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- Volume 33, Issue 9, 2015
First Break - Volume 33, Issue 9, 2015
Volume 33, Issue 9, 2015
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Spectrum beefs up its data library to expand globally and ride out the tough market
Rune Eng, Spectrum president and CEO, explains the thinking behind Spectrum’s recent acquisition of Fugro’s multi-client library for $115 million.
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Prospectivity evaluation with 3D CSEM
Authors Daniel Baltar and Neville D. BarkerEvaluation of the prospectivity potential of hydrocarbon exploration ventures is a process of integration. Information provided by different technologies needs to be integrated into a single evaluation. This paper details a method for embedding the additional information provided by 3D Controlled Source Electromagnetic (CSEM) surveys into existing (or independently generated) prospect evaluations. Workflows are designed to leverage the primary value of the CSEM information in exploration (sensitivity to hydrocarbon volume), while minimizing the disruption and potential increase in risk associated with the adoption of a new technology. This is achieved through a focus on maintaining the independence of information sources and visibility of measurement uncertainties, along with adoption of standard performance-tracking methodologies. Previously-described workflows for embedding CSEM information in a prospect evaluation process (e.g., Buland et al., 2011; Baltar and Roth, 2013) focus either on updates to the Probability of Success (PoS), or volume assessment. In contrast, we show that the nature of the information provided by CSEM is more suited to a coupled reassessment of both risk and volumes. This generates a more robust update not prone to the shortcomings associated with existing stand-alone approaches. Workflows are illustrated with the use of realistic synthetic examples; a published prediction using the methodology is also reviewed in light of recent drilling results. When applied systematically across a CSEM-sensitive portfolio, the new information provided by 3D CSEM has the effect of polarising existing evaluations, making CSEM a valuable tool in exploration venture evaluation.
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Setting new standards for regional understanding – mega-scale broadband PSDM in the North Sea
Authors Steve Hollingworth, Owen Pape, Chris Purcell, Ewa Kaszycka, Trevor Baker, John Cowley, Gregor Duval and Luke TwiggerRecovering the remaining and bypassed hydrocarbons in mature areas requires well-informed decision-making supported by good data. A great deal of seismic exploration has taken place within the North Sea, using a variety of acquisition configurations including the latest broadband solutions. Most surveys in this mature area have been processed and reprocessed multiple times as techniques have evolved and, every so often, significant advances in technology warrant the application of these new approaches in a wholesale way. The Central North Sea (CNS) still contains many oppor¬tunities and is notoriously challenging to image with seismic. Fuelled by the need for greater accuracy of deep imaging and structural interpretation, for both prospect discovery and field development, there has been a steady increase in the number of pre-stack depth migration (PSDM) projects. The majority of these projects have focused on small areas, primarily restricted by the high work effort involved in integrating all available data (wells, horizons, vertical seismic profiles, etc.) into the velocity model, combined with the lengthy timescales required to update the model using traditional, interpretation-heavy workflows and tomography methods. Recent advances in multi-layer tomography (Guillaume et al., 2012) now allow us to complete complex PSDM projects within a significantly reduced timescale while at the same time achieving improved image quality. In addition, advances in deghosting and demultiple processing technolo¬gies have enabled us to extract even more value from vintage conventional flat-towed streamer datasets. We describe how these technologies have been applied to integrate 37 acquisi¬tion phases covering more than 35,000 km2 in the CNS to generate a unique and contiguous high-quality broadband PSDM dataset which sets new standards for regional datasets in mature basins.
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Depth domain inversion to improve the fidelity of subsalt imaging: a Gulf of Mexico case study
Authors Laurence Letki, Jun Tang, Charles Inyang, Xiang Du and Robin FletcherAccurate geophysical reservoir characterisation in complex geologic environments remains a challenge. In particular, conventional methods of amplitude inversion assume that amplitudes in the seismic image are correctly located and can be inverted to elastic parameters from which a true representation of rock proper¬ties can be derived. However, complex geology, often com¬bined with limitations imposed by surface seismic acquisition geometries, can lead to inadequate illumination of subsurface targets, which can have detrimental effects on the amplitudes and phase of the migrated image. Conventional amplitude inversion techniques do not compensate for these amplitude and phase variations. Consequently, imprints of various non-geological effects and a complex overburden will manifest themselves in the results of seismic inversion, leading to less reliable estimation of acoustic and elastic parameters. An additional challenge to accurate amplitude inversion in complex geologic environments is that depth imaging is normally required to obtain a reliable image of the subsurface, while current amplitude inversion techniques are usually implemented in the time domain. This difference in approach between the imaging and inversion steps can compromise the fidelity of the attributes derived from seismic inversion. In order to improve consistency between structural imag¬ing and rock property estimation, a technique has been developed to perform amplitude inversion directly in the depth domain. The inversion workflow uses point spread functions to capture and correct for space-, depth- and dip-dependent illumination effects resulting from the acquisition geometry and complex geology. The amplitude inversion is performed in the depth domain and the output is a reflectivity image and associated acoustic impedance volume corrected for illumina¬tion effects, thus creating more consistent and reliable imaging products and rock property attributes from depth-migrated datasets. This article presents the application of the depth domain inversion workflow to a long-offset full-azimuth (FAZ) dataset from the Green Canyon area of the Gulf of Mexico (GoM) (Letki et al., 2015).
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Application of waveform tomography at the Campos Basin field
Authors Mauricio Pedrassi, Jyoti Behura, Thomas L. Davis, Esteban Diaz and Satyan SinghCampos Basin field has been continuously character¬ised at the Reservoir Characterization Project (RCP) in Colorado School of Mines. Past research includes poststack and prestack joint inversions of PP and PS data which increased the reservoir resolution and could predict a porosity map. To further improve characterisation of the Campos Basin field, waveform tomography (WT), or full waveform inversion (FWI), is performed for a 2D line from the 2010 ocean bottom cable (OBC) data under a 2D acoustic isotropic medium assumption. The goal is to bring high resolution and accuracy to the P wave veloc¬ity model for better-quality reservoir imaging. In order to achieve the best results the application of WT to the 2D dataset required defining the suitable parameters to these data, where the main options in the inversion are the type of objective function, the time domain damping, and the fre¬quency discretisation. Waveform inversion has improved the final velocity model, as verified by migrated images showing more continuous and focused horizons at the reservoir depth. The improved seismic image and velocity model are possible inputs, respectively, to a new geological interpretation and to acoustic/elastic attributes inversion. Waveform tomography (WT), or Full Waveform Inversion (FWI), has been the subject of studies and conceptual devel-opment over the past 30 years (Virieux and Operto, 2009). Furthermore, research groups and the oil industry around the world have shown the improvement that WT can bring to the velocity model, especially in terms of high resolution in comparison with conventional techniques, such as traveltime tomography (TT) or migration velocity analysis (MVA). These techniques can only build a smoothed version of the velocity model, containing the kinematics of the wavefield, even though they are able to generate a good quality seismic image. WT represents a more advanced approach that attempts to completely describe the complex interaction of the propagating waves and the earth, in which the phase of the whole waveform is used in the model reconstruction (Pratt, 2013).
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TrueDepth prestack depth migration: an essential tool for mitigating drilling risk
Authors Jaime A. Stein, Kevin Hellman, Tom Charlton, Tim Shepard, Dale Baptiste and Scott BoyerThe utilisation of non-seismic data in the structural imaging arena has been shifting its importance from an afterthought to an essentially a priori ingredient. The necessity to image complex subsurface structures that are at the right depth, at the correct geographical loca¬tion and with the correct geometry and topology has become paramount for a successful business model that combines drilling, geosteering, completion, fracking and re-fracking, as well as production and EOR efforts. This article can be thought of as an update and continu¬ation on our 2013 First Break publication (Stein et al., 2013) that introduced the concept of TrueDepth. Here we will describe the new developments in the technology suite, primarily spawned by our experiences processing many surveys around the world that pointed to some shortcomings in the original ideas and implementation. Particularly important has been the development of a new workflow that increases the efficiency and robustness of the techniques. The new workflow incorporates several new pieces of technology making the resulting images more accu¬rate. The new technologies include a global delta anisotropy tool, a tomography capable of inverting for velocity and anisotropy, and 3D QC visualisation techniques. We will finish the article by demonstrating the value of the new workflow and technologies by applying them to a real case history. It has become increasingly obvious that an accurate depth prediction, as well as a very detailed description of the geomet¬ric and topological nature of the reservoirs, is paramount for a cost-effective exploration and production effort. It has always been accepted that the incorporation of non-seismic data into the imaging effort is essential to the outcome. The shift in this mindset that has occurred in the last few years is that such data is not only valuable as a calibration or QC tool, but that it can, and we would argue it must, be part of the input data and combined with the seismic in our algorithms to produce exceptionally accurate results. This philosophy is at the core of the TrueDepth methodology; the use of a priori information in the imaging process. For a detailed description of the geophysical and math¬ematical basis of TrueDepth as well as some earlier examples, we will refer the reader to our earlier publications (Stein et al., 2013; Stein, 2014; Hellman et al., 2015; Baptiste et al., 2015).
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A comprehensive seismic characterisation via multi-component analysis of active and passive data
Authors G. Dal Moro, L. Keller and V. PoggiA comprehensive seismic survey was conducted with the aim of characterising one of the Swiss Digital Seismic Network stations in northern Switzerland. Both active (P- and S-wave refraction tomography, surface-wave analysis, vertical seismic profiling) and passive methodologies (wavelet decomposition, Horizontal-to-Vertical Spectral Ratio, three-component frequency-wavenumber analysis) were jointly considered in order to solve the intrinsic non-uniqueness of the solution and determine a consistent subsurface model free from ambiguities, eventually used for the assessment of the local site amplification.
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Volumes & issues
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Volume 42 (2024)
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Volume 41 (2023)
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Volume 40 (2022)
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Volume 39 (2021)
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Volume 38 (2020)
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Volume 37 (2019)
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Volume 36 (2018)
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Volume 35 (2017)
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Volume 34 (2016)
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Volume 33 (2015)
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Volume 32 (2014)
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Volume 31 (2013)
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Volume 30 (2012)
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Volume 29 (2011)
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Volume 28 (2010)
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Volume 27 (2009)
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Volume 26 (2008)
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Volume 25 (2007)
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Volume 24 (2006)
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Volume 23 (2005)
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Volume 22 (2004)
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Volume 21 (2003)
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Volume 20 (2002)
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Volume 19 (2001)
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Volume 18 (2000)
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Volume 17 (1999)
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Volume 16 (1998)
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Volume 15 (1997)
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Volume 14 (1996)
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Volume 13 (1995)
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Volume 12 (1994)
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Volume 11 (1993)
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Volume 10 (1992)
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Volume 9 (1991)
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Volume 8 (1990)
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Volume 7 (1989)
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Volume 6 (1988)
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Volume 5 (1987)
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Volume 4 (1986)
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Volume 3 (1985)
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Volume 2 (1984)
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Volume 1 (1983)