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1
Ha, Thang N., Kurt J. Marfurt, Bradley C. Wallet, and Bryce Hutchinson. "Pitfalls and implementation of data conditioning, attribute analysis, and self-organizing maps to 2D data: Application to the Exmouth Plateau, North Carnarvon Basin, Australia." Interpretation 7, no. 3 (August 1, 2019): SG23—SG42. http://dx.doi.org/10.1190/int-2018-0248.1.
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Recent developments in attribute analysis and machine learning have significantly enhanced interpretation workflows of 3D seismic surveys. Nevertheless, even in 2018, many sedimentary basins are only covered by grids of 2D seismic lines. These 2D surveys are suitable for regional feature mapping and often identify targets in areas not covered by 3D surveys. With continuing pressure to cut costs in the hydrocarbon industry, it is crucial to extract as much information as possible from these 2D surveys. Unfortunately, much if not most modern interpretation software packages are designed to work exclusively with 3D data. To determine if we can apply 3D volumetric interpretation workflows to grids of 2D seismic lines, we have applied data conditioning, attribute analysis, and a machine-learning technique called self-organizing maps to the 2D data acquired over the Exmouth Plateau, North Carnarvon Basin, Australia. We find that these workflows allow us to significantly improve image quality, interpret regional geologic features, identify local anomalies, and perform seismic facies analysis. However, these workflows are not without pitfalls. We need to be careful in choosing the order of filters in the data conditioning workflow and be aware of reflector misties at line intersections. Vector data, such as reflector convergence, need to be extracted and then mapped component-by-component before combining the results. We are also unable to perform attribute extraction along a surface or geobody extraction for 2D data in our commercial interpretation software package. To address this issue, we devise a point-by-point attribute extraction workaround to overcome the incompatibility between 3D interpretation workflow and 2D data.
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White, D. J., and M. Malinowski. "Interpretation of 2D seismic profiles in complex geological terrains: Examples from the Flin Flon mining camp, Canada." GEOPHYSICS 77, no. 5 (September 1, 2012): WC37—WC46. http://dx.doi.org/10.1190/geo2011-0478.1.
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A methodology was demonstrated for the 3D interpretation of networks of 2D seismic profiles in conjunction with other 3D geological constraints. The methodology employs 3D migration of 2D seismic data as a means of directly correlating reflections with out-of-plane geology, followed by ray-trace modeling of interpreted 3D geological surfaces. The proposed interpretation workflow was demonstrated with examples taken from 2D seismic profiles that were recently acquired for VMS ore exploration within the Flin Flon mining camp, Canada. In each example, the utility of the method was demonstrated and the resulting inferences were validated by comparison with a true 3D seismic survey acquired over a subset of the same area.
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Evans, B. J., B. F. Oke, M. Urosevic, and K. Chakraborty. "A COMPARISON OF PHYSICAL MODEL WITH FIELD DATA OVER OLIVER FIELD, VULCAN GRABEN." APPEA Journal 35, no. 1 (1995): 26. http://dx.doi.org/10.1071/aj94002.
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Physical models representing the three dimensional geology of oil fields can be built from materials such as plastics and resins. Using ultrasound transmitters and receivers, 2D and 3D seismic surveys can be simulated to aid in the survey design of field work, provide insight into data processing, and can test interpretation concepts. Such modelling simulates most aspects of both land and marine seismic.In 1993 BHP Petroleum, on behalf of the AC/P6 Joint Venture, contracted Curtin University's Geophysics Group to build a 1:40,000 scale, 11-layer, 2.5D model of the Oliver Field so that 2D and 3D field data acquisition and processing could be simulated. A 2.5D model is invariant in the strike direction, but can answer most of the questions of a true 3D model at a fraction of the effort and cost. This was the first such model built in Australia, and one of the most complex physical models ever built.Of interest was the quality of imaging under the fault shadow near reservoir level, and whether the application of dip or strike 3D acquisition and processing approaches could improve the seismic data quality. Consequently, both dip (2D) and strike (2.5D) seismic data were acquired over the model using similar parameters to those used in conventional offshore acquisition. The data were processed to migration stage and compared with the field seismic data. Numerical model and field VSP data were also processed and compared with the field and physical model seismic data.The good agreement between processed physical model seismic and field seismic shows that physical modelling of geology has application in both two and three dimensional interpretation, acquisition planning, and processing testing and optimisation.This physical model experiment proved conclusively that shallow faults with a relatively large velocity contrast across them cause 'back' faults on the seismic data which do not exist in reality. Furthermore, this experiment proved for the first time using a physical model that strike 3D marine recording is preferable to dip 3D marine recording.
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Wrona, Thilo, Indranil Pan, Rebecca E. Bell, Robert L. Gawthorpe, Haakon Fossen, and Sascha Brune. "3D seismic interpretation with deep learning: A brief introduction." Leading Edge 40, no. 7 (July 2021): 524–32. http://dx.doi.org/10.1190/tle40070524.1.
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Understanding the internal structure of our planet is a fundamental goal of the earth sciences. As direct observations are restricted to surface outcrops and borehole cores, we rely on geophysical data to study the earth's interior. In particular, seismic reflection data showing acoustic images of the subsurface provide us with critical insights into sedimentary, tectonic, and magmatic systems. However, interpretations of these large 2D grids or 3D seismic volumes are time-consuming, even for a well-trained person or team. Here, we demonstrate how to automate and accelerate the analysis of these increasingly large seismic data sets with machine learning. We are able to perform typical seismic interpretation tasks such as mapping tectonic faults, salt bodies, and sedimentary horizons at high accuracy using deep convolutional neural networks. We share our workflows and scripts, encouraging users to apply our methods to similar problems. Our methodology is generic and flexible, allowing an easy adaptation without major changes. Once trained, these models can analyze large volumes of data within seconds, opening a new pathway to study the processes shaping the internal structure of our planet.
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Notiyal, Subodh, and Victoria Seesaha. "Creating a 3D image from 2D data using structurally conformable interpolation: a case study from the Beagle Sub-basin, NSW, Australia." APPEA Journal 60, no. 1 (2020): 326. http://dx.doi.org/10.1071/aj19175.
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2D seismic data still provides key information for companies evaluating new permits on offer or entering new basins. However, working on multi-vintage 2D data can be time-consuming for several reasons, including getting correct navigation, variability of physical parameters like amplitude, time and phase between different vintages, and then interpreting the 2D data itself, which often results in gridding artefacts. In a step change to the use of traditional 2D data, TGS has developed a methodology called ‘structurally conformable interpolation’ – also known as 2Dcubed. It is created using input data from available 2D migrated stacks and velocities from available vintages. The workflow includes survey matching of different vintages, data-driven geological model building to interpolate large distances between existing data, and a 3D post-stack migration to minimise the 2D migration artefacts. The merging of these datasets successfully creates a 3D migrated image from legacy 2D data, offering better structure and continuity while increasing confidence in its interpretation. Interpretation of a 3D volume is much more efficient than when using 2D data and is free from 2D artefacts. With this methodology TGS has completed a project covering a 40000km2 area in the Beagle Sub-basin, north-west Western Australia, using existing 2D data from over 42 different vintages. The resulting output ‘Beagle Cube’ interpolated 3D volume has been interpreted for major regional trends and structures. The results are very consistent with the original 2D data, but with better definition of major structures. Another study comparing the interpretation between the interpolated 3D volume and the real open-file 3D shows excellent preservation of the structural picture within the interpolated 3D volume, not at the same level as real 3D, but it gives greater confidence in the regional interpretation conducted within areas that do not have 3D coverage. This paper will address how the interpolation methodology works stage by stage, the results of the final product and how it assists in performing regional interpretation in a quick timeframe.
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Cox, David R., Paul C. Knutz, D. Calvin Campbell, John R. Hopper, Andrew M. W. Newton, Mads Huuse, and Karsten Gohl. "Geohazard detection using 3D seismic data to enhance offshore scientific drilling site selection." Scientific Drilling 28 (December 1, 2020): 1–27. http://dx.doi.org/10.5194/sd-28-1-2020.
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Abstract. A geohazard assessment workflow is presented that maximizes the use of 3D seismic reflection data to improve the safety and success of offshore scientific drilling. This workflow has been implemented for International Ocean Discovery Program (IODP) Proposal 909 that aims to core seven sites with targets between 300 and 1000 m below seabed across the north-western Greenland continental shelf. This glaciated margin is a frontier petroleum province containing potential drilling hazards that must be avoided during drilling. Modern seismic interpretation techniques are used to identify, map and spatially analyse seismic features that may represent subsurface drilling hazards, such as seabed structures, faults, fluids and challenging lithologies. These hazards are compared against the spatial distribution of stratigraphic targets to guide site selection and minimize risk. The 3D seismic geohazard assessment specifically advanced the proposal by providing a more detailed and spatially extensive understanding of hazard distribution that was used to confidently select eight new site locations, abandon four others and fine-tune sites originally selected using 2D seismic data. Had several of the more challenging areas targeted by this proposal only been covered by 2D seismic data, it is likely that they would have been abandoned, restricting access to stratigraphic targets. The results informed the targeted location of an ultra-high-resolution 2D seismic survey by minimizing acquisition in unnecessary areas, saving valuable resources. With future IODP missions targeting similarly challenging frontier environments where 3D seismic data are available, this workflow provides a template for geohazard assessments that will enhance the success of future scientific drilling.
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Herron, Donald A., and Timothy E. Smith. "Practical aspects of working with 2D migrated seismic data." Interpretation 7, no. 3 (August 1, 2019): SG1—SG9. http://dx.doi.org/10.1190/int-2018-0189.1.
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Despite the ever-increasing use of 3D seismic data in today’s exploration and production activities, 2D seismic data continue to play an important role in the oil and gas industry. Interpretations of 2D regional and megaregional surveys are essential elements of integrated exploration programs, establishing frameworks for basin analysis, structural synthesis, and play fairway identification and mapping. When correlating and mapping horizons on 2D migrated seismic data, interpreters use certain practical techniques for handling structural misties, which are caused by the fundamental limitation of 2D migration to account for out-of-plane components of dip.
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Adetokunbo, Peter, Abdullatif A. Al-Shuhail, and Saleh Al-Dossary. "3D seismic edge detection using magic squares and cubes." Interpretation 4, no. 3 (August 1, 2016): T271—T280. http://dx.doi.org/10.1190/int-2015-0091.1.
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Edge detection is a category of geometric seismic attributes that has the capability to delineate vital information from seismic reflection data that can be used to aid qualitative and quantitative interpretation. We have evaluated a new method for geologic interpretation based on templates derived from magic squares and cubes. These are discrete differential operators that approximately calculate the spatial derivative of seismic amplitude through 2D and 3D convolution to locate edges and/or geologic features in seismic data. The new operator benefits from multidirectional scanning leading to efficient detection of different edge locations and their respective orientations. We have tested the new operators against the commonly used Sobel filter using two 3D seismic data volumes. Results of the [Formula: see text] magic cube operators provided better definition of seismic features than the [Formula: see text] magic cube operators. The overall results compared favorably with the Sobel operator, which suggests that the method can serve as a complementary tool to other existing seismic attributes.
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Gao, Dengliang. "Volume texture extraction for 3D seismic visualization and interpretation." GEOPHYSICS 68, no. 4 (July 2003): 1294–302. http://dx.doi.org/10.1190/1.1598122.
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Visual inspection of poststack seismic image patterns is effective in recognizing large‐scale seismic features; however, it is not effective in extracting quantitative information to visualize, detect, and map seismic features in an automatic and objective manner. Although conventional seismic attributes have significantly enhanced interpreters' ability to quantify seismic visualization and interpretation, very few attributes are published to characterize both intratrace and intertrace relationships of amplitudes from a three‐dimensional (3D) perspective. These relationships are fundamental to the characterization and identification of certain geological features. Here, I present a volume texture extraction method to overcome these limitations. In a two‐dimensional (2D) image domain where data samples are visualized by pixels (picture elements), a texture has been typically characterized based on a planar texel (textural element) using a gray level co‐occurrence matrix. I extend the concepts to a 3D seismic domain, where reflection amplitudes are visualized by voxels (volume picture elements). By evaluating a voxel co‐occurrence matrix (VCM) based on a cubic texel at each of the voxel locations, the algorithm extracts a plurality of volume textural attributes that are difficult to obtain using conventional seismic attribute extraction algorithms. Case studies indicate that the VCM texture extraction method helps visualize and detect major structural and stratigraphic features that are fundamental to robust seismic interpretation and successful hydrocarbon exploration.
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Infante-Paez, Lennon, and Kurt J. Marfurt. "In-context interpretation: Avoiding pitfalls in misidentification of igneous bodies in seismic data." Interpretation 6, no. 4 (November 1, 2018): SL29—SL42. http://dx.doi.org/10.1190/int-2018-0076.1.
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In the past few decades, many exploration wells have been drilled into igneous rocks because of their similar seismic expressions to common exploration targets, such as carbonate mounds, sheet sands, and sand-prone sinuous channels. In cases in which interpreters cannot clearly delineate sedimentary features such as channels or fans, the interpretation may be driven primarily by bright spot anomalies, in which a poor understanding of the wavelet polarity may lead to an erroneous interpretation. Although many wells drilled into igneous rocks are based on the interpretation of 2D seismic data, misinterpretation still occurs today using high-quality 3D seismic data. To address this challenge, we analyze the seismic expression of andesitic volcanoes in the Taranaki Basin, New Zealand and use it to help understand misinterpreted igneous bodies in different parts of the world. Then, we develop an in-context interpretation workflow in which the seismic interpreter looks for key clues above, below, and around the target of interest that may alert the interpreter to the presence of igneous rocks.
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Le Magoarou, Camille, Katja Hirsch, Clement Fleury, Remy Martin, Johana Ramirez-Bernal, and Philip Ball. "Integration of gravity, magnetic, and seismic data for subsalt modeling in the Northern Red Sea." Interpretation 9, no. 2 (April 21, 2021): T507—T521. http://dx.doi.org/10.1190/int-2019-0232.1.
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Rifts and rifted passive margins are often associated with thick evaporite layers, which challenge seismic reflection imaging in the subsalt domain. This makes understanding the basin evolution and crustal architecture difficult. An integrative, multidisciplinary workflow has been developed using the exploration well, gravity and magnetics data, together with seismic reflection and refraction data sets to build a comprehensive 3D subsurface model of the Egyptian Red Sea. Using a 2D iterative workflow first, we have constructed cross sections using the available well penetrations and seismic refraction data as preliminary constraints. The 2D forward model uses regional gravity and magnetic data to investigate the regional crustal structure. The final models are refined using enhanced gravity and magnetic data and geologic interpretations. This process reduces uncertainties in basement interpretation and magmatic body identification. Euler depth estimates are used to point out the edges of high-susceptibility bodies. We achieved further refinement by initiating a 3D gravity inversion. The resultant 3D gravity model increases precision in crustal geometries and lateral density variations within the crust and the presalt sediments. Along the Egyptian margin, where data inputs are more robust, basement lows are observed and interpreted as basins. Basement lows correspond with thin crust ([Formula: see text]), indicating that the evolution of these basins is closely related to the thinning or necking process. In fact, the Egyptian Northern Red Sea is typified by dramatic crustal thinning or necking that is occurring over very short distances of approximately 30 km, very proximal to the present-day coastline. The integrated 2D and 3D modeling reveals the presence of high-density magnetic bodies that are located along the margin. The location of the present-day Zabargad transform fault zone is very well delineated in the computed crustal thickness maps, suggesting that it is associated with thin crust and shallow mantle.
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Admasu, Fitsum, Stefan Back, and Klaus Toennies. "Autotracking of faults on 3D seismic data." GEOPHYSICS 71, no. 6 (November 2006): A49—A53. http://dx.doi.org/10.1190/1.2358399.
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Manual fault mapping in 3D seismic interpretation is labor-intensive and time-consuming. Complex fault geometries and the distortion of the seismic signal close to faults complicate full automation of the fault-mapping process. We present a semiautomatic fault-tracking method for 3D seismic data that consists of fault highlighting followed by model-based fault tracking. Fault highlighting uses log-Gabor filters for emphasizing oriented amplitude discontinuities at faults in the presence of noise. Subsequent fault tracking fits an active contour to the highlighted fault voxels. The active contour searches for a connected, smooth curve which fits the data and disambiguates misleading or missing information. The fault tracker requires the interpreter to place the active contour close to a fault on one initial seismic inline (2D pick). The active contour deforms to the closest amplitude dis-continuity highlighted. This tracking result is then projected forward to the next inline, providing an initial fault pick on this section that is again optimized by the active contour. Tracking results on a series of successive seismic sections, finally, constitute a 3D fault surface. User interaction is solely required for an approximate fault pick on the first inline, and in cases where the fault line is lost due to insufficient signal. Use of the autotracker prototype provides a fast solution for the mapping of complete 3D fault surfaces of constant dip, and for the automated tracking of fault portions within distinct dip domains, if fault surfaces are curved (i.e., listric). The method was applied to a series of high-quality reflectivity sections extracted from a 3D seismic volume from shallow-offshore Nigeria, with the tracking results (generated within seconds) comparing well with manually interpreted fault surfaces.
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Zhang, Chao, and Mirko van der Baan. "A denoising framework for microseismic and reflection seismic data based on block matching." GEOPHYSICS 83, no. 5 (September 1, 2018): V283—V292. http://dx.doi.org/10.1190/geo2017-0782.1.
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Microseismic and seismic data with a low signal-to-noise ratio affect the accuracy and reliability of processing results and their subsequent interpretation. Thus, denoising is of great importance. We have developed an effective denoising framework for surface (micro)-seismic data using block matching. The novel idea of the proposed framework is to enhance coherent features by grouping similar 2D data blocks into 3D data arrays. The high similarities in the 3D data arrays benefit any filtering strategy suitable for multidimensional noise suppression. We test the performance of this framework on synthetic and field data with different noise levels. The results demonstrate that the block-matching-based framework achieves state-of-the-art denoising performance in terms of incoherent-noise attenuation and signal preservation.
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Maerten, Frantz, and Laurent Maerten. "On a method for reducing interpretation uncertainty of poorly imaged seismic horizons and faults using geomechanically based restoration technique." Interpretation 3, no. 4 (November 1, 2015): SAA105—SAA116. http://dx.doi.org/10.1190/int-2015-0009.1.
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To reduce exploration risk and optimize production in structurally complex areas, the geologic interpretation must be based on sound geomechanical principles. Despite advances in 3D seismic acquisition and processing techniques as well as in the availability of computationally robust interpretation software, the challenge associated with interpreting complex structures from seismic reflection data is that highly deformed areas surrounding faults, folds, and salt surfaces are often poorly imaged and therefore their interpretation is highly uncertain. We have developed a methodology that should help geophysicists quickly check the strengths and weaknesses of their interpretation and to automatically reduce the uncertainty in a faulted horizon geometry. Our workflow consisted of restoring interpreted seismic horizons and relating the concentrations of computed deformation attributes to areas of interpretation uncertainty. We used the technique based on an iterative finite-element formulation that allowed unfolding and unfaulting of 3D horizons using physical elastic behavior. A fast algorithm has been developed to automatically correct the interpreted structures in zones that exhibited anomalous deformation concentrations after restoration. This approach is able to mechanically check and reduce uncertainty in a faulted seismic horizon interpretation. Its application to synthetic and reservoir data has a high degree of reliability in the characterization of structurally complex reservoirs. This technique is also applicable to 2D models (geologic cross sections) and 3D models (volume).
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Trinchero, Eduardo, Luis Vernengo, and Marcelo Roizman. "3D seismic processing and interpretation from 2D seismic data: Application in environmentally sensitive areas of the Neuquén Basin, Argentina." Leading Edge 33, no. 7 (July 2014): 714–20. http://dx.doi.org/10.1190/tle33070714.1.
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Linde, Niklas, and Laust B. Pedersen. "Characterization of a fractured granite using radio magnetotelluric (RMT) data." GEOPHYSICS 69, no. 5 (September 2004): 1155–65. http://dx.doi.org/10.1190/1.1801933.
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We applied tensor radio magnetotellurics (RMT) in the 10–250 kHz frequency range to study major fracture zones on Ävrö, a small island (1.6 × 1.2 km2) in southeastern Sweden with bedrock dominated by highly resistive granite. The interpretation of a 950‐m RMT profile was facilitated by seismic reflection and borehole data but was complicated (1) by possible 3D effects of the surrounding sea and (2) because the quasi‐static assumption is violated. Inversions based on the quasi‐static assumption give severely distorted models in this type of environment. Inversion codes that include displacement currents are restricted to 1D structures. Therefore, 2D inversions were applied to lower frequencies only. The central part of the inverted profile showed a 30–40‐m‐thick weathered layer over an almost intact bedrock down to a depth of at least 200 m, where higher salinity and/or fracturing yielded higher conductivities. The first 200 m of the profile revealed a major fracture zone, which coincided with a seismic reflector. We used 3D forward modeling to understand the sea effect and to model the conductor in three dimensions. We believe that 3D forward modeling is a highly valuable tool to distinguish known 3D effects (i.e., the sea) from regional 2D features of interest. We suggest that water flow at Ävrö is dominated by a few major fracture zones.
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Saraswat, Puneet, Vijay Raj, Mrinal K. Sen, and Arun Narayanan. "Multiattribute Seismic Analysis With Fractal Dimension and 2D and 3D Continuous Wavelet Transform." SPE Reservoir Evaluation & Engineering 17, no. 04 (June 10, 2014): 436–43. http://dx.doi.org/10.2118/164417-pa.
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Summary The 3D post-stack seismic attributes provide an intuitive and effective way of using seismic volumes for reservoir characterization and development, and further identification of exploration targets. Some of the seismic attributes can aid in the precise prediction of the geometry and heterogeneity of subsurface geological settings. These also can provide useful information on petrophysical and lithological properties when combined with well-log information. There exist numerous seismic attributes that provide a unique interpretation on some aspects of subsurface geology. Of these, the proper demarcation of structural features— such as location and edges of faults and salt domes, and their throw and extent—always has been of primary concern. In this paper, we propose new multiattribute seismic algorithms by using fractal dimension and 2D/3D continuous wavelet transform (CWT). The use of higher-dimensional wavelets incorporates information from the ensemble of traces and can correlate information between neighboring traces in seismic data. The spectral decomposition that is based on the CWT aids in resolving various features of geological interest at a particular scale or frequency, which, when rendered with fractal attribute, demarcates the boundaries between those. We apply these two algorithms separately to a seismic amplitude volume and co-render output volumes together with some weights to yield a final attribute volume incorporating information from the aforementioned algorithms. We demonstrate the efficacy of these two algorithms in terms of the resolution and proper demarcation of various geological structures on real seismic data. The application of these algorithms results in better illumination and proper demarcation of various geological features such as salt domes, channels, and faults, and it illustrates how these simple tools can help to extract detailed information from seismic data.
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Bishop, Daniel, Megan Halbert, Katherine Welbourn, Ben Boterhoven, Stacey Mansfield, Sophia Gerth, and Arief Maulana. "Mesozoic tectonostratigraphic evolution of the North Carnarvon Basin unlocked using regional 3D seismic." APPEA Journal 56, no. 2 (2016): 564. http://dx.doi.org/10.1071/aj15070.
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Interpretation of regional scale merged 3D seismic data sets covering the North Carnarvon Basin has for the first time enabled a detailed description of Mesozoic stratigraphic and structural features on a basin scale. Isoproportional slicing of the data enables direct interpretation of Triassic depositional environments, including contrasting low-stand and high-stand fluvial channel complexes, marginal marine clastic systems and reef complexes. Channels vary dramatically between sinuous-straight single channels within low net:gross floodplain successions, to broad channel belts within relatively high net:gross fluvial successions. The latter can be traced from the inboard part of the basin to the outer areas of the Exmouth Plateau. 3D visualisation and interpretation has demonstrated the huge variety of structural styles that are present, including basement-involved extensional faults, detached listric fault complexes, polygonal faults, and regional scale vertical strike-slip faults with flower structures. Fault trends include north–south, north–northeast to south–southwest, and northeast–southwest, with deformation events occurring mainly between the Rhaetian and Valanginian. Extensional and compressional deformation has created multiple horsts, three-way fault closures, fold belts and associated four-way anticlinal traps. Wrench tectonics may also explain pock-mark trains with the interpreted transfer of over-pressure from Triassic to Early Cretaceous levels. The use of regional scale merged 3D seismic data sets is now shedding light on tectonostratigraphic features on a basin scale that were previously unrecognised or enigmatic on 2D seismic or local 3D seismic data sets.
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Qayyum, Farrukh, Christian Betzler, and Octavian Catuneanu. "Space-time continuum in seismic stratigraphy: Principles and norms." Interpretation 6, no. 1 (February 1, 2018): T97—T108. http://dx.doi.org/10.1190/int-2017-0061.1.
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Seismic stratigraphy is not only a geometric understanding of a stratigraphic succession, but it also has a close link to the space-time continuum started by H. E. Wheeler (1907–1987). The science follows the fundamental principles of stratigraphy, and the norms that govern seismic interpretation play a fundamental role due to their practical significance. The birth of computer-aided algorithms paved a new platform for seismic interpretation. The ideas from A. W. Grabau (1870–1946) and Wheeler were brought to a new level when space-time continuum was represented using 3D seismic data. This representation is commonly referred to as the Wheeler transformation, and it is based on flattening theories. Numerous algorithms have been introduced. Each suffers from its own problem and follow some assumption. The hydrocarbon industry, as well as academia, should seek a solution that is globally applicable to a stratigraphic succession irrespective of resolution, geologic challenges, and depositional settings. We have developed a review of the principles and norms behind these algorithms assisting in developing the space-time continuum of a stratigraphic succession using 2D/3D seismic data.
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Abdel-Fattah, Mohamed I., and Hamed A. Alrefaee. "Diacritical Seismic Signatures for Complex Geological Structures: Case Studies from Shushan Basin (Egypt) and Arkoma Basin (USA)." International Journal of Geophysics 2014 (2014): 1–11. http://dx.doi.org/10.1155/2014/876180.
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Seismic reflection techniques show an imperative role in imaging complex geological structures and are becoming more acceptable as data interpreting tools in 2D/3D view. These subsurface geological structures provide complex seismic signature due to their geometrical behavior. Consequently, it is extremely difficult to interpret these seismic sections in terms of subsurface configuration. The main goal of this paper is to introduce seismic attributes as a powerful tool to interpret complex geological structures in different geological settings. In order to image these complex geological features, multiple seismic attributes such as coherence and curvature have been applied to the seismic data generated over the Shushan Basin (Egypt) and Arkoma Basin (USA). Each type of geological structure event usually generates a unique seismic “signature” that we can recognize and identify by using these seismic attributes. In Shushan Basin (Egypt), they provide a framework and constraint during the interpretation and can help prevent mistakes during a 3D structural modeling. In Arkoma Basin (USA), the seismic attributes results provide useful information for broader analyses of the complex structural relations in the region where the Ouachita orogenic belt intersects with the southern Oklahoma aulacogen. Finally, complex geological structures provide dramatically diacritical seismic signatures that can be easily interpreted by collaborating conventional seismic interpretation techniques with multiple seismic attributes.
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Wang, Haiyang, Olivier Burtz, Partha Routh, Don Wang, Jake Violet, Rongrong Lu, and Spyros Lazaratos. "Anisotropic 3D elastic full-wavefield inversion to directly estimate elastic properties and its role in interpretation." Leading Edge 40, no. 4 (April 2021): 277–86. http://dx.doi.org/10.1190/tle40040277.1.
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Elastic properties from seismic data are important to determine subsurface hydrocarbon presence and have become increasingly important for detailed reservoir characterization that aids to derisk specific hydrocarbon prospects. Traditional techniques to extract elastic properties from seismic data typically use linear inversion of imaged products (migrated angle stacks). In this research, we attempt to get closer to Tarantola's visionary goal for full-wavefield inversion (FWI) by directly obtaining 3D elastic properties from seismic shot-gather data with limited well information. First, we present a realistic 2D synthetic example to show the need for elastic physics in a strongly elastic medium. Then, a 3D field example from deepwater West Africa is used to validate our workflow, which can be practically used in today's computing architecture. To enable reservoir characterization, we produce elastic products in a cascaded manner and run 3D elastic FWI up to 50 Hz. We demonstrate that reliable and high-resolution P-wave velocity can be retrieved in a strongly elastic setting (i.e., with a class 2 or 2P amplitude variation with offset response) in addition to higher-quality estimation of P-impedance and VP/VS ratio. These parameters can be directly used in interpretation, lithology, and fluid prediction.
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Velasco, Maria Soledad, David Alumbaugh, and Emmanuel Schnetzler. "Multiphysics data modeling and imaging for exploration in the southern Rocky Mountains." Interpretation 6, no. 3 (August 1, 2018): SG59—SG78. http://dx.doi.org/10.1190/int-2017-0215.1.
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We carried out a multidata geophysics study in southern Colorado to explore for [Formula: see text] reservoirs in an area where seismic imaging is very limited due to the mountainous terrain, the presence of high-velocity volcanic rocks, and difficulty in obtaining land access permits. We have developed a modeling/interpretation methodology using ground magnetotelluric data as well as airborne magnetic and electromagnetic data combined with public domain gravity data and existing well and seismic data. We used the integration of these data sets to produce a series of 2D and 3D geophysical models that reveal basin architecture previously poorly defined through the analysis of limited seismic and well data alone. We found that this type of analysis aids in decreasing uncertainty in the interpreted geologic cross sections and a better understanding of the structural complexities of the region. Through the application of machine learning methods, we are also able to integrate several data sets into a mathematical framework resulting in a predictive model of spatial [Formula: see text] distribution. The integration of the interpretations from all data sets, predictive analytics results, and knowledge of [Formula: see text] production, allows us to delineate areas of interest for further exploration.
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van Heteren, S., J. A. C. Meekes, M. A. J. Bakker, V. Gaffney, S. Fitch, B. R. Gearey, and B. F. Paap. "Reconstructing North Sea palaeolandscapes from 3D and high-density 2D seismic data: An overview." Netherlands Journal of Geosciences - Geologie en Mijnbouw 93, no. 1-2 (March 13, 2014): 31–42. http://dx.doi.org/10.1017/njg.2014.4.
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AbstractThe North Sea subsurface shows the marks of long-term tectonic subsidence. Much of it contains a thick record of glacial and interglacial deposits and landscapes, formed during multiple glacial cycles and the associated regressions and transgressions during the past two million years. At times of lower sea level than today, areas that are presently submerged were fertile lowlands more favourable for hunting and gathering than the surrounding upland. These drowned lowlands are not captured by traditional 1:250,000 geological maps of the North Sea subsurface because the underlying seismic and core data are commonly too widely spaced to achieve this. Palaeolandscape mapping requires identification of building blocks with spatial scales in the order of 1 km or less. As high-density 2D and high-quality 3D seismics are becoming available for an increasing part of the North Sea, glacial and interglacial palaeolandscapes can be reconstructed for more and more areas. An overview of published palaeolandscape reconstructions shows that shallow time slices through 3D data provide map views that are very suitable for the identification of landscape elements. For optimal results, each time slice needs to be validated and ground-truthed with 2D seismics and with descriptions and analyses of cores and borehole samples. Interpretations should be made by teams of geoscientists with a sufficiently broad range of expertise to recognise and classify even subtle or unfamiliar patterns and features. The resulting reconstructions will provide a context and an environmental setting for Palaeolithic, Mesolithic, and Neolithic societies and finds.
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Hart, Bruce S. "Whither seismic stratigraphy?" Interpretation 1, no. 1 (August 1, 2013): SA3—SA20. http://dx.doi.org/10.1190/int-2013-0049.1.
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Here, I provide an historical summary of seismic stratigraphy and suggest some potential avenues for future collaborative work between sedimentary geologists and geophysicists. Stratigraphic interpretations based on reflection geometry- or shape-based approaches have been used to reconstruct depositional histories and to make qualitative and (sometimes) quantitative predictions of rock physical properties since at least the mid-1970s. This is the seismic stratigraphy that is usually practiced by geology-focused interpreters. First applied to 2D seismic data, interest in seismic stratigraphy was reinvigorated by the development of seismic geomorphology on 3D volumes. This type of reflection geometry/shape-based interpretation strategy is a fairly mature science that includes seismic sequence analysis, seismic facies analysis, reflection character analysis, and seismic geomorphology. Rock property predictions based on seismic stratigraphic interpretations usually are qualitative, and reflection geometries commonly may permit more than one interpretation. Two geophysics-based approaches, practiced for nearly the same length of time as seismic stratigraphy, have yet to gain widespread adoption by geologic interpreters even though they have much potential application. The first is the use of seismic attributes for “feature detection,” i.e., helping interpreters to identify stratigraphic bodies that are not readily detected in conventional amplitude displays. The second involves rock property (lithology, porosity, etc.) predictions from various inversion methods or seismic attribute analyses. Stratigraphers can help quality check the results and learn about relationships between depositional features and lithologic properties of interest. Stratigraphers also can contribute to a better seismic analysis by helping to define the effects of “stratigraphy” (e.g., laminations, porosity, bedding) on rock properties and seismic responses. These and other seismic-related pursuits would benefit from enhanced collaboration between sedimentary geologists and geophysicists.
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Reshef, Moshe, Shahar Arad, and Evgeny Landa. "3D prediction of surface-related and interbed multiples." GEOPHYSICS 71, no. 1 (January 2006): V1—V6. http://dx.doi.org/10.1190/1.2159062.
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Multiple attenuation during data processing does not guarantee a multiple-free final section. Multiple identification plays an important role in seismic interpretation. A target-oriented method for predicting 3D multiples on stacked or migrated cubes in the time domain is presented. The method does not require detailed knowledge of the subsurface geological model or access to prestack data and is valid for both surface-related and interbed multiples. The computational procedure is based on kinematic properties of the data and uses Fermat's principle to define the multiples. Since no prestack data are required, the method can calculate 3D multiples even when only multi-2D survey data are available. The accuracy and possible use of the method are demonstrated on synthetic and real data examples.
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Kolyukhin, Dmitriy R., Vadim V. Lisitsa, Maxim I. Protasov, Dongfang Qu, Galina V. Reshetova, Jan Tveranger, Vladimir A. Tcheverda, and Dmitry M. Vishnevsky. "Seismic imaging and statistical analysis of fault facies models." Interpretation 5, no. 4 (November 30, 2017): SP71—SP82. http://dx.doi.org/10.1190/int-2016-0202.1.
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Interpretation of seismic responses from subsurface fault zones is hampered by the fact that the geologic structure and property distributions of fault zones can generally not be directly observed. This shortcoming curtails the use of seismic data for characterizing internal structure and properties of fault zones, and it has instead promoted the use of interpretation techniques that tend to simplify actual structural complexity by rendering faults as lines and planes rather than volumes of deformed rock. Facilitating the correlation of rock properties and seismic images of fault zones would enable active use of these images for interpreting fault zones, which in turn would improve our ability to assess the impact of fault zones on subsurface fluid flow. We use a combination of 3D fault zone models, based on empirical data and 2D forward seismic modeling to investigate the link between fault zone properties and seismic response. A comparison of spatial statistics from the geologic models and the seismic images was carried out to study how well seismic images render the modeled geologic features. Our results indicate the feasibility of extracting information about fault zone structure from seismic data by the methods used.
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Polomka, S. M., J. Bruins, G. A. Spanninga, and I. P. Mennie. "WA-27I-P, EXMOUTH SUB-BASIN—INTEGRATED PROSPECTIVITY EVALUATION." APPEA Journal 39, no. 1 (1999): 115. http://dx.doi.org/10.1071/aj98008.
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Permit WA-271-P in the southern Exmouth Sub-basin was initially gazetted as W96–20 in the 1996 gazettal round.It was recognised at an early stage that fluids found in Novara-1 (14° API oil), Pyrenees-1 and Macedon-1 (19° API oil and gas) made economic viability of traditional Barrow Group prospects in WA-271-P problematic and dependant upon the accurate prediction of reservoir development and fluid type.After award, Woodside embarked upon an intensive data acquisition program that included 800 km2 3D, 1,600 km 2D seismic, and 34,000 line km of aeromagnetic data. The integration of this data was completed in the latter part of 1998. The evaluation of the exploration 3D survey in the north eastern portion of the permit included volume interpretation and 3D visualisation, the results of which were integrated with an aeromagnetic and gravity study of the permit. The resultant interpretation clearly defined fault patterns and confidently identified and distinguished seismic anomalies caused by fluid effects from those generated by igneous bodies. This interpretation was supported by the application of quantitative interpretation techniques to Near, Full, Far stacks and DMO gathers with the knowledge then extrapolated to the regional 2D seismic grid beyond the 3D survey area.Environmental risk awareness and contingency planning formed an integral part of the early work within the permit. A metocean survey and spill modelling study were conducted leading to the production of a Resource Atlas. The results of the environmental studies were incorporated into the timing of exploration activities to minimise any potential impact on the environment.In summary, a focussed and multidisciplinary approach to the evaluation of the prospectivity of the permit was achieved through an integrated work flow. This has resulted in an attractive portfolio of prospects and leads from a number of play fairways, improved risk assessment, and the development of new plays within the permit, including both the traditional Barrow Group plays, and Jurassic and Triassic deep water plays. This approach has added considerable value to the permit by introducing new technologies and successfully managing risk with old play types.The first prospect drilled in the permit in December 1998, Vincent–1, was an oil and gas discovery.
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Tari, Gabor, Rudi Dellmour, Emma Rodgers, Shaista Sultan, Abdo Al Atabi, Farrukh Daud, and Adel Salman. "Seismic expression of salt tectonics in the Sab’atayn Basin, onshore Yemen." Interpretation 2, no. 4 (November 1, 2014): SM91—SM100. http://dx.doi.org/10.1190/int-2014-0043.1.
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A variety of distinct salt tectonic features are present in the Sab’atayn Basin of western Yemen. Based on the interpretation of 2D/3D seismic data and exploration wells in the central part of the basin, an Upper Jurassic evaporite unit produced numerous salt rollers, salt pillows, reactive, flip-flop, and falling diapirs. Halokinetics began as soon as the early Cretaceous, within just a few million years after the deposition of the Tithonian Sab’atayn evaporite sequence. The significant proportions of nonevaporite lithologies within the “salt” made the seismic interpretation of the salt features challenging. The evaporite sequence had been described by most as a syn-rift unit and therefore a strong correlation was assumed between the subsalt syn-rift basement architecture and the overlying diapirs and other salt-related features. However, seismic reflection and well data revealed a nonsystematic relationship between the salt diapirs and the subsalt basement highs. This observation has very important implications for the subsalt fractured basement play in the Sab’atayn Basin.
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Malinowski, Michal, Ernst Schetselaar, and Donald J. White. "3D seismic imaging of volcanogenic massive sulfide deposits in the Flin Flon mining camp, Canada: Part 2 — Forward modeling." GEOPHYSICS 77, no. 5 (September 1, 2012): WC81—WC93. http://dx.doi.org/10.1190/geo2011-0474.1.
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We applied seismic modeling for a detailed 3D geologic model of the Flin Flon mining camp (Canada) to address some imaging and interpretation issues related to a [Formula: see text] 3D survey acquired in the camp and described in a complementary paper (part 1). A 3D geologic volumetric model of the camp was created based on a compilation of geologic data constraints from drillholes, surface geologic mapping, interpretation of 2D seismic profiles, and 3D surface and grid geostatistical modeling techniques. The 3D modeling methodology was based on a hierarchical approach to account for the heterogeneous spatial distribution of geologic constraints. Elastic parameters were assigned within the model based on core sample measurements and correlation with the different lithologies. The phase-screen algorithm used for seismic modeling was validated against analytic and finite-difference solutions to ensure that it provided accurate amplitude-variation-with-offset behavior for dipping strata. Synthetic data were generated to form zero-offset (stack) volume and also a complete prestack data set using the geometry of the real 3D survey. We found that the ability to detect a clear signature of the volcanogenic massive sulfide with ore deposits is dependent on the mineralization type (pyrite versus pyrrhotite rich ore), especially when ore-host rock interaction is considered. In the presence of an increasing fraction of the host rhyolite rock within the model volume, the response from the lower impedance pyrrhotite ore is masked by that of the rhyolite. Migration tests showed that poststack migration effectively enhances noisy 3D DMO data and provides comparable results to more computationally expensive prestack time migration. Amplitude anomalies identified in the original 3D data, which were not predicted by our modeling, could represent potential exploration targets in an undeveloped part of the camp, assuming that our a priori earth model is sufficiently accurate.
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Hashimoto, Takehiko, Karen Higgins, Ron Hackney, Vaughan Stagpoole, Chris Uruski, Nadege Rollet, George Bernardel, Graham Logan, and Rupert Sutherland. "Capel and Faust basins—integrated geoscientific assessment of Australia's remote offshore eastern frontier." APPEA Journal 49, no. 2 (2009): 586. http://dx.doi.org/10.1071/aj08059.
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The paper discusses the results from the GA–302 2D seismic survey and GA–2436 (RV Tangaroa) marine reconnaissance survey over the Capel and Faust basins in the northern Tasman Sea. The integration of seismic, potential field and bathymetric data sets in 3D space at an early stage in the project workflow has assisted in the visualisation of the basin architecture, the interpolation of data between the seismic lines and the iterative refinement of interpretations. The data sets confirm the presence of multiple depocentres previously interpreted from satellite gravity data with a maximum sediment thickness of 5–7 km. Preliminary interpretation of the seismic data has identified two predominantly Cretaceous syn-rift and two Upper Cretaceous to Neogene sag megasequences overlying a heterogeneous pre-rift basement. The comparison of seismic facies and tectonostratigraphic history with offshore New Zealand and eastern Australian basins suggests the presence of possible Jurassic to Upper Cretaceous coaly and lacustrine source rocks in the pre-rift and syn-rift, and fluvio-deltaic to shallow marine reservoir rocks in the syn-rift to early post-rift successions. Preliminary 1D basin modelling suggests that the deeper depocentres of the Capel and Faust basins are within the oil and gas windows. Large potential stratigraphic and structural traps are also present.
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Wu, Xinming, and Guangfa Zhong. "Generating a relative geologic time volume by 3D graph-cut phase unwrapping method with horizon and unconformity constraints." GEOPHYSICS 77, no. 4 (July 1, 2012): O21—O34. http://dx.doi.org/10.1190/geo2011-0351.1.
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Construction of a relative geologic time (RGT) volume is vital to seismic geomorphological and sedimentological interpretation. Seismic instantaneous phase unwrapping provides an excellent approach for generating an RGT volume. Although several 2D or 3D seismic phase unwrapping results have been published, there is a clear need for discussions on concrete methods for seismic phase unwrapping. We have developed the graph-cut phase unwrapping method, which performs well in the interferometric synthetic aperture radar image processing. It has advantages of strong discontinuity-preserving ability and high computing efficiency. To make it suitable for 3D seismic phase unwrapping, the method is improved by extending it from 2D to 3D, and by introducing the seismic horizon and unconformity constraints. The strong and continuous conformable seismic events, which can be easily tracked by certain autopicking methods, are introduced as horizon constraints for guiding the phase unwrapping to ensure a constant unwrapped phase on a constraining horizon. This idea is based on the fact that continuous seismic horizons are of time-stratigraphic significance. The horizon constraints can promise a correct unwrapped result on the constraining horizons and avoid the possible phase unwrapping errors propagating across a horizon. An unconformity represents a geologic time discontinuity, which is difficult to recover in an RGT volume by phase unwrapping. What’s worse, incorrect phase unwrapping on an unconformity will result in some discontinuities of unwrapped phase in the conformable data areas outside the unconformity. Interpreted unconformities are used as unconformity constraints to recover the discontinuities of the unwrapped phase at the constraining unconformities. As a test, our improved 3D graph-cut phase unwrapping method is successfully applied to the late Permian to early Triassic carbonate reservoirs in northern Sichuan Basin, southwest China. The results match well with the regional geologic background.
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Morozov, Igor B., and Jinfeng Ma. "Accurate poststack acoustic-impedance inversion by well-log calibration." GEOPHYSICS 74, no. 5 (September 2009): R59—R67. http://dx.doi.org/10.1190/1.3170687.
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The seismic-impedance inversion problem is underconstrained inherently and does not allow the use of rigorous joint inversion. In the absence of a true inverse, a reliable solution free from subjective parameters can be obtained by defining a set of physical constraints that should be satisfied by the resulting images. A method for constructing synthetic logs is proposed that explicitly and accurately satisfies (1) the convolutional equation, (2) time-depth constraints of the seismic data, (3) a background low-frequency model from logs or seismic/geologic interpretation, and (4) spectral amplitudes and geostatistical information from spatially interpolated well logs. The resulting synthetic log sections or volumes are interpretable in standard ways. Unlike broadly used joint-inversion algorithms, the method contains no subjectively selected user parameters, utilizes the log data more completely, and assesses intermediate results. The procedure is simple and tolerant to noise, and it leads to higher-resolution images. Separating the seismic and subseismic frequency bands also simplifies data processing for acoustic-impedance (AI) inversion. For example, zero-phase deconvolution and true-amplitude processing of seismic data are not required and are included automatically in this method. The approach is applicable to 2D and 3D data sets and to multiple pre- and poststack seismic attributes. It has been tested on inversions for AI and true-amplitude reflectivity using 2D synthetic and real-data examples.
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Edwards, Rowan, Marcus Sanderson, Pedro Martinez Duran, Gregor Duval, and Mike King. "Enhancing SAR seep interpretation with broadband seismic: a case study from the Timor Trough." APPEA Journal 57, no. 2 (2017): 818. http://dx.doi.org/10.1071/aj17019.
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By combining sea surface seep data derived from synthetic aperture radar imagery and 2D seismic acquired by CGG’s Multi-client New Ventures, a seeps to seismic workflow has been developed which allows the linking of interpreted surface seeps with features on the seabed and within the subsurface related to seepage. The project combines these data sources in order to create hotspot maps which describe the quality and frequency of these seep related features, be it direct hydrocarbon indicators, possible migration pathways, fluid escape features or seabed features. By combing these maps with the surface seeps, localised points of hydrocarbon generation, migration and escape are able to be identified. 3D modelling software is utilised to link these hot spots within the seismic along strike and identify the most important and continuous structures. By identifying and understanding the geology where hydrocarbons are reaching the surface it is possible to better identify potential locations where the same hydrocarbons may instead be properly trapped. This allows the efficient identification of prospects within a basin.
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Donoso, George A., Alireza Malehmir, Bojan Brodic, Nelson Pacheco, João Carvalho, and Vitor Araujo. "Innovative seismic imaging of volcanogenic massive sulfide deposits, Neves-Corvo, Portugal — Part 2: Surface array." GEOPHYSICS 86, no. 3 (April 21, 2021): B181—B191. http://dx.doi.org/10.1190/geo2020-0336.1.
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Seismic methods are an affordable and effective way of studying the subsurface for mineral exploration. With the goal of testing new technologies for mineral exploration in highly challenging mining areas, in early 2019, an innovative seismic survey was conducted at the Neves-Corvo mine, south Portugal. We have focused on the data and results from the surface array data, whereas other work deals with the underground seismic data. The surface seismic survey consisted of two perpendicular 2D profiles positioned above the known world-class tier-1 Lombador deposit. Simultaneously, a survey inside the active underground mine took place, being unique because it included the testing of a prototype system that enabled accurate GPS-time (microsecond accuracy) synchronization inside the mine tunnels, approximately 650 m below the surface profiles. Due to the active mining operations, the surface data are noisy. To handle this, a carefully tailored processing algorithm was developed and applied to enhance reflections in the data, interpreted to originate from lithologic contacts and the Lombador deposit. The results and interpretations from 2D processing were validated taking advantage of the known deposit geometry using 3D exploding reflector modeling and pseudo-3D cross-dip analysis. These analyses suggest that there is an out-of-plane signature of the Lombador deposit on the surface data. Additionally, source points activated in the exploration tunnels and simultaneously recorded on the surface profiles allowed for the creation of a 2D velocity model that was used for migration and time-to-depth conversion, providing a reliable 2D seismic section of the subsurface under the surface profiles. We determine that limited surface coverage 2D surveys and a velocity model derived from the tunnel-to-surface seismic recordings allow for imaging of key subsurface geologic structures and delineating mineral deposits of economic interest.
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Molezzi, Marcello G., Kim A. A. Hein, and Musa S. D. Manzi. "Mesoarchaean-Palaeoproterozoic crustal-scale tectonics of the central Witwatersrand basin - Interpretation from 2D seismic data and 3D geological modelling." Tectonophysics 761 (June 2019): 65–85. http://dx.doi.org/10.1016/j.tecto.2019.04.004.
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Bugge, Aina J., Stuart R. Clark, Jan E. Lie, and Jan I. Faleide. "A case study on semiautomatic seismic interpretation of unconformities and faults in the southwestern Barents Sea." Interpretation 6, no. 2 (May 1, 2018): SD29—SD40. http://dx.doi.org/10.1190/int-2017-0152.1.
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Recently, there has been a growing interest in automatic and semiautomatic seismic interpretation, and we have developed methods for extraction of 3D unconformities and faults from seismic data as alternatives to conventional and time-consuming manual interpretation. Our methods can be used separately or together, and they are time efficient and based on easily available 2D and 3D image-processing algorithms, such as morphological operations and image region property operations. The method for extraction of unconformities defines seismic sequences, based on their stratigraphic stacking patterns and seismic amplitudes, and extracts the boundaries between these sequences. The fault-extraction method extracts connected components from a coherence-based fault-likelihood cube where interfering objects are addressed prior to the extraction. We have used industry-based data acquired in a complex geological area and implemented our methods with a case study on the Polhem Subplatform, located in the southwestern Barents Sea north of Norway. For this case study, our methods result in the extraction of two unconformities and twenty-five faults. The unconformities are assumed to be the Base Pleistocene, which separates preglacial and postglacial Cenozoic sediments, and the Base Cretaceous, which separates the severely faulted Mesozoic strata from prograding Paleocene deposits. The faults are assumed to be mainly Jurassic normal faults, and they follow the trends of the eastern and southwestern boundaries of the Polhem Subplatform; the north–south-trending Jason Fault complex; and the northwest–southeast-trending Ringvassøy-Loppa Fault complex.
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Steinmetz, D., J. Winsemann, C. Brandes, B. Siemon, A. Ullmann, H. Wiederhold, and U. Meyer. "Towards an improved geological interpretation of airborne electromagnetic data: a case study from the Cuxhaven tunnel valley and its Neogene host sediments (northwest Germany)." Netherlands Journal of Geosciences - Geologie en Mijnbouw 94, no. 2 (December 30, 2014): 201–27. http://dx.doi.org/10.1017/njg.2014.39.
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AbstractAirborne electromagnetics (AEM) is an effective technique for geophysical investigations of the shallow subsurface and has successfully been applied in various geological settings to analyse the depositional architecture of sedimentary systems for groundwater and environmental purposes. However, interpretation of AEM data is often restricted to 1D inversion results imaged on resistivity maps and vertical resistivity sections. The integration of geophysical data based on AEM surveys with geological data is often missing and this deficiency can lead to uncertainties in the interpretation process. The aim of this study is to provide an improved methodology for the interpretation of AEM data and the construction of more realistic 3D geological subsurface models. This is achieved by the development of an integrated workflow and 3D modelling approaches based on combining different geophysical and geological data sets (frequency-domain helicopter-borne electromagnetic data (HFEM), time-domain helicopter-borne electromagnetic data (HTEM), three 2D reflection seismic sections and 488 borehole logs). We used 1D inversion results gained from both HFEM and HTEM surveys and applied a 3D resistivity gridding procedure based on geostatistical analyses and interpolation techniques to create continuous 3D resistivity grids. Subsequently, geological interpretations have been performed by combining with, and validation against, borehole and reflection seismic data. To verify the modelling results and to identify uncertainties of AEM inversions and interpretation, we compared the apparent resistivity values of the constructed 3D geological subsurface models with those of AEM field measurements. Our methodology is applied to a test site near Cuxhaven, northwest Germany, where Neogene sediments are incised by a Pleistocene tunnel valley. The Neogene succession is subdivided by four unconformities and consists of fine-grained shelf to marginal marine deposits. At the end of the Miocene an incised valley was formed and filled with Pliocene delta deposits, probably indicating a palaeo-course of the River Weser or Elbe. The Middle Pleistocene (Elsterian) tunnel valley is up to 350 m deep, 0.8–2 km wide, and incised into the Neogene succession. The unconsolidated fill of the Late Miocene to Pliocene incised valley probably formed a preferred pathway for the Pleistocene meltwater flows, favouring the incision. Based on the 3D AEM resistivity model the tunnel-valley fills could be imaged in high detail. They consist of a complex sedimentary succession with alternating fine- and coarse-grained Elsterian meltwater deposits, overlain by glaciolacustrine (Lauenburg Clay Complex) and marine Holsteinian interglacial deposits. The applied approaches and results show a reliable methodology, especially for future investigations of similar geological settings. The 3D resistivity models clearly allow a distinction to be made between different lithologies and enables the detection of major bounding surfaces and architectural elements.
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Schwebel, D. "EXPLORATION REVIEW." APPEA Journal 43, no. 2 (2003): 93. http://dx.doi.org/10.1071/aj02066.
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Both exploration expenditure and drilling were significantly down in 2002 in comparison to 2001. This quiet phase is primarily due to the evaluation of the 2001 drilling and seismic results which should lead, in the long term, to the next cycle of prospect drilling and re-evaluation.The amount of onshore 2D seismic acquisition data gathered was similar to 2001 with most data acquired primarily in the producing basins.Offshore seismic acquisition was down markedly due the completion of a number of major 3D surveys. These data are now in the processing and interpretation phase and when completed will identify the next drilling candidates.The continued success story of the offshore Otway Basin has re-invigorated exploration interest in Australia’s southern margins with exploration continuing to ramp up in the Bight Basin. In the west, the further evaluation of the offshore Perth Basin indicates renewed interest as a result of the Cliff Head discovery.
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Mishra, Prashant Kumar, Sanjai Kumar Singh, and Pradip Kumar Chaudhuri. "A union of spectrum and cepstrum: Recipe for thin-bed delineation." Leading Edge 38, no. 4 (April 2019): 298–305. http://dx.doi.org/10.1190/tle38040298.1.
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The resolution limit of seismic data is an intricate issue that depends not only on frequency and data quality (signal-to-noise ratio) but also on the tools and technology used to analyze seismic response. In this context, the subject of thin-bed delineation is extremely significant for coal-laminated (causing large acoustic impedance contrasts) clastic sequences of the Western Onshore Basin, India. Most of the clastic reservoirs in the area are of subseismic resolution (below 10 m in thickness) due to the low dominant frequency available in seismic data (19–35 Hz). This is where improving seismic resolution is essential for a detailed structural and stratigraphic interpretation. We have implemented a modified workflow with which, by using state-of-the-art techniques of time-frequency decomposition and cepstral analysis, significant seismic bandwidth extension has been achieved. This in turn yields improved vertical resolution of the seismic data with better geologic interpretability. Our approach is named the “syn-cepstral method” after its two integral constituents — synchrosqueezing transform and cepstral analysis. Applying the syn-cepstral method produces better well-to-seismic ties and resolves additional events in comparison to the original seismic data. The validity of syn-cepstral methodology has been demonstrated by 1D and 2D modeling studies followed by application to a 3D seismic data set from the Western Onshore Basin of India. The improvement in thin-bed delineation arising from the increased bandwidth of the resultant data has been validated by well-to-seismic ties and amplitude map interpretation. Thus, while thin clastic reservoir beds in the logs show no discernible presence in the original seismic data, upon application of the syn-cepstral method, the resultant seismic data show improved interpretability of these units.
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Longley, Ian, and James Dirstein. "Prospectivity and play analysis in the frontier Great Australian Bight: the benefits of a public domain data system and the application of traditional and new technologies." APPEA Journal 56, no. 2 (2016): 579. http://dx.doi.org/10.1071/aj15085.
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The deep water portion of the Great Australian Bight remains an untested basin with the Gnarlyknots–1A well drilled in 2003 not penetrating deep enough to test the well's targets within the Upper Cretaceous Ceduna Delta section. If an anoxic marine shale source system, that is an effective source in many parts of West Africa, is present beneath the delta, then this could supply a material oil charge into the numerous fault block structures identified on seismic data. With eight wells due to be drilled in the next few years, this area will be one of the most active exploration frontier settings in the region. Since Australia has an open file system for technical data, the regional Flinders 2000 2D Marine seismic Interpretation report containing five regional Time structure maps is now in the public domain, as is the Gnarlyknots–1A well data and the raw seismic data from the Ceduna 3D survey acquired in 2012. These data were used to evaluate the untested Coniacian play interval with the construction of Reservoir Presence and quality, seal and charge relative probability maps made from various proxies that were then stacked to show areas of relative prospectivity. This traditional approach was supplemented by the an example showing pre-interpretation surfaces from the pre-Cenomanian portion of the 3D volume to help develop a better understanding of the potential prospectivity of deeper intervals not captured on the submitted open file maps. The workflow presented here suggests some parts of the Ceduna Sub Basin are significantly more prospective than others. Moreover, we demonstrate that even in frontier settings with minimal well data, pre-interpretation processing and simple play analysis together can be a useful and efficient approach for delivering significant insights into prospectivity. This workflow will ultimately promote more exploration thinking and activity in the future.
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Edwards, H., J. Crosby, N. David, C. Loader, and S. Westlake. "AUSTRALIAN MEGASURVEYS—THE KEY TO NEW DISCOVERIES IN MATURING AREAS?" APPEA Journal 45, no. 1 (2005): 407. http://dx.doi.org/10.1071/aj04032.
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In a maturing province such as the North West Shelf, it is time-critical to find remaining hydrocarbon resources as well as to develop small finds before existing big field installations and their associated infrastructure are decommissioned. Finding the remaining smaller fields with subtle geophysical expression is a challenge, and a thorough understanding of the petroleum geology is essential. To achieve this, the subsurface structure and depositional systems must be understood in a regional as well as a local context.To date, exploration companies’ regional models have been based on a mixture of 2D and 3D seismic of varying vintages, orientations, and quality. Consequently they have been incomplete and lacking detail. To address this problem, PGS initiated the MegaSurvey Project, merging a number of 3D surveys into large, consistent 3D data sets. For the first time, the regional picture and prospect-size detail are both available from a single dataset.Two MegaSurveys for the North West Shelf are now available; the Vulcan Sub-Basin MegaSurvey (VMS) and the Carnarvon MegaSurvey (CMS).The MegaSurvey seismic data and consistent horizon interpretation (tied to released well control) enables asset- focussed oil companies to concentrate on the more detailed search-for-the-subtle-trap to find, understand, and develop remaining reserves. Interpretation of the first MegaSurvey (Vulcan Sub-Basin) was completed in 2004 and work is focussed on the Carnarvon MegaSurvey, the interpretation of which will be completed in March 2005.The PGS 3D MegaSurveys allow visualisation of the subsurface both on a scale and resolution that has hitherto been unavailable. They provide an essential new tool to help fully unlock the remaining potential of the North West Shelf.
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Behura, Jyoti, and Ilya Tsvankin. "Estimation of interval anisotropic attenuation from reflection data." GEOPHYSICS 74, no. 6 (November 2009): A69—A74. http://dx.doi.org/10.1190/1.3191733.
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Knowledge of interval attenuation can be highly beneficial in reservoir characterization and lithology discrimination. We combine the spectral-ratio method with velocity-independent layer stripping to develop a technique for the estimation of the interval attenuation coefficient from reflection seismic data. The layer-stripping procedure is based on identifying the reflections from the top and bottom of the target layer that share the same ray segments in the overburden. The algorithm is designed for heterogeneous, arbitrarily anisotropic target layers, but the overburden is assumed to be laterally homogeneous with a horizontal symmetry plane. Although no velocity information about the overburden is needed, interpretation of the computed anisotropic attenuation coefficient involves the phase angle in the target layer. Tests on synthetic P-wave data from layered transversely isotropic and orthorhombic media confirm the high accuracy of 2D and 3D versions of the algorithm. We also demonstrate that the interval attenuation estimates are independent of the inhomogeneity angle of the incident and reflected waves.
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Boult, P. J., B.A.Camac, and A. W. Davids. "3D FAULT MODELLING AND ASSESSMENT OF TOP SEAL STRUCTURAL PERMEABILITY—PENOLA TROUGH, ONSHORE OTWAY BASIN." APPEA Journal 42, no. 1 (2002): 151. http://dx.doi.org/10.1071/aj01009.
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Many of the commercial hydrocarbon accumulations discovered to date within the Pretty Hill Formation in the onshore Otway Basin of southeastern Australia rely on a semi-brittle top seal and fault seal. Therefore a detailed and integrated fault, stress field and fracture analysis is fundamental to prospect evaluation.A syn-kinematic interpretation of the 3D seismic data set, using variance cube and visualisation technology was augmented with interpretation of the dip-meter and high-resolution borehole images. This resulted in the interpretation of a more complex fault history than previously inferred from 2D seismic mapping and dipmeter analysis alone.There are two major prospect/field bounding fault sets within the Penola Trough. Northwest-trending faults are associated with two commercial fields and several palaeo-accumulations. East-west trending faults are associated with three major fields, two uneconomic fields and two possible palaeo accumulations.Hydrocarbon leakage is probably caused by the creation of structural permeability across the regional seal. The location of leakage depends on the interaction between the seal, associated faults, and the regional stress field. Faults deflect regional stress trajectories within the top seal, creating local areas of high differential stress which enables brittle failure and the development of structural permeability. Predicting stress trajectories, the magnitude of differential stress and thus the location of structural permeability within the top seal to the underlying Pretty Hill Formation reservoirs, will reduce exploration risk uncertainty.
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Long, A., P. Zhao, P. Gatley, D. Cooke, R. van Borselen, M. Schonewille, and R. Hegge. "MULTIPLE REMOVAL SUCCESS IN THE CARNARVON BASIN WITH SRME." APPEA Journal 45, no. 1 (2005): 399. http://dx.doi.org/10.1071/aj04031.
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In 2003, Santos Ltd revisited a poor data quality area in the northern Carnarvon Basin, offshore Western Australia, where both short and long period multiple energy prohibits imaging of the underlying geology. Previous reprocessing efforts had failed to satisfactorily improve data quality, or reduce the level of multiple contamination. A two-dimensional (2D) reprocessing project was initiated to establish whether any modern variant of Surface-Related Multiple Elimination (SRME) could have success. Consequently, several versions of SRME were tested, with all output diagnostics being imaged with anisotropic Kirchhoff pre-stack time migration (PSTM). The new SRME results are a significant improvement over previous reprocessing efforts, and provide a much better platform for the picking of anisotropic velocity functions, and the application of PSTM imaging. Most of the multiple energy in this location is actually surface-related, with only a small component of internal multiple reverberations. Both long and short period multiple energy was successfully removed, and interpretation can now be pursued with more confidence in a difficult data location. Many outof- the-plane events still appear to contaminate the final 2D result, so a full three-dimensional (3D) production project was then pursued using standard (2D) SRME processing applied to 3D data gathers.Despite many noise challenges existing within the 3D field data, the final data images shed new light on a challenging geological environment, and prove the merits of SRME processing. A new generation of 3D acquisition and processing technology is now required to improve upon existing results, so a brief consideration is also given to the potential applications of 3D SRME processing to 3D seismic data from the North West Shelf. A brief example from offshore Brazil is used to illustrate the potential benefits of 3D SRME.
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Karimi, Parvaneh, Sergey Fomel, Lesli Wood, and Dallas Dunlap. "Predictive coherence." Interpretation 3, no. 4 (November 1, 2015): SAE1—SAE7. http://dx.doi.org/10.1190/int-2015-0030.1.
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Detection and interpretation of fault systems and stratigraphic features and the relationship between them are crucial for seismic interpretation and reservoir characterization. To provide better interpretation insight and to be able to extract overlooked features out of seismic data volumes, we have developed a new attribute that detects faults and other discontinuities while handling local nonstationary variations across them. First, we used predictive painting to form a structural prediction of seismic events from neighboring traces (left and right neighboring traces in 2D and neighboring traces in all directions around a reference trace in 3D) according to the local structural slopes. Then, we computed prediction residuals by subtracting each prediction from the original data, and we found the smallest prediction-error interval for each point that best represented discontinuity information at that point. The extracted fault information changed with location (spatially and temporally), and it was nonstationary. Conventional coherence measures operate on a spatial window of neighboring traces and a temporal (vertical) analysis window of samples above and below the analysis point, and they can hardly cope with nonstationarity in fault information. In contrast, in our method, neither temporal nor spatial windows were involved in coherence computation, which allowed us to honor nonstationary changes of fault information and to achieve high resolution in the vertical and lateral directions. To assess the performance of the proposed attribute, we compared it with the conventional coherence attribute over the same data set. The comparison demonstrated the effectiveness of discontinuity detection using predictive coherence and showed its value in extracting additional information from seismic data.
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Dunham, Michael W., SeyedMasoud Ansari, and Colin G. Farquharson. "Application of 3D marine controlled-source electromagnetic finite-element forward modeling to hydrocarbon exploration in the Flemish Pass Basin offshore Newfoundland, Canada." GEOPHYSICS 83, no. 2 (March 1, 2018): WB33—WB49. http://dx.doi.org/10.1190/geo2017-0451.1.
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In recent years, marine controlled-source electromagnetic (CSEM) surveying has become an effective supplemental interpretation tool to the seismic reflection method to help mitigate risk in an offshore exploration setting. Interpretation of marine CSEM data is commonly achieved via finite-difference inversions on rectilinear meshes, which has its merits, but the results are typically of very low resolution. The alternative is forward modeling, which requires a model to be known a priori, but the detail of the model can be created to reflect realistic geologic conditions. What is typically seen in the literature are applications of EM forward modeling codes to synthetic, and sometimes complex synthetic, models. However, what the literature is missing is an application that overcomes the challenges of applying a 3D forward modeling method to real models constructed from real information. We have developed an application of a 3D marine CSEM finite-element forward modeling method to the Bay du Nord prospect in the Flemish Pass Basin offshore Newfoundland. The 3D resistivity model, composed of four topographical layers and the Bay du Nord reservoir body, was built using 2D seismic data, one well log, and a marine CSEM inversion. Although other mesh representations have their merits, we chose to discretize our 3D model into an unstructured tetrahedral mesh because its flexibility enabled the accurate representation of complex structures while minimizing the number of unknowns. The availability of measured marine CSEM data allowed for the resistivities of each layer in the 3D model to be refined, and it also allowed for the simulated data to be assessed in the context of the real noise levels. A subsequent sensitivity analysis of the forward modeling results provided insights regarding the detectability of the Bay du Nord reservoir.
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Tharimela, Raghava, Adolpho Augustin, Marcelo Ketzer, Jose Cupertino, Dennis Miller, Adriano Viana, and Kim Senger. "3D controlled-source electromagnetic imaging of gas hydrates: Insights from the Pelotas Basin offshore Brazil." Interpretation 7, no. 4 (November 1, 2019): SH111—SH131. http://dx.doi.org/10.1190/int-2018-0212.1.
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Mapping of natural gas hydrate systems has been performed successfully in the past using the controlled-source electromagnetic (CSEM) method. This method relies on differentiating resistive highly saturated free gas or hydrate-bearing host sediment from a less resistive low-saturated gas or brine-bearing host sediments. Knowledge of the lateral extent and resistivity variations (and hence the saturation variations) within sediments that host hydrates is crucial to be able to accurately quantify the presence of saturated gas hydrates. A 3D CSEM survey (PUCRS14) was acquired in 2014 in the Pelotas Basin offshore Brazil, with hydrate resistivity mapping as the main objective. The survey was acquired within the context of the CONEGAS research project, which investigated the origin and distribution of gas hydrate deposits in the Pelotas Basin. We have inverted the acquired data using a proprietary 3D CSEM anisotropic inversion algorithm. Inversion was purely CSEM data driven, and we did not include any a priori information in the process. Prior to CSEM, interpretation of near-surface geophysical data including 2D seismic, sub-bottom profiler, and multibeam bathymetry data indicated possible presence of gas hydrates within features identified such as faults, chimneys, and seeps leading to pockmarks, along the bottom simulating reflector and within the gas hydrate stability zone. Upon integration of the same with CSEM-derived resistivity volume, the interpretation revealed excellent spatial correlation with many of these features. The interpretation further revealed new features with possible hydrate presence, which were previously overlooked due to a lack of a clear seismic and/or multibeam backscatter signature. In addition, features that were previously mapped as gas hydrate bearing had to be reinterpreted as residual or low-saturated gas/hydrate features, due to the lack of significant resistivity response associated with them. Furthermore, we used the inverted resistivity volume to derive the saturation volume of the subsurface using Archie’s equation.
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Smithyman, Brendan R., and Ronald M. Clowes. "Waveform tomography of field vibroseis data using an approximate 2D geometry leads to improved velocity models." GEOPHYSICS 77, no. 1 (January 2012): R33—R43. http://dx.doi.org/10.1190/geo2011-0076.1.
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Waveform tomography, a combination of traveltime tomography (or inversion) and waveform inversion, is applied to vibroseis first-arrival data to generate an interpretable model of P-wave velocity for a site in the Nechako Basin, south-central British Columbia, Canada. We use constrained 3D traveltime inversion followed by 2D full-waveform inversion to process long-offset (14.4 km) first-arrival refraction waveforms, resulting in a velocity model of significantly higher detail than a conventional refraction-statics model generated for a processing workflow. The crooked-line acquisition of the data set makes 2D full-waveform inversion difficult. Thus, a procedure that improves the tractability of waveform tomography processing of vibroseis data recorded on crooked roads is developed to generate a near-surface ([Formula: see text]) velocity model for the study area. The data waveforms are first static corrected using a time shift determined by 3D raytracing, which accounts for the crossline offsets produced by the crooked-line acquisition. The velocity model generated from waveform tomography exhibits substantial improvement when compared with a conventional refraction-statics model. It also shows improved resolution of sharp discontinuities and low-velocity regions when compared to the model from traveltime tomography alone, especially in regions where the geometry errors are moderate. Interpretation of the near-surface velocity model indicates possible subbasins in the Nechako Basin and delineates the Eocene volcanic rocks of the study area. This approach limits the ability of the full-waveform inversion to fit some propagation modes; however, the tractability of the inversion in the near-surface region is improved. This new development is especially useful in studies that do not warrant 3D seismic acquisition and processing.
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Craig, A., H. Sit, P. Sheridan, and L. MacLean. "A GEOPHYSICAL APPRAISAL OF THE EAST SPAR GAS/CONDENSATE FIELD." APPEA Journal 37, no. 1 (1997): 12. http://dx.doi.org/10.1071/aj96001.
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III order to appraise and define the East Spar gas/ condensate field the YVA-214-P joint venture has employed various geophysical techniques. The East Spar field is a Top Barrow Group four-way-dip closure in depth, but has no closure in time, requiring accurate velocity interpretation for depth conversion. Evaluation of the field has followed an approach of 2D reprocessing followed by acquisition of a 3D survey. Appraisal techniques have included inversion to acoustic impedance, amplitude versus offset studies and amplitude mapping.Initially defined from regional well control, a velocity model was constructed from multi-vintage velocity data, then later refined from the 3D velocity data. The velocity model was constructed by careful interpretation of normal moveout velocities from seismic processing. The velocity field is affected by anomalous velocities in the shallow section and a slow velocity zone over the field possibly related to gas permeation throughout the sealA probabilistic approach was adopted for depth con version and reserves estimation. Minimum, most likely and maximum case depth maps were derived by perturb ing the velocity model away from well control. Alterna tive depth conversion techniques were employed with varying success to quantify the uncertainty and accuracy of the velocity model.The reservoir sand exhibits a discrete phase change. Such gas sands are notoriously difficult to identify, interpret and map. Slight changes in the reservoir and sealing unit quality affect the phase and amplitude response of the seismic data. Normal incidence seismic models were constructed to analyse the effects of variations in reservoir, seal and sand thickness on the seismic response. These models were used to constrain several attribute based net pay maps. The reserves estimates from these attribute based maps compared favourably with the highest confidence estimates derived from depth mapping.
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Carpenter, Chris. "Machine-Learning Method Determines Salt Structures From Gravity Data." Journal of Petroleum Technology 73, no. 02 (February 1, 2021): 70–71. http://dx.doi.org/10.2118/0221-0070-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201424, “Machine-Learning Method To Determine Salt Structures From Gravity Data,” by Jie Chen, Cara Schiek-Stewart, and Ligang Lu, Shell, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, 5-7 October. The paper has not been peer reviewed. In the complete paper, the authors develop a machine-learning (ML) method to determine salt structures directly from gravity data. Based on a U-net deep neural network, the method maps the gravity downward continuation volume directly to a salt body mask volume, which is easily interpretable for an exploration geophysicist. The authors conclude that the ML-based method from gravity data complements seismic data processing and interpretation for subsurface exploration. Introduction In subsurface exploration, seismic is the dominant method used to reconstruct the underground image for geophysicists and geologists to locate possible hydrocarbon reservoirs. Seismic acquisition is carried out by human-induced sound waves (by airgun or vibrators) that are recorded, once reflected, on the surface. Through the iterative waveform inversion process, a subsurface image can be reconstructed for reservoir location and property determination. Nonseismic (gravity and magnetic-measurement) methods, on the other hand, are passive measurements and not intrusive to the environment. In gravity data acquisition, gravimeters measure the change in the gravitation-al field, which can be used to determine the density variation on the subsurface. Compared with seismic acquisition, gravity acquisition is cheaper and introduces a much smaller carbon footprint. Gravity data resolution is, in principle, worse than that of seismic. However, especially in areas of salt structures, gravity data provide a unique addition because the density contrast between salt and the surrounding sediments in-creases with depth, while the velocity contrast decreases with depth. Therefore, gravity data provide valuable additional constraints in salt delineation for interpretation and seismic processing. Recently, ML and deep-learning (DL) applications in hydrocarbon exploration have been studied extensively. The authors note developments such as use of ML/DL on seismic data noise attenuation, salt interpretation from seismic stack, least-square inversion, rock-facies classification, and 4D seismic in reservoir management. To the authors’ knowledge, no literature exists that explores use of ML on nonseismic data. The authors’ method can map the gravity downward continuation volume directly to a salt body mask (0/1 for nonsalt/salt) volume, which saves iterative effort of the conventional gravity inversion process and is easily interpretable for explorational geophysicists and geologists. Gravity Data Processing Raw gravity data are measured as a 2D Bouguer anomaly (the difference between measured gravity and theoretical gravity value) grid. The first step of gravity inversion is to perform a downward continuation calculation to generate a 3D volume so that the depth of the density anomaly can be estimated. The equivalent source technique is one of the more-stable downward continuation calculations and is a preferred method for making downward continued volumes used in in-field reference drilling.