a slope of −1. Potential hydrocarbon anomalies will then plot as data points with maximum scatter away from the normalized shale line. An A plus B section based upon a normalized shale line shows the potential hydrocarbon anomalies at maximum amplitude and the wet sands at minimum amplitude. AVO analysis of A and B is generally performed together with forward modelling that generates theoretical responses for intercept amplitude (A) and gradient (B) parameters. The forward modelling helps validate the processing steps, give clues as to the non-uniqueness of various A and B responses, and integrates the geology into the study. In the Fylla area, offshore West Greenland, an AVO analysis focused on large flat spots identified on the seismic data, as part of a licence application. A and B analysis was used to delineate trends in the data, to isolate three different classes of AVO anomalies which suggest the presence of hydrocarbons, and to provide insight as to the rock properties of the interbedded sandstones and shales. An AVO analysis was also performed to help evaluate the prospectivity of an area in the Norwegian Hammerfest Basin. The purpose of the study was to establish the expected AVO response for the prospective interval from nearby gas discoveries and determine if similar anomalies exist within the prospect area. The AVO work consisted of forward modelling and A plus B analysis. Subtle AVO effects associated with gas in the Middle Jurassic section were identified.

Anisotropy and amplitude versus offset: a case history from the West of Shetlands

An amplitude versus offset (AVO) case study is presented from the West of Shetlands, UKCS in which pre-drill AVO signatures over a prospect were interpreted to be expressions of hydrocarbons but upon study of the data provided by the well were interpreted as a manifestation of anisotropy. The core from the well proved to be crucial in understanding the non-hydrocarbon AVO signature. The well encountered good quality, high porosity, water wet sand and an underlying tuff sequence. Neither the dipole sonic log nor the check-shot survey revealed any anomalous elastic properties, nor did they detect the presence of anisotropy. Conventional, isotropic modelling using the measured log properties could not match the observed AVO response. Only comparison of the dipole sonic log and the check-shots with the core measurements gave evidence for the presence of substantial elastic anisotropy. Incorporation of anisotropy inferred from core and log measurements in the shales and tuffs gave a reasonable match to the observed AVO. The inferred anisotropies are substantial, averaging 15% for both the compressional and shear velocities and increasing over some depth intervals to 25%. A subsequent walkaway vertical seismic profile (VSP), acquired for the specific purpose of calibrating the AVO response, shows a marked AVO effect at the base of the target sandstone and tuffs, consistent with the surface seismic data. It is clear from this case study and other work that simple transverse anisotropy, for example, produced by the natural layering in shales, can cause first order effects on the AVO response.

AVO as an Exploration Tool in the Penola Trough, Otway Basin

In 1988, Katnook-1 discovered gas in the basal Eumeralla Formation in the Penola Trough. All subsequent commercial discoveries have been within the underlying Crayfish Group. Amplitude-versus-offset (AVO) analysis performed on single gather records correctly predicted the subsequent discovery of gas within the Crayfish Group in the Katnook-2 and Ladbroke Grove-1 wells. Seismic recorded since 1990 has generally better quality data which are more suitable for AVO analysis. Two lines were recorded in 1993 over the Katnook Field, tied to the three Katnook wells. Only a small AVO effect was predicted at some locations from modelling using the well data, which was probably due to the poor quality well logs. The seismic AVO analysis, however, using all gather records, produced clear anomalies at both reservoir levels which approximately matched the predicted extent of the gas in the field from structural mapping. The subsequent Katnook-4 appraisal well confirmed the presence of gas at these levels, but unfortunately was not commercial. AVO and inversion were also run over the Haselgrove Gas Field prior to its discovery in 1994. AVO anomalies are seen at both Katnook reservoir levels, but the strong basal Eumeralla Formation anomaly is interpreted to be due to a clean, water saturated sand rather than gas. The anomalies at the top Pretty Hill Sandstone level are more consistent with structure although they extend below mapped closure. Subsequent reprocessing using pre-stack migration prior to AVO analysis produced anomalies which closely match the actual gas column height, and are within the zone of strong seismic amplitudes at this level. AVO anomalies in the area appear to be caused by both clean, water filled sands and the presence of hydrocarbons. Seismic inversion can help the prediction of sand quality variations, and the mapped extent of structural closure can be used to identify those AVO anomalies more likely to be related to hydrocarbons. Pre-stack time migration prior to AVO processing is essential in most cases. Unfortunately, AVO anomalies also occur in reservoirs with low gas saturations or low reservoir permeability. Despite these drawbacks AVO with inversion has proven to be a valuable exploration tool in the Penola Trough. No gas discoveries have yet been made which are not associated with an AVO anomaly.

Viscoelastic attenuation, anisotropy, and AVO

The classical interpretation relating Amplitude Versus Offset (AVO) to Poisson’s ratio and other petrophysical properties is based on the assumptions of elasticity and isotropy. We extend this interpretation to a layered medium with anisotropic and/or viscoelastic properties, using a Fourier Pseudo‐Spectral method to solve the wave equation. Both viscoelasticity and anisotropy are key factors for the quantitative interpretation of AVO trends, because they contribute to the seismic energy partition at geological interfaces (the reflection coefficients), and because they continually induce propagation effects. We show that: 1) Reflection coefficients at an interface are strongly dependent on the elastic anisotropy of both the overlying and the underlying media. The AVO effect is further complicated by materials with viscoelastic properties. 2) Propagation effects are due to elastic anisotropic energy focusing and viscoelastic dissipation that distort the energy and phase distribution of the incident and reflected wavefronts. These two phenomena can be of the same order of magnitude as variations in reflection amplitudes with offset and can make it difficult to recover reflection coefficients along an interface from seismic data. In theory, they make the amplitude determination of a seismic event somewhat dependent on wavelet phase changes that occur continually as the wavefront propagates. In practice, they create anisotropic radiation patterns and differentially focus the seismic energy distribution along the wavefront. For these reasons, all detailed reservoir characterizations based on modeling and interpretation work should attempt to account for anisotropy and viscoelastic attenuation; this is not an easy task in the real world because of the difficulty in prescribing appropriate physical parameters.

Anti-Aliasing and Amplitude Preserving 2D and 3D DMO — some Practical Considerations

A practical definition of DMO (Dip Move-Out) is that it is a mapping to zero offset. In order to avoid the arbitrary attenuation of dipping events in this mapping process, Amplitude-Preserving or True-Amplitude DMO is needed. Such a DMO algorithm will be an invaluable tool in the study of AVO (Amplitude-Versus-Offset) effects. A method is described whereby both anti-aliasing and Amplitude-Preserving DMO can be implemented using the integral approach (also known as Kirchhoff DMO, Summation DMO, and (x-t) or space-time DMO). Anti-aliasing is accomplished by using band-limited sincfunction interpolators based upon local dip of the impulse response of the DMO operator. This enables the appropriate amplitude weighting along the DM0 impulse response to be applied. That gives rise to the so-called True-Amplitude and Amplitude-Preserving DMO algorithms. The F-K domain offers a useful platform for the comparison and implementation of various weighting factors for the DMO impulse response. F-K analyses of impulse responses can be used to illustrate the effects of anti-aliasing and amplitude properties of integral DMO. In 2D, where in general there is regular sampling in the common offset plane, the anti-aliasing and Amplitude-Preserving DMO algorithm improves the image quality in the mapping of pre-stack data to zero offset. In the 3D case the DMO ellipse is exactly the same as the 2D DMO ellipse, apart from the fact that for 3D DMO we must rotate the ellipse to lie in the direction given by the source-receiver axis with respect to the processing grid. This grid is usually organised in terms of 3D binline and 3D CMP (Common Mid-Point). In marine data, streamer feathering has the effect of spreading midpoints (3D CMPs), for a given sail line, over several 3D binlines. The result of this is to vary the distribution of source-receiver azimuths (feather angles) within a given bin. This leads to irregular sampling in the common offset-azimuth plane where 3D DMO is performed. Whilst Kirchhoff methods have the flexibility of dealing with irregularly sampled data, the desirability of regular sampling in this common offset-azimuth plane in order to preserve amplitudes is illustrated. Methods for data regularisation in offset and azimuth are not discussed here. Instead we question the need for 3D DMO in certain marine applications. A simple criterion for determining the condition under which cable feathering becomes a significant factor in determining the need for 3D DMO is presented in tabular form and its implications are discussed.

Seismic AVO analysis of a permian gas sand at Kerna field, Cooper Basin, SA

The Kerna gas field is located in the south-central part of the Cooper Basin close to the large Dullingari and Toolachee Fields. Kerna is a domal anticline and contains gas structurally trapped within sandstones of the Early Permian Patchawarra Formation. The overlying Epsilon Formation sands also contain gas which may be stratigraphically trapped around the south and west flanks of the field.Seismic reflection amplitudes are used to map the extent of this Epsilon gas sand. Seismic modelling studies show that the gas sand displays an amplitude-versus-offset (AVO) response which distinguishes it from a wet sand or from a coal bed at the same stratigraphic level. Constructive and destructive interference from the top and base of the gas sand, and from overlying coal seams, have a marked effect on the overall seismic stack response of the target horizon. The modelled AVO response shows a good correlation with AVO changes on cd.p. gathers from seismic lines across the area.The spatial distribution of the AVO anomalies (AVO increases), and of the overall seismic stack response, has been mapped across the field and can be used to locate future appraisal and exploration wells. This study has implications for other areas of the Cooper Basin where adequate separation between coal beds and gas sands allows the AVO effect of the latter to be observed. These AVO effects can then be used as a direct indicator of gas in stratigraphic or even structural traps.

SEISMIC AVO STUDIES ASSIST IN THE MAPPING OF A PERMIAN GAS SAND AT KERNA FIELD, COOPER BASIN

Kerna is a gas field within the south-central part of the Cooper Basin, 12 km southwest of the Dullingari Field and adjacent to the border of South Australia and Queensland. The trap is a domal anticline containing gas structurally trapped within the Early Permian Patchawarra Formation. The overlying Permian Epsilon Formation, above intervening shale, also contains gas, which may be stratigraphically trapped or restricted by permeability barriers around the southern and western flanks of the field.Seismic reflection amplitudes can be used to map the extent of the Epsilon gas sand. Seismic modelling studies show that the gas sand displays an amplitude-versus-offset (AVO) effect which distinguishes the gas sand from a wet sand or from a coal reflection at the same stratigraphic level. The spatial distribution of the AVO anomalies, and of the overall seismic stack response, has been mapped across the field. The interpreted 'seismic facies' map shows a meander belt across a coal swamp dominated flood plain. The distribution of AVO anomalies within and around this meander belt shows the likely occurrence of gas-bearing sandstones.This study has implications for other areas of the Cooper Basin where adequate separation between coal beds and gas sands allows the AVO effect of the latter to be observed. These AVO effects can then be used as a direct indicator of gas in stratigraphic and structural traps.