Low Frequency Based Seismic Data Processing: An Effective Tool for Direct Hydrocarbon Indicator in Complex Lithological Environment

Comparison of spectral decomposition methods

Seismic coherence is commonly used to delineate structural and stratigraphic discontinuities. We generally use full-bandwidth seismic data to calculate coherence. However, some seismic stratigraphic features may be buried in this full-bandwidth data but can be highlighted by certain spectral components. Due to thin-bed tuning phenomena, discontinuities in a thicker stratigraphic feature may be tuned and thus better delineated at a lower frequency, whereas discontinuities in the thinner units may be tuned and thus better delineated at a higher frequency. Additionally, whether due to the seismic data quality or underlying geology, certain spectral components exhibit higher quality over other components, resulting in correspondingly higher quality coherence images. Multispectral coherence provides an effective tool to exploit these observations. We have developed the performance of multispectral coherence using different spectral decomposition methods: the continuous wavelet transform (CWT), maximum entropy, amplitude volume technique (AVT), and spectral probe. Applications to a 3D seismic data volume indicate that multispectral coherence images are superior to full-bandwidth coherence, providing better delineation of incised channels with less noise. From the CWT experiments, we find that providing exponentially spaced CWT components provides better coherence images than equally spaced components for the same computation cost. The multispectral coherence image computed using maximum entropy spectral voices further improves the resolution of the thinner channels and small-scale features. The coherence from AVT data set provides continuous images of thicker channel boundaries but poor images of the small-scale features inside the thicker channels. Additionally, multispectral coherence computed using the nonlinear spectral probes exhibits more balanced and reveals clear small-scale geologic features inside the thicker channel. However, because amplitudes are not preserved in the nonlinear spectral probe decomposition, noise in the noisier shorter period components has an equal weight when building the covariance matrix, resulting in increased noise in the generated multispectral coherence images.

Channels are hydrocarbon prospective areas which are often below the resolution of seismic data. This study was therefore conducted with the aim of using spectral decomposition methods for imaging of buried channels and associated structures in a 3D Post-Stack Depth Migrated (PSDM) volume acquired from a field in the Niger Delta Basin. Two commonly used spectral decomposition methods were used to enhance the resolution of seismic data for interpretation. The methods utilized included Fast Fourier Transform (FFT) and Continuous Wavelet Transform (CWT). Petrel and Opendtect were the interpretational software tools utilized for the study. The seismic data was conditioned using structural smoothing, and a zone of interest was selected around -1000 to -3000ms. Three dominant frequencies were selected from the sub-volume generated around the zone of interest. The frequencies were 10Hz, 25Hz and 32Hz respectively. These frequencies were extracted from the seismic data using FFT and CWT decomposition methods. The results were colored using Red, Green and Blue (Red for 10Hz, Green for 25Hz and Blue for 32Hz). These frequencies were then blended together in a process called RGB blending. The resultant output was a mix of only these three dominant frequencies. Analysis of these results revealed the presence of several channels, crevasse splay deposits, flood-plains and faults on two time-slices obtained at -2020ms and -1800ms. The channels were meandering channels of low sinuosity, some of which were fault controlled. The crevasse splay deposits were significantly large and increased in number at the shallow time-slice. Some of the crevasse splay deposits were found bifurcating fault lines and being deposited on floodplains, indicating that they were younger than the faults. Channel flow direction was from East to West, while channel migration was from South to North of the study area. The increase in the number of channels from the base to the top of the seismic data suggested a multistory stacked channel system. It was established that channels and crevasse splays were best enhanced using the FFT decomposition method while major and minor faults were best enhanced using CWT method. Hence, this study has proven that the spectral decomposition method is very effective in imaging subsurface buried channels, thus delineating prospects and can be used for reservoir characterization. Keywords: Spectral decomposition, Fast Fourier Transform (FFT), Continuous Wavelet Transform (CWT), Channels, Crevasse splays, Faults, Reservoir Characterization.

Summary Conventional seismic sections cannot display most of the important events in reservoir studies. The study of frequency content of seismic sections can provide better understanding to geoscientists, as well as interpreters in the field of petroleum engineering studies. An isofrequency process is a powerful tool in terms of reservoir imaging. One of the methods that provides isofrequency slice is Spectral Decomposition (SD). SD is a comprehensive method that eliminates most of limitations encountered in seismic data to reveal geological information. SD provides continuous analysis of amplitude, frequency, phase, and energy spectrum. Therefore, SD is applied to obtain an amplitude spectrum of frequency content of seismic trace which is attributed to the temporal center of the sample trace. So higher frequency resolution is obtained at lower frequencies and higher time resolution at higher frequencies. In this paper, Short Time Fourier Transform (STFT) and Continuous Wavelet Transform (CWT) as SD methods were used in order to detect sand channel at one of the Iranian Southwest oil fields for which it has the potential to be considered as a reservoir.

The pre-stack time migration and velocity analysis methods on common scatter-point (CSP) gathers are based on pre-stack Kirchhoff time migration. The concept of equivalent offset provides a new idea for the research of seismic pre-stack migration and velocity estimation. In this paper, according to the theory of the equivalent offset, we derive the travel-time equation of CSP gathers, introduce the related pre-stack time migration method and discuss velocity analysis methods based on the CSP gathers, and point out the advantages of CSP methods over conventional methods. Processing of a model example and field seismic data show the validity of CSP pre-stack time migration and the velocity analysis methods based on it.

Summary Results from the P-P and P-Sv prestack time migration of a 2.5D four-component (4C) OBC seismic swath test acquired in 2004 over the Pamberi area in Block Lower Reverse L offshore Trinidad, are presented. The 4C swath acquisition consisted of twelve 100-m spaced source lines, shot into two parallel 15-km OBC receiver lines, separated by 400 m. A description of the processing applied to the recorded multicomponent (4C) seismic data, through curved-ray anisotropic Kirchhoff prestack time migration for both the compressional P-wave and mode-converted PSv-wave, is provided. Mode-converted shear-wave data acquired from 4C surveys allow for imaging where conventional seismic data are perturbed due to the presence of shallow gas and/or fluid in the pore spaces of the rock. Furthermore, mode-converted shear waves propagate with a different raypath than that of the compressional wave, thereby providing an alternative illumination of the subsurface target. As both the compressional P-wave and mode-converted S-wave record independent measurements of the same subsurface, more reliable rock properties can be uniquely determined, allowing for improved reservoir characterization and lithology prediction. A conventional streamer 3D survey was acquired over the Pamberi area in 2003, but failed to image or resolve adequately the target reflectors comprising the reservoir under the main growth fault. Therefore, the purpose of the 4C swath test was to evaluate the potential of long-offset multicomponent technology for resolving stratigraphic interpretation in complex areas with challenging geology.

Seismic inversion has become a standard geophysical tool to enhance seismic resolution, predict the reservoir porosity distribution, and to discriminate between reservoir and non-reservoir pay zones. Conventional seismic data does not record the low frequencies necessary for inversion. To enable a complete bandwidth, low frequencies are modelled from well data and are typically interpolated throughout the volume using seismic velocities. This often causes the resultant porosity distribution calculated from the inverted P-impedance to be biased by the well data and the geometry of well locations. Dual-sensor GeoStreamer technology was used to acquire a regional multi-client 2D survey by PGS in 2008, including some lines over the Ichthys gas-condensate field in the Browse Basin. Dual-sensor streamer processing recovers a wider frequency bandwidth than conventional seismic. Receiver ghost removal combined with deep streamer towing simultaneously boosts both the low and high frequencies. The improved bandwidth enables a higher quality of velocity analysis, which further improves resolution throughout the section. Simultaneous inversion of the data validated the uplift of the low frequency data, and significantly reduced the bias towards well data for the low frequency model. The resultant P-impedance data demonstrated an excellent tie to well data. The dual-sensor technology promises to improve the description of the porosity distribution within our reservoir model.

The following is a brief investigation into additional understanding of hydrocarbon indicators and processing methods leading to stratigraphic investigations from seismic. The resultant hydrocarbon indicator net pay thickness graph combined with wave forms identification allows for a rapid approximation to sand thickness. Also, there exists the flexibility to adjust the determinations based on availability of additional geologic or geophysical control. The results of pulse compression filtering in combination with spike-like deconvolution on present seismic data has the potential for stratigraphic interpretation from seismic data. The approach can provide sand-shale ratios of greater precision and reliability. The method is applicable to all marine provinces and is a possible approach to the stratigraphic understanding of land seismic data. INTRODUCTION The original concept for the investigation in seismic identities evolved from a study that attempts to resolve a rapid but simple method of thickness estimates of observed hydrocarbon indicators. Hence, the initial investigations were directed toward what constitutes a hydrocarbon indicator; how a hydrocarbon indicator is recognized and what would be entailed in a simple but creditable thickness measurement method. This method of thickness measurement was not to compete with precise modeling, but to be an exploratory tool to determine the merits of additional modeling requirements. In the process of attempting to devise a rapid and somewhat creditable measurement method, considerable reprocessing of offshore data was performed in order to gain increased resolvement of hydrocarbon indicator Characteristics. In the analysis of the reprocessed information several factors concerning the known stratigraphic environment of the area were enhanced. Thus, as additional efforts were performed, it became apparent that the onset to stratigraphic seismic data enhancement could become a practical exploration tool. Hence, the evolvement of this report, "Seismic Identities: Stratigraphic and Hydrocarbon Determination." The paper will discuss briefly both hydrocarbon determination with some results and examples of those results in stratigraphic enhancement. HYDROCARBON Determinations The following discussion will investigate several aspects in the understanding and determinations of hydrocarbon indicators, their use and problems. A method of computing net pay thickness can be accomplished faster and to a higher degree of reliability, yet allowing the flexibility of change based on increased knowledge of the area. The use of amplitude is shown to be limited in section depth, thus stressing the importance of other characteristics in the determination of possible hydrocarbon indicators. Tables 1 and 2 compare the positive and negative aspects of hydrocarbon indicator characteristics. AMPLITUDE The most controversial and referred to characteristic of a hydrocarbon indicator is amplitude. Amplitude is generally a prime factor in the initial determinations of a true hydrocarbon .indicator, and considerable effort in quality control has recently been devoted to amplitude preservation in seismic data processing methods. Thus, a discussion on the factors affecting amplitude has merit in the understanding of a usable and qualitative hydrocarbon indicator. The prime factors affecting amplitude are reflection coefficients (density velocity relationship) and boundary curvature (structural orientation - focusing variation).

Laboratory measurements of acoustic properties of representative rock samples, simulating in-situ effective stress and fluid saturation, provide useful guides for calibrating and interpreting seismic and sonic log data. This paper addresses some of the major implications arising from a petro-acoustic study for the evaluation of reservoir depletion of Cooper Basin gas reservoirs using logs and seismic. Measurement of P- and S-wave velocities on cores under varying pressure conditions reveals that the stress dependency of Cooper Basin rocks is very large, while core porosity remains effectively unchanged.The saturation heterogeneity at pore-scale, which is shown in capillary pressure data, controls the velocity- saturation in partially water-saturated samples. The steady decrease of P-wave velocity as saturation decreases from the high saturation range to near irreducible conditions suggests a simultaneous drainage of water from pores with a variety of high to moderate aspect ratios, while microcracks (low aspect ratio pores) retain water. Closure and degree of saturation of the low aspect ratio pores control the velocity-effective stress and velocity-saturation relationships at low saturation and stress conditions.The velocity dispersion due to frequency difference between ultrasonic laboratory measurements on cores and theoretical low (seismic) frequency is about 1%, and thus laboratory-measured velocities are comparable with sonic log and seismic data in the Cooper Basin. The potential of the velocity ratio (Vp/Vs) for detection of fluid type and the saturation status at in-situ reservoir effective stress, and prediction of Vs from Vp, are demonstrated for the Cooper Basin rocks. Acoustic measurements on cores, wireline data and seismic modelling are used to predict the expected change in seismic response as the reservoir depletes. Synthetic seismic profiles indicate that the zero-offset reflectivity of a shale to reservoir interface decreases by 28% for a 30 MPa pressure depletion in a typical gas expansion drive reservoir. Such changes should be easily measurable between repeated surveys, suggesting that time-lapse seismic for the monitoring of in-situ effective stress and saturation may have application in Cooper Basin reservoirs. Although these findings refer specifically to the Cooper Basin, the methods used and results of this study may be applicable elsewhere.

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.

Low S/N ratios, interfering diffractions, and dip‐related problems (e.g., reflector point dispersal, dip‐dependent NMO, and reflection angle) make reliable amplitude versus offset (AVO) analysis a difficult task. Prestack time migration (PSTM) collapses diffractions, increases the S/N ratio, and reduces dip‐related problems. Therefore, PSTM is usually required before offset dependent information can be extracted from seismic data, and PSTM is mandatory before comparing real seismic data with 1-D earth model synthetic data. We present a 2-D frequency‐wavenumber common‐offset prestack time migration algorithm. To treat the amplitudes correctly, a 3-D to 2-D transform of the data is required before doing the migration. This is done by correcting the data for out‐of‐plane geometrical spreading. Migration artifacts are attenuated, exploiting the fact that the maximum dip to be migrated decreases with increasing traveltime and offset. The final processing steps before further processing are 2-D geometrical spreading correction and removal of the implicit NMO correction inherent in the migration. Two marine data examples show improved data quality after prestack time migration, making subsequent amplitude analysis more reliable.

In the process of quantifying resources/reserves, geoscientists attempt to employ all the available pertinent information to produce the most accurate results. The presence of direct hydrocarbon indicators (DHI) on seismic data can have a significant impact on the reserve/resource calculations not only for volumes, but also uncertainty levels. In 2001 a consortium of oil companies was organized in an attempt to understand seismic amplitude anomalies interpreted as DHIs and their impact on prospect risking and resource calculations (Roden et al., 2005; Forrest et al., 2010). The geologic setting, seismic and rock physics data quality, DHI characteristics, and calibration of drilling results are all incorporated into a database in a consistent and systematic process. From this process, the evaluation of 217 prospects and associated well results has enabled an in-depth understanding of the relevant key aspects of seismic amplitude anomalies and how they relate to drilling results.

Seismic processing is expected to deliver a reliable product for seismic structure interpretation and reservoir characterization to support subsequent reservoir modeling and drilling operation. 3D OBC wide-azimuth (WAZ) seismic data has a significant advantage in this respect, since it contains large offset and wide azimuth information, which can be utilized for amplitude versus offset (AVO) and amplitude versus azimuth (AVAz) analysis respectively. However, these advanced studies require area-specific data processing efforts in this region for strong linear noise, multiple noise, designature uncertainty etc. Seismic data re-processing was newly conducted in pre-stack time migration (PrSTM) sequence to overcome such technical challenges. Surface-wave noise attenuation was achieved by 2D and 3D model-based dispersive energy attenuation and multi-pass structure oriented filtering in pre-stack and post-stack stages. Source-side deghosting highlighted a low frequency residual bubble and was followed by another pass of de-bubbling based on a smooth spectrum assumption. Shallow water reverberation was minimized by 3D deconvolution and high-resolution radon demultiple. 5D regularization and interpolation with trace densification provided evenly populated traces for each angle and azimuth sectors. Intensive signal preservation protected diffraction energy and resulted in better fault imaging than the vintage processing outcome. Both the vintage and the re-processed seismic data were evaluated in quantitative manners to compare with each other. Angle stacks from the re-processing showed more reasonable response for AVO analysis. Azimuth stacks showed stable S/N ratio leading to higher confidence in azimuthal anisotropy analysis. All these seismic deliverables enable accurate elastic property estimation and detail fault interpreation at target reservoir intervals. The novelty of the proposed workflow is to overcome common technical problems with targeted noise and multiple reduction focusing on angle / azimuth stacks. It unlocks advanced geophysical study for carbonate reservoir in shallow water areas. Processing deliverables will be fully utilized in fault interpretation, AVO and AVAz analysis and will support the forthcoming field development activity.

Marine data acquisition and processing has generated new concepts in velocity analysis, amplitude analysis, and frequency analysis. This has been possible because of consistent surface conditions on marine data, development of direct detection of hydrocarbon concepts, and improved computing power. Exploitation of the correlation of time, amplitude, velocity, and frequency relations has been largely confined to time, amplitude, and velocity. Such basic seismic theories as dispersion, fluidity, and multiple energy indicate a strong relation between frequency and velocity. Experiments on synthetic data illustrates an additional interdependence between apparent velocity and frequency. Both the theoretical assumptions and the synthetic exercises are reenforced by experiments on seismic data. Overlays of continuous velocity analysis and continuous frequency analysis show a substantial correlation. Frequency analysis in a seismic section dimensionally compatible contour allows the correlation with velocity on large volumes of data. An example on Gulf Coast data indicates good potential for this type of analysis. INTRODUCTION The advent of marine seismic recording in conjunction with increased energy needs resulted in a very large volume of seismic data. It was also marine data which generated improved methods of rock velocity estimation. Direct detection of hydrocarbons motivated attention toward such neglected seismic observations as phase and frequency anomalies. Time relations continue to be the basis of interpretation of structure but stratigraphic exploration and direct detection of hydrocarbons brought amplitude to the fore as a meaningful and interpretable measure. Amplitude, while difficult on land data, is reasonably consistent on marine data due to the relatively steady surface conditions at sea. Analysis of both velocity and frequency began to receive more attention for the same reason. Interpretation techniques on seismic data broadened to include frequency and velocity considerations. Time, amplitude, velocity, and frequency are all directly related to the earth response. Anomalies in the seismic data usually will create anomalies in some of these basic parameters so that they are at least indirectly related to each other. Some formulas relating these measures are well known and much utilized. The best known such equation is perhaps the "moveout" equation directly relating time and velocity: (Available In Full Paper) The relation between frequency and velocity or frequency and amplitude is also direct but seldom used in data processing. However, any discussion of compressional wave theory must include frequency as a very basic parameter. Some existing seismic theory does relate velocity and frequency but actual measurement on real data is scant. It is proposed to consider their possible relationship in the context of geophysical theory and practical observation. VELOCITY DISPERSION One accepted theory, which directly relates frequency and velocity is dispersion. Residual attenuation of the seismic wavefront after distance and reflection factors are removed is proportional to frequency. The equation which governs this dependence of velocity on frequency according to O'Brien and Lucas, 1971, is: (Available In Full Paper) It is indicated by the equation that if the attenuation, Q, is known, the velocity at each frequency could be computed.

Thin (<20 m), sand injectites, too small to resolve in conventional seismic reflection data, can constitute a large part of the net-to-gross volume and affect fluid flow in the reservoir. However, they may also cause challenges for well placement and reservoir development because they are too small to be reliably imaged in seismic reflection data. It is therefore important to better understand how small-scale injectites influence seismic images, and how they may be recognized and characterized above reservoirs. The Grane Field (North Sea) hosts numerous small-scale sand injectites above the main reservoir unit, challengin well placement, volume estimates and seismic interpretation. Here, we investigate how such small-scale sand injectites influence seismic images and may be characterized by (1) using well, 3D seismic and outcrop data to investigate geometries of small-scale sand injectites (0–15 m thick), (2) performing seismic convolution modelling to investigate how these would be imaged in seismic data, and (3) comparing these synthetic seismic images with actual 3D seismic data from the well-investigated Grane Field. Our results show that despite injectites being below seismic resolution, small-scale sand injectites can be detected in seismic data. They are more likely to be detected if they have high thickness (>5 m), steep dip (>30°), and when densely spaced. Furthermore, as the fraction of sand injectites increases the top reservoir amplitude will decrease. Moreover, comparison of the synthetic seismic images with real seismic data from the Grane Field indicates that the low-amplitude anomalies and irregularities observed above the reservoir may be a result of the overlying sand injectites. Additionally, the comparison strongly suggests that the Grane Field hosts sand injectites that are thicker and located further away from the top reservoir than is indicated by well observations. These results may be used to improve well planning and develop reservoirs with overlying sand injectites. Supplementary material: A PDF file containing all the seismic modelling results allowing the reader to flip back and forth between the models is available at https://www.doi.org/10.6084/m9.figshare.14333102 and well logs from well 25/11-18T2 are available at https://factpages.npd.no/pbl/wellbore_documents/2358_25_1_18_COMPLETION_REPORT_AND_LOG.pdf