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- Volume 25, Issue 5, 2007
First Break - Volume 25, Issue 5, 2007
Volume 25, Issue 5, 2007
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Higher costs and need for exploration highlighted in oil and gas industry report
Authors J.S. Herold and H. LovegroveGlobal Upstream Performance Review 2006 is the latest annual report on 200 oil and gas companies tracked by corporate oil analysts and advisors John S. Herold (US) and Harrison Lovegrove (UK). It constitutes one of the best regular assessments of the oil and gas industry’s performance and the challenges it faces. We publish here extracts from the abridged version of the report. Tight markets and escalating prices fuelled a 32% jump in the average price per barrel oil equivalent (boe) realized by the Global Upstream Performance Review universe of over 200 oil companies in 2005; the sector enjoyed a revenue gain of $190 billion over the prior year. Clearly, it is a challenge for the industry to invest such a surge of funds, particularly given the restrictions on access to basins with large resource potential. For context, the entire industry’s finding and development investment during 2004 was $164 billion.
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Unravelling a carbonate system: technical advances in seismic sequence stratigraphy
Authors G. de Bruin, K. McBeath and N. HemstraGeert de Bruin,* Kirstin McBeath, and Nanne Hemstra show how recently introduced software could be the key to greater use of seismic sequence stratigraphy. In essence, sequence stratigraphy is used to provide a chronostratigraphic framework for correlation and mapping and for stratigraphic prediction (Emery and Myers, 1996). Although, sequence stratigraphy has proven to be a powerful instrument, and despite major advances in concepts since its introduction in the 1970s, sequence stratigraphy has not lived up to its potential because of the lack of supporting software tools. Recently a new software system, OpendTect SSIS, came to the market with the aim of filling this gap. The basic concept of OpendTect SSIS is that all stratigraphic events (horizons) are auto detected by the system and placed into stratigraphic order (Ligtenberg et al., 2006; de Bruin et al., 2006; and de Groot et al., 2006a, 2006b). These chronostratigraphic surfaces are generated at sub-seismic resolution and tracked throughout the seismic volume within the limits of conventionally mapped bounding surfaces. They are assigned relative geological time indices, or ‘geotimes’.
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Fast-track reservoir characterization of a subtle Paleocene deep-marine turbidite field using a rock physics and seismic modelling-led workflow
Authors H. Morris, R. Christensen, D. Gawith and M. Millwood HargraveHenry Morris,* Rod Christensen, David Gawith, and Martyn Millwood Hargrave present a novel approach, based on forward modelling, AVO, and inversion-of-inversion techniques, to identify/track interlocking Palaeocene sand and shale-filled channels in an appraised subtle Palaeocene deep-marine turbidite, Central North Sea. Seismic attributes relate to physical phenomena, and can be modelled by theoretical rock physics methods. By calculating and quantifying lithological and fluid-fill variability, it is possible to take the well-based model forward into the seismic world of AVA (Amplitude Variation with Angle) and inversion. By using rock physics to bridge the gap between petrophysics and seismic, we can use a supervised neural network technique to quantitatively predict reservoir properties (such as porosity, shale volume, and saturation) away from the well. Without the use of rock physics, seismic is incapable of measuring any of these parameters directly. Improvements being made in processing to enhance the signal-to-noise ratio will improve our confidence that subtle changes observed in the seismic signal reflect changes in the subsurface environment.
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Maintaining the momentum in seismic safety management
By A. McBarnetAndrew McBarnet looks at some of the perennial challenges in safety management for geophysical survey operations in a global market. Safety is an extraordinarily sensitive issue in any industry, but probably especially so in land and marine seismic survey operations. Oil companies and their contractors are, after all, under intense pressure to ensure the safety of project personnel on a 24/7 basis while they are engaged in inherently dangerous activities. If something does go wrong, the emotional turmoil of an accident especially one involving loss of life is always extremely hard to deal with, and there can be unpredictable consequences. Companies and their managements can be vulnerable to hefty legal and financial penalties. An example of the impact on a company of a large scale accident was illustrated by the explosion at BP’s Texas City refinery in the US two years ago killing 15 workers. The company suffered a major blow to its credibility, has been fined, no doubt faces endless civil damages litigation, and the incident is widely held to have speeded the intended retirement date of its chairman Lord Browne, frequently cited as the outstanding CEO of his generation.
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Crosswell imaging provides detail for optimizing reservoir development
By M. McCallumMark McCallum, Z-Seis Corporation, Calgary, Canada provides some case studies to highlight the benefits of crosswell seismic in making exploration and development decisions. New challenges are being faced by oil and gas producers as conventional hydrocarbon resources continue to dwindle. The focus in the industry is shifting from developing new conventional reserves to maximizing the potential of existing reserves. Exploration is now shifting to either unconventional reserves such as oil sands, tight gas, and coal bed methane or remote locations such as the arctic and deep water offshore. In both cases, development of new resources and redevelopment of mature fields, crosswell seismic can deliver unprecedented resolution to solve reservoir issues in the interwell space. At critical junctures in the life of a reservoir, development decisions are made that can dramatically increase value, if they are based on a precise understanding of reservoir architecture. During the last decade, 3D surface seismic has supplied information about the reservoir that has driven exploration and development decisions. However, today crosswell seismic technology is emerging as an effective new tool in characterizing the unconventional resource reservoir and in optimizing the development of mature fields.
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Application of the FBTD converted-wave static method in a sand dune area
More LessIn a sand dune area, the LVL (low velocity layer) mainly comprises two layers: loose dry sand and water-saturated sand. These two layers are totally different in P- and S-wave velocities. When a 3C survey is conducted, a serious static problem arises. This means that 3C data processing has to put the emphasis on S-wave statics estimation. In the Sulige gas field of the Erdos basin, China, 2D/3C and 3D/3C seismic surveys were conducted successfully by BGP from 2002 to 2004. The main purpose of the surveys was to improve the sand channel interpretation and gas reservoir characterization in terms of converted-waves. Furthermore, BGP wanted to know if the PS data can be used for lithology prediction in order to discriminate between the gas sand and overbank shale, and if 3D/3C can be used for reservoir monitoring during gas production in the long run.
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Articles from the archive: Common-offset migrations and velocity analysis
More LessPrestack depth migration is very sensitive to velocity errors. This can make it an excellent tool for velocity analysis. However, to get maximum benefit from this Sensitivity to velocity we must choose our algorithm carefully. Most of the sensitivity to velocity arises from the normal moveout (NMO) term, i.e. from the alignment corrections to data recorded at different offsets. It therefore makes sense, in the context of velocity analysis, to design the prestack migration so that the overall procedure does not apply NMO according to a preconceived velocity model. Instead, the NMO should be calculated after migration in the standard way by fitting hyperbolas to common-midpoint gathers. Unfortunately, the strict application of such a design criterion eliminates most of the standard migration techniques, such as datuming, downward continuation and reverse time migration. It also eliminates shot record imaging by integral methods. I do not mean to imply that such imaging methods cannot be used for velocity estimation, but simply that the initial velocity model has to be significantly more accurate than that required if the migration technique does not mix data recorded at different offsets. For example, shot-record dip moveout (DMO) requires a significantly more accurate initial velocity estimate than common-offset DMO.
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Volumes & issues
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Volume 43 (2025)
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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)
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