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- Volume 22, Issue 10, 2004
First Break - Volume 22, Issue 10, 2004
Volume 22, Issue 10, 2004
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High resolution 3D seismic imaging using 3C data from large downhole seismic arrays
Authors B. Paulsson, M. Karrenbach, P. Milligan, A. Goertz and A. HardinBjörn Paulsson, Martin Karrenbach, Paul Milligan, Alex Goertz, and Alan Hardin of Paulsson Geophysical Services, with John O'Brien and Don McGuire of Anadarko Petroleum Corporation explain why recording multi-component seismic data using receivers positioned deep in the earth, and closer to the target-zone, can overcome many of the limitations experienced by surface 3D seismic methods. Borehole seismic surveys, commonly known as Vertical Seismic Profiling (VSP), have been an industry standard technique for several decades. In the past, however, these data have been used primarily for check-shot type velocity surveys and for reflection mapping at the well location in a one-dimensional fashion. This 1D measurement can be extended to 2D by using one or more walk-away lines of surface source points. The 2D method works well enough for imaging simple layered stratigraphy, but in a complex reservoir a full 3D data acquisition and imaging solution needs to be pursued. Inserting seismic sensors deep into oil and gas wells, as shown in Figure 1, allows the recording of much higher frequencies as compared to placing sensors at the Earth’s surface. The reason for this is simple: seismic waves have to propagate only once through the weathered layer in a confined zone near the source. In contrast, during surface seismic surveys, waves must travel through the weathered layer twice. Each traversal of the weathered layer attenuates high frequencies much more than the low frequencies, thus reducing the image resolution. The frequency content of borehole seismic data is typically more than twice that of surface seismic data, which provides an increase in subsurface resolution. In addition to recording higher frequency data, borehole seismic sensors provide a number of other advantages: borehole seismic data typically achieve a much higher signal-tonoise ratio than surface seismic data. The combination of a quiet borehole environment and strong sensor coupling to the borehole wall enables such high signal-to-noise ratio. Surface geophones, on the other hand, are generally poorly coupled in weathered rock and exposed to cultural and environmental noise at the surface. Good sensor coupling in the borehole enables three-component (3C) seismic data to be recorded with high vector fidelity. This ultimately allows shear and converted-wave imaging as well as the determination of anisotropy by shear wave splitting analysis (see, e.g., Maultzsch, 2003). Combining P and S wave images allows for attribute inversions of rock properties, such as fluid content, pore pressure, stress direction and fracture patterns. O’Brien et al. (2004b) use time lapse borehole seismic to map changes in such critical attributes for production monitoring purposes. Another advantage of borehole seismic surveys is a favourable geometry to illuminate complex structures such as sub-salt targets, salt flanks or steeply dipping faults. The 3D image volume that can be generated from a large downhole seismic array data is shown in Figure 1. The typical 3D borehole seismic image volume is cone shaped with the top of the cone coincident with the top receiver in the borehole array. The size of the base of the cone is determined by the depth of the image volume and the offset of the sources.
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Quantitative analysis on the first Q-on-Q 4D programme
Authors J. Khazanehdari, R. Goto, T. Curtis, H. Özdemir, A. Murineddu, J.M. Gehenn and T. YiJ. Khazanehdari, R. Goto, T. Curtis, H. Ozdemir, A. Murineddu, J.M. Gehenn and T. Yi describe how the first repeat survey using WesternGeco's Q-Marine technology for both the baseline and monitor surveys of a 4D seismic project over Statoil's Norne field has been used successfully to quantify changes in the reservoir's saturation and pressure.
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Passive seismic makes sense for 4D reservoir monitoring
More LessStephen Wilson, Rob Jones, Will Wason, Daniel Raymer and Paul Jaques of Vetco Gray, Cornwall, UK (formerly part of ABB) describe how passive seismic monitoring technology is making its way into the mainstream as a value proposition for the management of hydrocarbon resources. The use of 4D seismic as a mainstream technology in the management of hydrocarbon reservoirs is now established. In contrast to the traditional perception of seismic technology as an exploration tool, the value of 4D seismic sits securely on the production side of oilfield technology. This shift in emphasis within the seismic industry to encompass both production and exploration work has recently taken on a higher profile as a result of the difficulty of increasing reserves purely by exploration. New production technology now offers an alternative path to increasing booked reserves. The widening scope of seismic applications and the increasing number of reservoir geophysicists is helping to bring forward another seismic technology capable of greatly improving our understanding of reservoir dynamics. That technology is passive seismic monitoring. During the past few years the implementation of passive seismic monitoring as a mainstream technology for the management of hydrocarbon resources has been gathering pace. Recent permanent passive seismic studies in Oman have shown the capabilities of this technology to provide information upon which reservoir management decisions can be made (Jones et al, 2004). Knowledge of the existence and capabilities of the technology within our industry is reaching a critical mass and the technological barriers to its uptake are disappearing. Perhaps the most critical of these barriers concerns the ability to monitor microseismic activity from within active wells during production or injection. Recent developments in downhole tool technology allow the deployment of downhole seismic sensors capable of a 30-40 db improvement in signal performance when compared with previous technologies (Jaques et al., 2003). In addition to improvements in tool technology, software applications capable of delivering automatic microseismic locations to the client’s desktop in real-time are now available (Jones and Wason, 2004). The advent of 4D has improved our ability to observe reservoir performance and make timely decisions about reservoir operations. The deployment of permanent ocean bottom systems provides scope for improving the speed with which reservoir management decisions can be made by reducing turnaround time. Passive seismic monitoring further supports this improved decision-making capability by delivering real-time information about the reservoir to the desktop within minutes. In terms of instrumentation, permanent downhole seismic sensors represent the cornerstone for the implementation of full-field continuous passive seismic monitoring. The prospect of permanent downhole seismic sensors for use during 4D studies offers the prospect of accurate well ties, wavelet characterisation and VSP on demand. The combined value proposition for passive seismic monitoring and 4D seismic using downhole instrumentation may now be sufficient to drive the deployment of these systems. Figure 1 illustrates this virtuous circle of 4D seismic promoting the take up of microseismic technology which in turn helps 4D to better resolve reservoir change. All of which is driven by the value proposition of new technology as a method of improving recovery, increasing NPV and booking reserves.
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Designing an optimal 4D streamer survey pays reservoir dividends
Authors K. Watt and G. PattisonIn this case study of a 4D survey offshore Norway, Keith Watt and Gavin Pattison of I/O company Concept Systems provide a case study of how planning and design of a 4D seismic survey ultimately rewards reservoir management. 4D started life as a research technology in the geophysicists’ domain, but the real beneficiaries of the final outcome are reservoir geoscientists. Over the last few years the reservoir engineering community has begun to understand the benefits of 4D and how the technology can be applied to optimise reservoir management programmes. Conferences such as the joint SPE/EAGE conference ‘What Do Petroleum Engineers Expect from Time Lapse Seismic, and Do Geophysicists Answer the Right Questions?’ in March this year helped to bring the two communities together to build a common understanding of the technologies. A key issue in 4D surveys is to ensure that the data is of sufficient quality to provide reliable imaging of changes in reservoir behaviour during production. For marine acquisition of 4D seismic using towed streamers, this poses a major positional challenge which Concept Systems has been addressing for several years now. The company has been involved in over 40 surveys, enough to identify that major sources of error arise from the towing of long cables and the differences in source/receiver positions between monitor and baselines surveys. To minimise these positional differences, the first priority is to measure them. In 2001 Concept began a research project in partnership with Shell Expro to develop software to measure the positional errors in 4D surveys and correlate them with the processed seismic data. The resulting ‘repeatability’ technology was used successfully in Shell’s 2002 North Sea 4D programme to QC/optimise the acquisition and to make 4D infill choices. One lesson from this early work was the significant benefit arising from anticipating the positional issues at an early stage of the process, in other words in the planning stages. The ability to measure 4D repeatability during the design/ planning phase of a 4D project, and to analyse multiple scenarios to decide on the best compromise between repeatability and acquisition costs, can significantly improve the quality of a 4D dataset. We focus here on the application of the technology and knowledge applied in the design and planning phase of a 4D project.
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Identifying vertical productive fractures in the Narraway gas field using the envelope of the anisotropic gradient
Authors G. Larson, D. Gray, S. Cheadle, G. Soule and Y. ZhengIn this Canadian case study Dragana Todorovic-Marinic, Glenn Larson, David Gray, Scott Cheadle, Greg Soule and Ye Zheng report on their progress with a new seismic attribute in identifying productive vertically aligned fractures, cracks or micro-cracks in gas reservoirs using surface seismic data. Fractures are of great interest for hydrocarbon production. They can either hurt or help production depending on the nature of the reservoir being explored, so knowledge of their distribution and orientation can be critical to exploration success. Vertically aligned fractures, cracks or micro-cracks are known causes of Horizontal Transverse Isotropy (HTI). This type of anisotropy often has a horizontal axis aligned with open vertical fracturing that trends parallel to the maximum horizontal stress and normal to the minimum horizontal stress. It is widely recognised (e.g. Hall et al, 2000; Gray et al, 2002) that HTI anisotropy has a strong effect on the seismic amplitude. This can be measured by fitting the parameters of the Pwave Amplitude Versus Angle and Azimuth (AVAZ) equation of Rüger (1996) to surface seismic data. The outputs are seismic attributes that contain information that may be relevant to the fracturing. The P-wave reflectivity is the response of the rock to compression by the seismic wave and provides information on the rock’s lithology and fluid content. The Swave reflectivity is the response of the rock to shearing by the seismic wave and is comprised primarily of information about the lithology. The anisotropic gradient describes the variations of the AVO gradient with azimuth and is related to the crack density, i.e. to the magnitude of the differential horizontal permeability (Lynn et al, 1996). The azimuth of the anisotropic gradient is the orientation of the symmetry axis of an HTI medium. To the extent that a reservoir with vertical open fractures represents an HTI medium, the azimuth of the anisotropic gradient indicates the orientation of the fractures.
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Well log and seismic data analysis using rock physics templates
Authors P. A. Avseth and E. OdegaardRock physics is an integral part of quantitative seismic data analysis and is fundamental for fluid- and lithology-substitution, for AVO modelling, and for interpretation of elastic inversion results.
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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)