Signal enhancement and multiple suppression using Radon transform: an application to marine multichannel seismic data

It is well known that a complex near surface—encountered in areas such as desert, mountainous, and glacial till environments—can significantly distort primary reflections from deeper horizons of interest. This has been and remains a major problem in seismic data processing.

<p>In 2016, approximately 850 km of high-resolution multichannel seismic reflection data of the BALTEC survey have been acquired offshore Poland within the transition zone between the East European Craton and the Paleozoic Platform. Data processing, focused on removal of multiples, strongly overprinting geological information at shallower intervals, included SRME, TAU-P domain deconvolution, high resolution parabolic Radon demultiple and SWDM (Shallow Water De-Multiple). Entire dataset was Kirchhoff pre-stack time migrated. Additionally, legacy shallow high-resolution multichannel seismic reflection data acquired in this zone in 1997 was also used. All this data provided new information on various aspects of the Phanerozoic evolution of this area, including Late Cretaceous to Cenozoic tectonics and sedimentation. This phase of geological evolution could be until now hardly resolved by analysis of industry seismic data as, due to limited shallow seismic imaging and very strong overprint of multiples, essentially no information could have been retrieved from this data for first 200-300 m. Western part of the BALTEC dataset is located above the offshore segment of the Mid-Polish Swell (MPS) – large anticlinorium formed due to inversion of the axial part of the Polish Basin. BALTEC seismic data proved that Late Cretaceous inversion of the Koszalin – Chojnice fault zone located along the NE border of the MPS was thick-skinned in nature and was associated with substantial syn-inversion sedimentation. Subtle thickness variations and progressive unconformities imaged by BALTEC seismic data within the Upper Cretaceous succession in vicinity of the Kamień-Adler and the Trzebiatów fault zones located within the MPS documented complex interplay of Late Cretaceous basin inversion, erosion and re-deposition. Precambrian basement of the Eastern, cratonic part of the study area is overlain by Cambro-Silurian sedimentary cover. It is dissected by a system of steep, mostly reverse faults rooted in most cases in the deep basement. This fault system has been regarded so far as having been formed mostly in Paleozoic times, due to the Caledonian orogeny. As a consequence, Upper Cretaceous succession, locally present in this area, has been vaguely defined as a post-tectonic cover, locally onlapping uplifted Paleozoic blocks. New seismic data, because of its reliable imaging of the shallowest substratum, confirmed that at least some of these deeply-rooted faults were active as a reverse faults in latest Cretaceous – earliest Paleogene. Consequently, it can be unequivocally proved that large offshore blocks of Silurian and older rocks presently located directly beneath the Cenozoic veneer must have been at least partly covered by the Upper Cretaceous succession; then, they were uplifted during the widespread inversion that affected most of Europe. Ensuing regional erosion might have at least partly provided sediments that formed Upper Cretaceous progradational wedges recently imaged within the onshore Baltic Basin by high-end PolandSPAN regional seismic data. New seismic data imaged also Paleogene and younger post-inversion cover. All these results prove that Late Cretaceous tectonics substantially affected large areas located much farther towards the East than previously assumed.</p><p>This study was funded by the Polish National Science Centre (NCN) grant no UMO-2017/27/B/ST10/02316.</p>

The collection of a range of different seismic data types has greatly improved our understanding of the crustal architecture of Australia's Archaean Yilgarn Craton over the last few years. These seismic data include broadband seismic studies, seismic receiver functions, wide-angle recordings and mine-scale to deep seismic reflection transects. Each data set provides information on the three-dimensional (3D) tectonic model of the Yilgarn Craton from the craton scale through to the mine scale. This paper demonstrates that the integration and rationalisation of these different seismic data sets into a multi-scale 3D geological/seismic model, that can be visualised at once in a single software package, and incorporating all available data sets, significantly enhances this understanding. This enhanced understanding occurred because the integrated 3D model allowed easy and accurate comparison of one result against another, and facilitated the integrated questioning and interrogation across scales and seismic method. As a result, there are feedback questions regarding understanding of the individual seismic data sets themselves, as well as the Yilgarn Craton as a whole. The methodology used, including all the data sets in the model range, had to allow for the wide range of data sets, frequencies and seismic modes. At the craton scale, P-wave, S-wave and surface wave variations constrained the 3D lithospheric velocity model, revealing noticeable large-scale velocity variations within and across the craton. An interesting feature of the data, easily identified in 3D, is the presence of a fast S-wave velocity anomaly (> 4.8 km s − 1 ) within the upper mantle. This velocity anomaly dips east and has a series of step-down offsets that coincide approximately with province and terrane boundaries of the Yilgarn Craton. One-dimensional receiver function profiles show variations in their crustal velocity across the craton. These crustal velocity variations are consistent with the larger-scale geological subdivision of the craton, and provide characteristic profiles for provinces and terranes. The receiver function results and the deep seismic reflection data both agree on the depth to the Moho, and both indicate an increase in Moho depth to the east. The 2D seismic refraction results in the south-west of the craton provide crustal thickness information, an indication of middle and lower crustal compositions, and information regarding the broad-scale architectural framework. At the province- and terrane-scale, the deep seismic reflection data and the mine-scale seismic data provide geometric constraints on crustal architecture, in particular the orientation of the region's fault systems as well as variations in the thickness of the granite–greenstone succession. Integration of the results from wide-angle seismic refraction data coincident with the deep seismic reflection data provided additional constraints on likely upper crustal lithologies. The integrated 3D seismic model implies the dominant geodynamic process involved the development of an orogenic belt that developed with a series of contractional (folding and thrusting) events, separated by equally important extensional events. The seismic reflection data in particular suggests that extensional movement on many shear zones was more common than previously thought. The seismic reflection data suggest that the dominant mineral systems involved deeply sourced fluid flowing up crustal-penetrating shear zones. These deeply sourced fluids were further focussed into sites located above fault-breached domal regions in the upper crust.

The application of the seismic reflection method to detect stratigraphic changes away from well locations is beginning to gain acceptance among Reservoir Engineers. Unfortunately one of the limitations of this method is the inherent low resolution of seismic data as compared to well log data. Several approaches have been proposed to produce well log-like or pseudo log traces from seismic reflection data. Although there is no improvement in the resolution, the pseudo log traces provide a more convenient way of visually corelating well data to seismic data. A new stratigraphic extrapolation method designed to overcome some of the drawbacks of low resolution is presented. This method consists of relating a model trace (initially derived from well information) to an actual seismic trace by varying the parameters of the model trace within well defined constraints until best match is achieved between them. Extrapolation of the stratigraphy away from the well is performed from trace to trace, the starting model for each trace being determined either from the final model for the previous trace or from an independently postulated model. An interactive computer program is employed for this purpose which allows the incorporation of additional information to the initial model. In this way the final stratigraphic model of the reservoir is the one which best matches the seismic data. Several examples showing the application of the method will be discussed.

Seismic reflection data are used by geologists to identify the best site for oil and gas explorations. The raw seismic image cannot be directly used for explorations because the noises may hinder the primary reflections and result in misinterpretations. In the proposed research work, the denoising method with adaptive dictionary learning is attempted to attenuate the coherent and random noises which affect the seismic reflections. In this method, Karhunen Loeve Transform (KLT) is combined with K-means Singular Value Decomposition (KSVD) to improve the Signal to Noise Ratio (SNR) of the seismic data. The combination of fixed transform using KLT and learning-based dictionary using KSVD remove the redundant data while retaining the necessary data for further interpretations. KLT is applied on the whole seismic image to decorrelate the coefficients and retain the primary reflections. The horizontal events in the seismic image are preserved as they represent the eigen images with large energy. The KSVD is applied to the KLT resultant data, which denoises the patch of data while simultaneously updating the dictionary. The noise is eliminated using local sparsity of the image where mutually overlapping small image blocks are learned to yield the self-adaptive redundant dictionary. It is then used to obtain the sparse representation of the image blocks by eliminating noise. The algorithm is tested for both synthetic and field seismic images, and the results indicate a better reduction of random and coherent noise with the acceptable execution time compared to other denoising algorithms used. The KLT combined with KSVD method decorrelate the seismic data from noise by preserving the primary reflections and discarding the redundant noise.

Estimation of rock properties from seismic data is important for exploration and production activities in the petroleum industry. Considering the compressional velocity—the speed of propagating body waves in formations—and the quality factor (Q)—a measure of the frequency-selective energy losses of waves propagating through formations—both properties are usually estimated from multichannel seismic data. Velocity is estimated during multichannel processing of seismic reflection data in either the time or depth domain. In marine seismic acquisition, Q can be estimated from the following sources: Vertical Seismic Profile (VSP) surveys, where sources are located near the sea surface and geophones are distributed at depth along a borehole; and multichannel reflection data, where sources are also located near the sea surface and receivers are distributed either at the sea surface (conventional seismic survey with streamers) or on the sea floor (use of nodes or Ocean Bottom Cables (OBC)). The aforementioned acquisition devices, VSP, conventional streamers, nodes, and OBCs are much more expensive than single-channel acquisition with one receiver per shot due to the cost of operation. There are numerous old and new datasets from academia and the oil industry that have been acquired with single-channel acquisition devices. However, there is a paucity of work addressing the estimation of velocity and Q from this type of equipment. We investigate the estimation of Q and velocity from single-channel seismic data. Using the windowed discrete Fourier transform for a single seismic trace, we calculate the peak and dominant frequency that changes with time. In the geologic environment, higher frequencies are attenuated at shallow depths (time), while lower frequencies remain at deeper positions. From the rate at which higher frequencies are attenuated with time, we estimate the effective quality factor (Qeff). However, when using Kirchhoff migration to process single-channel seismic data, events far from the vertical projection of the receiver contribute to the trace at a given time. Then, an underestimation of the effective quality factor occurs. To compensate for the effects of more distant events with lower-frequency content contaminating the shorter events, we propose a linear equation to correct the effective quality factor estimated from migrated seismic data. Effective Q and its correction are estimated in five single-channel seismic lines surveyed along the Joetsu Knoll, a SW-NE anticline structure on the eastern margin of the Sea of Japan. These results are linked to geomorphological and geological features and the velocity field. Joetsu Knoll is a known site of massive gas hydrates (GH), which occur in the first hundred metres of Neogene sediments and, together with gas chimneys, play an important role in seismic wave absorption. Qeff estimated from migrated seismic data maintains the spatial relationship between high and low Q regions. The region of low Q, which is below 124 and has an average value of 57, occurs near the anticlinal hinge and tends to coincide with the region in which the Bottom Simulating Reflector (BSR) resides. The coexistence of GH and free gas coincides with the very low P velocity gradient of 0.225 s−1. BSR occurrence, Qeff and the geometry of the Joetsu anticline testify to progressive gas hydrate depletion northward along the dome.

High‐resolution reflection seismic and detailed gravity data were acquired across an exposure of the Wasatch fault, Utah, near a trench excavated for dating of Quaternary fault displacement. The seismic data across the Quaternary Wasatch fault are interpreted to show three subparallel surfaces dipping from 70°W at the surface to an estimated 45°W at 40 m, displaced unconsolidated sediments, and colluvial material abutting the main fault. Detailed gravity data were of assistance in mapping the sediment‐bedrock interface from the rangefront across the Wasatch Fault Zone. A combined high‐resolution seismic and gravity interpretation reveals that bedrock is 80 m deeper in the hanging wall than in the footwall, suggesting that displacement has occurred on several en echelon blocks in the near‐surface of the Wasatch fault. Movement on the most recent Wasatch fault trace began prior to deposition of Pleistocene lacustrine sediments. The twelvefold, high‐resolution reflection seismic data were recorded and processed to achieve vertical resolution of approximately 1 m and horizontal resolution (Fresnel zone radii) of as good as 5 m on the deepest reflecting interfaces at 40 m. Reasonably high frequencies and good bandwidth (about 80–300 Hz) in the stacked seismic data permitted a direct comparison to the trenched cross section. Good correlation between the trench stratigraphy and structure and the seismic data suggests high‐resolution seismic data can be a valuable tool for analyzing near‐surface faulting in unconsolidated sediment and for locating potential trench sites.

Numerical 3D high-resolution models of subsurface petroelastic properties are key tools for exploration and production stages. Stochastic seismic inversion techniques are often used to infer the spatial distribution of the properties of interest by integrating simultaneously seismic reflection and well-log data also allowing accessing the spatial uncertainty of the retrieved models. In frontier exploration areas, the available data set is often composed exclusively of seismic reflection data due to the lack of drilled wells and are therefore of high uncertainty. In these cases, subsurface models are usually retrieved by deterministic seismic inversion methodologies based exclusively on the existing seismic reflection data and an a priori elastic model. The resulting models are smooth representations of the real complex geology and do not allow assessing the uncertainty. To overcome these limitations, we have developed a geostatistical framework that allows inverting seismic reflection data without the need of experimental data (i.e., well-log data) within the inversion area. This iterative geostatistical seismic inversion methodology simultaneously integrates the available seismic reflection data and information from geologic analogs (nearby wells and/or analog fields) allowing retrieving acoustic impedance models. The model parameter space is perturbed by a stochastic sequential simulation methodology that handles the nonstationary probability distribution function. Convergence from iteration to iteration is ensured by a genetic algorithm driven by the trace-by-trace mismatch between real and synthetic seismic reflection data. The method was successfully applied to a frontier basin offshore southwest Europe, where no well has been drilled yet. Geologic information about the expected impedance distribution was retrieved from nearby wells and integrated within the inversion procedure. The resulting acoustic impedance models are geologically consistent with the available information and data, and the match between the inverted and the real seismic data ranges from 85% to 90% in some regions.

Over the last project six months, our project activities have concentrated on three areas: (1) performing a stochastic inversion of pattern 16 seismic data to deduce reservoir permeability, (2) development of the geochemical inversion strategy and implementation of associated software, and (3) completing the software implementation of TProGS and the geostatistical analysis that provides the information needed when using the software to produce realizations of the Midale reservoir. The report partially the following deliverables: D2: Model development: MCMC tool (synthetic fluid chemistry data); deliverable completed. D4: Model development/verification: MCMC tool (TProGS, field seismic/chemistry data) work product; deliverable requirements partially fulfilled. D5: Field-based single-pattern simulations work product; deliverable requirements partially fulfilled. When completed, our completed stochastic inversion tool will explicitly integrate reactive transport modeling, facies-based geostatistical methods, and a novel stochastic inversion technique to optimize agreement between observed and predicted storage performance. Such optimization will be accomplished through stepwise refinement of: (1) the reservoir model - principally its permeability magnitude and heterogeneity - and (2) geochemical parameters - primarily key mineral volume fractions and kinetic data. We anticipate that these refinements will facilitate significantly improved history matching and forward modeling of CO{sub 2} storage. Our tool uses the Markov Chain Monte Carlo (MCMC) methodology. Deliverable D1, previously submitted as a report titled ''Development of a Stochastic Inversion Tool To Optimize Agreement Between The Observed And Predicted Seismic Response To CO{sub 2} Injection/Migration in the Weyburn-Midale Project'' (Ramirez et al., 2009), described the stochastic inversion approach that will identify reservoir models that optimize agreement between the observed and predicted seismic response. The software that implements this approach has been completed, tested, and used to process seismic data from pattern 16. A previously submitted report titled ''Model verification: synthetic single pattern simulations using seismic reflection data'', Ramirez et al. 2010, partially fulfilled deliverable D3 by summarizing verification activities that evaluate the performance of the seismic software and its ability to recover reservoir model permeabilities using synthetic seismic reflection data. A future progress report will similarly describe summarizing verification activities of the geochemical inversion software, thereby completing deliverable D3. This document includes a chapter that shows and discusses permeability models produced by seismic inversion that used seismic data from pattern 16 in Phase 1A. It partially fulfills deliverable D5: Field-based single-pattern simulations work product. The D5 work product is supposed to summarize the results of applying NUFT/MCMC to refine the reservoir model and geochemical parameters by optimizing observation/prediction agreement for the seismic/geochemical response to CO{sub 2} injection/migration within a single pattern of Phase 1A/1B. A future progress report will show inversion results for the same pattern using geochemical data, thereby completing deliverable D5. This document also contains a chapter that fulfills deliverable D2: Model development: MCMC tool (synthetic fluid chemistry data). The chapter will summarize model development activities required to facilitate application of NUFT/MCMC to optimize agreement between the observed and predicted geochemical response to CO{sub 2} injection/migration. Lastly, this document also contains a chapter that partially fulfills deliverable D4: Model development/verification: MCMC tool (TProGS, field seismic/chemistry data) work product. This work product is supposed to summarize model development activities required for (1) application of TProGS to Weyburn, (2) use of TProGS within the MCMC tool, and (3) application of the MCMC tool to address field seismic and geochemical data. The chapter included here fulfills requirements 1 and 2. Requirement 3 will be addressed in a future progress report.

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

Seismic data interpolation and denoising play vital roles in obtaining complete and clean data in seismic data processing. Seismic data usually misses along various spatial axes and always mix with random noise. In order to obtain complete and clean seismic data, reconstruction technology can interpolate missing data and attenuate random noise. Nonsubsampled contourlet transform is an effective transform to obtain multi-scale and multi-direction sparse domain data for compression sensing interpolation and denoising. However, conventional iterative shrinkage/thresholding cannot handle ill-posed and ill-conditioned equations for solving linear inverse problem. We present a two-step iterative log thresholding method to overcome ill-posed and ill-conditioned problems and improve the convergence rate and solution accuracy, which can interpolate and denoise seismic data simultaneously in the nonsubsampled contourlet transform framework. First, we use nonsubsampled contourlet transform to convert the seismic missing data with random noise to sparse domain. Then, we apply two-step iterative log thresholding algorithm to interpolate and denoise data in sparse domain. The result of each iteration is based on the results of the previous two iterations, which can accelerate convergence rate. In addition, log thresholding can further improve convergence rate and solution accuracy. Finally, we use inverse nonsubsampled contourlet transform to obtain the interpolated and denoised seismic data. The new method can reconstruct the irregularly missing data and attenuate random noise to obtain complete and clean seismic data with high accuracy, which is crucial for seismic imaging and inversion. We demonstrate the applicability and effectiveness of this simultaneous interpolation and denoising technique with successful applications to both synthetic and field data examples.

A mean-based filter to remove power line harmonic noise from seismic reflection data

Recent interest in the Karoo basin of South Africa has been sparked by the possibility of extensive shale gas reserves. Here we present an integrated study of historical reflection and refraction seismic (industry and academic), borehole, MT and regional gravity and magnetic data, with the goal of evaluating the shale gas potential. The reflection seismic data, constrained by 5 deep boreholes and MT data are used to map the contact between the base of the Karoo (Dwyka Group) and the underlying basement. This provides an important constraint on the thickness of the Karoo Supergroup (~5.5 km). By constraining the gravity data with the structure known from the reflection seismic and density data from boreholes, this contact can be extended to regions where the seismic data are sparse and suggests that the basin in the region near 24° longitude is thinner than on either side. The flexure of the basin also suggests that at the time of deposition, the Kaapvaal Craton was stiff, preventing a deep basin from developing further northwards on-craton. Additionally, the magnetic and borehole data highlight pervasive Jurassic dolerite sills and dykes. These sills and dykes can be highly fractured at surface, but at depth are possibly impermeable, providing seals and traps. They are also an important source of heat and need to be accounted for when evaluating the gas potential. The borehole data indicate sills can occur at any depth throughout the basin. The near surface sills are easily mapped with the coarse national magnetic data and single flight line modeling suggests that the edges of deeper sills can be delineated with higher resolution magnetic data. This approach indicates the importance of integrated studies to evaluating the shale gas potential in the Karoo.

Seismic data offer valuable spatial information that contributes to the development strategy, such as drilling decisions and well planning. Inverting 3D seismic reflectivity data to impedance unlocks the potential of using seismic data to estimate the lateral variability and to predict reservoir geomechanical behaviour. The geomechanical model contributes for the evaluation of wellbore stability, frackability and drilling direction. The objective of this work is to illustrate the use of seismic derived models for reservoir and geomechanical properties, such as total porosity, total organic carbon (TOC) and rock rigidity. These properties are instrumental to characterize tight reservoirs and useful tools for defining a horizontal well trajectory.The study area has an exploration potential of unconventional reservoirs, targeting tight carbonates from Upper Jurassic. To date, only one well has been drilled in the area of the interest and high quality 3D seismic data is available. The process consists of conducting seismic inversion, using the well and the 3D PSTM seismic data, and resulting in the generation of 3D subsurface impedance model. The well-log relationships between impedance and reservoir quality (effective porosity, source richness) and completion quality (brittleness) were determined and showed high correlation. Hence, 3D rock quality and geomechanical volumes were derived to characterize the behaviour of the reservoir target.Seismic derived properties models yield a better description of the reservoir heterogeneity than using seismic reflectivity data only. The horizontal well trajectory was planned taking into account the observed and significant lateral variability revealed by the 3D models estimated based on seismic inverted data.The results obtained using this methodology demonstrate the importance of integrating geophysical characterisation as a relevant supporting factor in the drilling decision making process. In particular, it validates the use of seismic derived reservoir and completion quality models as an additional tool in the definition of a horizontal well trajectory in a tight/unconventional deep gas target.

Accurate subsurface modeling and characterization require the prediction of facies and rock properties within the reservoir model. This is commonly achieved by inverting geophysical data, such as seismic reflection data, using a two-step approach either in the discrete or the continuous domain. We have adopted an iterative simultaneous method, namely, stochastic perturbation optimization, to invert seismic reflection data jointly for facies and rock properties. Facies first are simulated according to a Markov chain model, and then rock properties are generated with stochastic sequential simulation and cosimulation conditioned to each facies. Elastic and seismic data are computed by applying a rock-physics model to the realizations of petrophysical properties and a seismic convolutional model. The similarity between observed and synthetic seismic data is used to update the solution by perturbing facies and rock properties until convergence. Coupling the discrete and continuous domains ensures a consistent perturbation of the reservoir models throughout the iterations. We have evaluated the method in a 1D synthetic example for the estimation of facies and porosity from zero-offset seismic data assuming a linear rock-physics model to demonstrate the validity of the method. Then, we apply the method to a real 3D data set from the North Sea for the joint estimation of facies and petrophysical properties from prestack seismic data. The results show spatially consistent rock and fluid inverted models in which the predicted facies reproduce the vertical ordering as observed in the well data.